Edgar Filing: HERCULES OFFSHORE, INC.

Inputs are quoted prices in active markets for identical assets or liabilities.

Inputs are quoted prices for similar assets or liabilities in an active market, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable and market-corroborated inputs which are derived principally from or corroborated by observable market data.

e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended June 30, 2009


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

Commission file number: 0-51582

HERCULES OFFSHORE, INC.

(Exact name of registrant as specified in its charter)


Delaware				56-2542838
(State or other jurisdiction of				(I.R.S. Employer
incorporation or organization)				Identification No.)


9 Greenway Plaza, Suite 2200
Houston, Texas				77046
(Address of principal executive offices)				(Zip Code)

(713) 350-5100
(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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES o NO o

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


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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange 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 practicable date.


Common Stock, par value $0.01 per share		Outstanding as of July 21, 2009
		95,825,615

HERCULES OFFSHORE, INC.

INDEX


	Page No.
PART I. FINANCIAL INFORMATION

Item 1. Financial Statements:
Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008		3
Consolidated Statements of Operations for the three and six months ended June 30, 2009, and June 30, 2008		4
Consolidated Statements of Cash Flows for the six months ended June 30, 2009 and June 30, 2008		5
Consolidated Statements of Comprehensive Income (Loss) for the three and six months ended June 30, 2009, and June 30, 2008		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		40
Item 4. Controls and Procedures		42

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		42
Item 1A. Risk Factors		42
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		53
Item 4. Submission of Matters to a Vote of Security Holders		54
Item 6. Exhibits		54

Signatures		55
EX-4.1
EX-31.1
EX-31.2
EX-32.1

PART I. FINANCIAL INFORMATION


ITEM 1.		FINANCIAL STATEMENTS

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except par value)

(Unaudited)


	June 30,			December 31,
	2009			2008
				(As Adjusted)
ASSETS
Current Assets:
Cash and Cash Equivalents	$	129,880		$	106,455
Accounts Receivable, Net		227,808			293,089
Prepaids		34,492			23,033
Current Deferred Tax Asset		16,527			17,379
Assets Held for Sale		11,390			39,623
Other		20,807			19,946

		440,904			499,525
Property and Equipment, Net		2,020,766			2,049,030
Other Assets, Net		50,638			42,340

	$	2,512,308		$	2,590,895

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term Debt and Current Portion of Long-term Debt	$	9,000		$	11,455
Insurance Note Payable		19,330			11,126
Accounts Payable		68,745			99,823
Accrued Liabilities		71,224			83,424
Taxes Payable		34,337			32,440
Other Current Liabilities		53,120			36,472

		255,756			274,740
Long-term Debt, Net of Current Portion		960,222			1,015,764
Other Liabilities		29,036			35,529
Deferred Income Taxes		315,138			339,547
Commitments and Contingencies
Stockholders’ Equity:
Common Stock, $0.01 Par Value; 200,000 Shares Authorized; 97,314 and 89,459 Shares Issued, Respectively; 95,815 and 87,976 Shares Outstanding, Respectively		973			895
Capital in Excess of Par Value		1,827,663			1,785,462
Treasury Stock, at Cost, 1,499 Shares and 1,483 Shares, Respectively		(50,128	)		(50,081	)
Accumulated Other Comprehensive Loss		(13,350	)		(14,932	)
Retained Deficit		(813,002	)		(796,029	)

		952,156			925,315

	$	2,512,308		$	2,590,895

The accompanying notes are an integral part of these financial statements.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
				(As Adjusted)						(As Adjusted)
Revenues	$	183,691		$	270,106		$	407,182		$	482,600
Costs and Expenses:
Operating Expenses		116,097			158,014			265,341			289,160
Impairment of Property and Equipment		26,882			—			26,882			—
Depreciation and Amortization		51,091			47,274			99,937			90,894
General and Administrative		15,450			23,966			31,742			40,330

		209,520			229,254			423,902			420,384

Operating Income (Loss)		(25,829	)		40,852			(16,720	)		62,216
Other Income (Expense):
Interest Expense		(14,561	)		(15,222	)		(30,350	)		(31,178	)
Gain on Early Retirement of Debt, Net		13,747			—			13,747			—
Other, Net		3,346			250			2,690			2,275

Income (Loss) Before Income Taxes		(23,297	)		25,880			(30,633	)		33,313
Income Tax Benefit (Provision)		11,510			(9,492	)		14,335			(12,050	)

Income (Loss) from Continuing Operations		(11,787	)		16,388			(16,298	)		21,263
Loss from Discontinued Operation, Net of Taxes		(242	)		(209	)		(675	)		(598	)

Net Income (Loss)	$	(12,029	)	$	16,179		$	(16,973	)	$	20,665

Basic Earnings (Loss) Per Share:
Income (Loss) from Continuing Operations	$	(0.13	)	$	0.18		$	(0.18	)	$	0.24
Loss from Discontinued Operation		(0.01	)		—			(0.01	)		(0.01	)

Net Income (Loss)	$	(0.14	)	$	0.18		$	(0.19	)	$	0.23

Diluted Earnings (Loss) Per Share:
Income (Loss) from Continuing Operations	$	(0.13	)	$	0.18		$	(0.18	)	$	0.24
Loss from Discontinued Operation		(0.01	)		—			(0.01	)		(0.01	)

Net Income (Loss)	$	(0.14	)	$	0.18		$	(0.19	)	$	0.23

Weighted Average Shares Outstanding:
Basic		88,733			88,625			88,368			88,742
Diluted		88,733			89,461			88,368			89,516

The accompanying notes are an integral part of these financial statements.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Six Months Ended June 30,
	2009			2008
				(As Adjusted)
Cash Flows from Operating Activities:
Net Income (Loss)	$	(16,973	)	$	20,665
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:
Depreciation and Amortization		99,937			90,906
Stock-Based Compensation Expense		4,115			7,932
Deferred Income Taxes		(25,063	)		5,864
Provision for Doubtful Accounts Receivable		543			181
Amortization of Deferred Financing Fees		2,096			1,712
Amortization of Original Issue Discount		2,386			643
Gain on Insurance Settlement		(8,700	)		—
Gain on Disposal of Assets		(332	)		(1,911	)
Gain on Early Retirement of Debt, Net		(13,747	)		—
Impairment of Property and Equipment		26,882			—
Excess Tax Benefit from Stock-Based Arrangements		(4,209	)		(5,447	)
(Increase) Decrease in Operating Assets -
Accounts Receivable		64,738			(41,936	)
Insurance Claims Receivable		(621	)		(142	)
Prepaid Expenses and Other		9,004			14,069
Increase (Decrease) in Operating Liabilities -
Accounts Payable		(31,542	)		(885	)
Insurance Note Payable		(13,236	)		(21,077	)
Other Current Liabilities		(5,010	)		(4,846	)
Other Liabilities		(1,946	)		3,126

Net Cash Provided by Operating Activities		88,322			68,854
Cash Flows from Investing Activities:
Acquisition of Assets		—			(320,839	)
Additions of Property and Equipment		(62,068	)		(130,528	)
Deferred Drydocking Expenditures		(9,662	)		(9,151	)
Proceeds from Sale of Marketable Securities		—			39,300
Insurance Proceeds Received		8,717			25,332
Proceeds from Sale of Assets, Net		4,722			12,649

Net Cash Used in Investing Activities		(58,291	)		(383,237	)
Cash Flows from Financing Activities:
Short-term Debt Borrowings (Repayments), Net		(2,455	)		1,086
Long-term Debt Borrowings		—			350,000
Long-term Debt Repayments		(2,250	)		(104,470	)
Redemption of 3.375% Convertible Senior Notes		(6,099	)		—
Common Stock Repurchases		—			(49,228	)
Proceeds from Exercise of Stock Options		—			5,127
Excess Tax Benefit from Stock-Based Arrangements		4,209			5,447
Payment of Debt Issuance Costs		—			(8,005	)

Other		(11	)		—

Net Cash Provided by (Used in) Financing Activities		(6,606	)		199,957

Net Increase (Decrease) in Cash and Cash Equivalents		23,425			(114,426	)
Cash and Cash Equivalents at Beginning of Period		106,455			212,452

Cash and Cash Equivalents at End of Period	$	129,880		$	98,026

The accompanying notes are an integral part of these financial statements.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

(Unaudited)


	Three Months Ended June 30,					Six Months Ended June 30,
	2009			2008		2009			2008
				(As Adjusted)					(As Adjusted)
Net Income (Loss)	$	(12,029	)	$	16,179	$	(16,973	)	$	20,665
Other Comprehensive Income (Loss), Net of Taxes:
Changes Related to Hedge Transactions		1,988			5,352		1,582			(1,674	)

Comprehensive Income (Loss)	$	(10,041	)	$	21,531	$	(15,391	)	$	18,991

The accompanying notes are an integral part of these financial statements.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
UNAUDITED

1. General

Hercules Offshore, Inc. and its majority owned subsidiaries (the “Company”) provides shallow-water drilling and marine services to the oil and natural gas exploration and production industry in the U.S. Gulf of Mexico and international locations through its Domestic Offshore, International Offshore, Inland, Domestic Liftboats, International Liftboats and Delta Towing segments (See Note 11). At June 30, 2009, the Company owned a fleet of 31 jackup rigs, 17 barge rigs, three submersible rigs, one platform rig, a fleet of marine support vessels operated through Delta Towing, a wholly owned subsidiary, and 60 liftboat vessels and operated an additional five liftboat vessels owned by a third party. In addition, the Company owns four retired jackup rigs and 10 retired inland barges, all located in the U.S. Gulf of Mexico. These rigs would require extensive refurbishment and currently are not expected to re-enter active service. The Company currently operates in ten countries on four continents.

In January 2009, the Company entered into agreements with Mosvold Middle East Jackup I Ltd. and Mosvold Middle East Jackup II Ltd. whereby it will market, manage and operate two high-specification new-build jackup drilling rigs each with a maximum water depth of 300 feet. The rigs, which have an independent leg cantilever design, are under construction in the Middle East and are expected to be available for operations in early to mid first quarter 2010 and second quarter 2010, respectively. The Company will have worldwide, exclusive marketing rights, except in U.S. sanctioned countries. All operating and capital expenses incurred to operate the rig will be paid for or reimbursed by Mosvold Middle East Jackup I Ltd. or Mosvold Middle East Jackup II Ltd. Upon commencement of a drilling contract, the Company will receive a commencement fee and an ongoing management fee for the remainder of the contract.

The consolidated financial statements of the Company are unaudited; however, they include all adjustments of a normal recurring nature which, in the opinion of management, are necessary to present fairly the Company’s Consolidated Balance Sheet at June 30, 2009, Consolidated Statements of Operations and Consolidated Statements of Comprehensive Income (Loss) for the three and six months ended June 30, 2009 and 2008, and Consolidated Statements of Cash Flows for the six months ended June 30, 2009 and 2008. Although the Company believes the disclosures in these financial statements are adequate to make the interim information presented not misleading, certain information relating to the Company’s organization and footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles have been condensed or omitted in this Form 10-Q pursuant to Securities and Exchange Commission rules and regulations. These financial statements should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2008 and the notes thereto included in the Company’s Annual Report on Form 10-K. The results of operations for the three and six months ended June 30, 2009 are not necessarily indicative of the results expected for the full year.

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, the Company evaluates its estimates, including those related to bad debts, investments, intangible assets, property, plant and equipment, income taxes, insurance, employment benefits and contingent liabilities. The Company bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates.

Reclassifications

Certain reclassifications have been made to conform prior year financial information to the current period presentation.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED

Revenue Recognition

Revenues generated from our contracts are recognized as services are performed. For certain contracts, the Company may receive lump-sum fees for the mobilization of equipment and personnel. Mobilization fees received and costs incurred to mobilize a rig from one market to another under contracts longer than one month are recognized as services are performed over the term of the related drilling contract. Amounts related to mobilization fees are summarized below (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
Mobilization revenue deferred	$	—	$	4,450	$	12,000	$	8,277
Mobilization expense deferred		—		—		132		3,398
Mobilization revenue recognized		4,233		4,206		8,149		6,176
Mobilization expense recognized		700		2,142		1,393		2,956

For certain contracts, the Company may receive fees from its customers for capital improvements to its rigs. Such fees are deferred and recognized as services are performed over the term of the related contract. The Company capitalizes such capital improvements and depreciates them over the useful life of the asset.

The Company records reimbursements from customers for “out-of-pocket” expenses as revenues and the related cost as direct operating expenses. Total revenues from such reimbursements were $4.5 million and $3.9 million for the three months ended June 30, 2009 and 2008, respectively. Total revenues from such reimbursements were $8.0 million and $6.8 million for the six months ended June 30, 2009 and 2008, respectively.

Other Assets

Other assets consist of drydocking costs for marine vessels, other intangible assets, deferred costs, financing fees, investments, deposits and other. Drydocking costs are capitalized at cost and amortized on the straight-line method over a period of 12 months. Drydocking costs, net of accumulated amortization, at June 30, 2009 and December 31, 2008, were $7.6 million and $6.5 million, respectively. Amortization expense for drydocking costs was $4.8 million and $4.7 million for the three months ended June 30, 2009 and 2008, respectively, and $8.6 million and $9.8 million for the six months ended June 30, 2009 and 2008, respectively.

Financing fees are deferred and amortized over the life of the applicable debt instrument. However, in the event of an early repayment of debt, the related unamortized deferred financing fees are expensed in connection with the repayment. Unamortized deferred financing fees at June 30, 2009 and December 31, 2008 were $14.7 million and $18.2 million, respectively. The amortization expense related to the deferred financing fees is included in interest expense on the Consolidated Statements of Operations. Amortization expense for financing fees was $1.0 million for both the three months ended June 30, 2009 and 2008, and $2.1 million and $1.7 million for the six months ended June 30, 2009 and 2008, respectively. In addition, the Company recognized a pretax charge of $1.4 million related to the write off of unamortized issuance costs related to its 3.375% Convertible Senior Notes in connection with the April 2009 debt repurchase and the June 2009 debt retirement (See Note 5).

Other Intangible Assets

As of June 30, 2009 and December 31, 2008, the Company had certain international customer contracts with a carrying value of $4.0 million and $7.2 million, net of accumulated amortization of $13.6 million and $10.4 million, respectively, included in Other Assets, Net on the Consolidated Balance Sheets. The value of each contract is being amortized over its respective life.

Amortization expense was $1.7 million and $2.2 million for the three months ended June 30, 2009 and 2008, respectively, and $3.2 million and $4.2 million for the six months ended June 30, 2009 and 2008, respectively. Future estimated amortization expense for the carrying amount of these intangible assets as of June 30, 2009 is expected to be as follows (in thousands):


Remainder of 2009	$	1,793
2010		1,590
2011		658
2012		—
2013		—

HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED

Cash and Cash Equivalents and Marketable Securities

Cash and cash equivalents include cash on hand, demand deposits with banks and all highly liquid investments with original maturities of three months or less. From time to time the Company may invest a portion of its available cash in marketable securities. Marketable securities are classified as available for sale and are stated at fair value on the Consolidated Balance Sheets. At June 30, 2009 and December 31, 2008, the Company had no investments in marketable securities.

Realized and unrealized gains and losses related to marketable securities are calculated using the specific identification method. Unrealized gains or losses, net of taxes, are included in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets until realized. Realized gains or losses are included in Other, Net in the Consolidated Statements of Operations. Proceeds of $39.3 million were received from sales and maturities of marketable securities for the six months ended June 30, 2008. There were no realized or unrealized gains or losses related to these securities in the six months ended June 30, 2009 and 2008.

2. Earnings Per Share

The reconciliation of the numerator and denominator used for the computation of basic and diluted earnings per share is as follows (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
Denominator:
Weighted average basic shares		88,733		88,625		88,368		88,742
Add effect of stock equivalents		—		836		—		774

Weighted average diluted shares		88,733		89,461		88,368		89,516

The Company calculates basic earnings per share by dividing net income by the weighted average number of shares outstanding. Diluted earnings per share is computed by dividing net income by the weighted average number of shares outstanding during the period as adjusted for the dilutive effect of the Company’s stock option and restricted stock awards. The effect of stock option and restricted stock awards is not included in the computation for periods in which a net loss occurs, because to do so would be anti-dilutive. Stock equivalents of 4,826,061 and 4,343,526 were anti-dilutive and are excluded from the calculation of the dilutive effect of stock equivalents for the diluted earnings per share calculations for the three and six months ended June 30, 2009, respectively. Stock equivalents of 176,092 and 542,748 were anti-dilutive and are excluded from the calculation of the dilutive effect of stock equivalents for the diluted earnings per share calculations for the three and six months ended June 30, 2008, respectively.

3. Asset Acquisition

In February 2008, the Company entered into a definitive agreement to purchase three jackup drilling rigs and related equipment for $320.0 million. The Company completed the purchase of the Hercules 350 and the Hercules 261 and related equipment during March 2008, while the purchase of the Hercules 262 and related equipment was completed in May 2008.

4. Dispositions and Assets Held for Sale

In June 2009, the Company entered into an agreement to sell its Hercules 100 and Hercules 110 jackup drilling rigs for a total purchase price of $12.0 million. The Hercules 100 is classified as “retired” and is currently stacked in Sabine Pass, Texas, and the Hercules 110 is cold-stacked in Trinidad. The closing of the sale of the Hercules 100 and Hercules 110 is expected to occur on or before August 15, 2009 and is subject to customary closing conditions. The Consolidated Statements of Operations for the three and six months ended June 30, 2009 includes approximately $26.9 million ($13.1 million, net of tax) of impairment charges related to the write-down of the Hercules 110 to fair value less costs to sell (See Note 7). The financial information for the Hercules 100 has historically been reported as part of the Domestic Offshore Segment and the Hercules 110 financial information has been reported as part of the International Offshore Segment.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED

Balance sheet information for the assets held for sale is as follows:


	June 30,		December 31,
	2009		2008
Other	$	123	$	123
Property and Equipment, Net		11,267		39,500

Current Assets Held for Sale	$	11,390	$	39,623

During the second quarter of 2008, the Company sold Hercules 256 for gross proceeds of $8.5 million, which approximated the carrying value of this asset.

5. Debt

Debt is comprised of the following (in thousands):


	June 30, 2009		December 31, 2008
			(As Adjusted)
Term Loan Facility, due July 2013	$	884,250	$	886,500
3.375% Convertible Senior Notes due June 2038		81,460		134,752
7.375% Senior Notes, due April 2018		3,512		3,512
Foreign Overdraft Facility		—		2,455

Total Debt		969,222		1,027,219
Less Short-term Debt and Current Portion of Long-term Debt		9,000		11,455

Total Long-term Debt, Net of Current Portion	$	960,222	$	1,015,764

Senior secured credit agreement

In July 2007, the Company entered into a $1,050.0 million credit facility, consisting of a $900.0 million term loan facility and a $150.0 million revolving credit facility which is governed by the credit agreement (“Credit Agreement”). In connection with the Credit Agreement, the Company entered into derivative instruments with the purpose of hedging future interest payments (See Note 6). In April 2008, the Company entered into an agreement to increase the revolving credit facility to $250.0 million.

The availability under the revolving credit facility is to be used for working capital, capital expenditures and other general corporate purposes. No amounts were outstanding and $14.1 million in standby letters of credit had been issued under the revolving credit facility as of June 30, 2009. The remaining availability under this revolving credit facility was $235.9 million at June 30, 2009.

As of June 30, 2009, $884.3 million was outstanding on the term loan facility and the interest rate was 2.96%. The annualized effective rate of interest was 5.09% for the six months ended June 30, 2009 after giving consideration to revolver fees and derivative activities.

The Company’s obligations under the Credit Agreement are secured by liens on a majority of its vessels and substantially all of its other personal property. Substantially all of the Company’s domestic subsidiaries, and several of its international subsidiaries, guarantee the obligations under the Credit Agreement and have granted similar liens on several of their vessels and substantially all of their other personal property.

The Credit Agreement requires that the Company meet certain financial ratios and tests, which it met as of June 30, 2009. The Company’s failure to comply with such covenants would result in an event of default under the Credit Agreement. An event of default could prevent the Company from borrowing under the revolving credit facility, which would in turn have a material adverse effect on the Company’s available liquidity. Additionally, an event of default could result in the Company having to immediately repay all amounts outstanding under the Credit Agreement and in the foreclosure of liens on its assets.

On July 27, 2009 the Company amended its Credit Agreement with the syndicate of financial institutions (“Credit Amendment”) in order to revise its covenants to be more favorable to the Company. A fee of 0.50% was paid to lenders consenting to the Credit Amendment based on their total commitment, which approximated $4.8 million.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED

The Credit Amendment reduced the revolving credit facility by $75.0 million to $175.0 million. The commitment fee on the revolving credit facility increased from 0.375% to 1.00%. Additionally, the Credit Amendment establishes a minimum London Interbank Offered Rate (“LIBOR”) rate of 2.00% and 3.00% with respect to the Company’s Alternative Base Rate (“ABR”) Loans and increases the margin applicable to Eurodollar Loans and ABR Loans, subject to a grid based on the aggregate principal amount of the term loans outstanding as follows ($ in millions):


Principal Amount Outstanding				Margin Applicable to:
Less than or				Eurodollar			ABR
equal to:		Greater than:		Loans			Loans
$	882.0	$	684.25		6.50	%		5.50	%
	684.25		484.25		5.00	%		4.00	%
	484.25		—		4.00	%		3.00	%

The Credit Amendment also modifies certain provisions of the Credit Agreement to, among other things:

	•		Eliminate the requirement that the Company comply with the total leverage ratio financial covenant for the nine month period commencing October 1, 2009 and ending on June 30, 2010 and amend the maximum total leverage ratio following the expiration of the nine month period to be more favorable to the Company;

	•		Require maintenance of a minimum level of liquidity, measured as the amount of unrestricted cash and cash equivalents on hand and availability under the revolving credit facility, of (i) $100.0 million for the period between October 1, 2009 through December 31, 2010, (ii) $75.0 million during calendar year 2011 and (iii) $50.0 million thereafter;

	•		Revise the fixed charge coverage ratio definition and reduce the minimum fixed charge coverage ratio that the Company must maintain in a manner that is more favorable to the Company;

	•		Require mandatory prepayments of debt outstanding under the Credit Agreement with 100% of excess cash flow for the fiscal year ending December 31, 2009 and 50% of excess cash flow thereafter and with proceeds from:

	§		unsecured debt issuances, with the exception of refinancing, through June 30, 2010;

	§		secured debt issuances; and

	§		sales of assets in excess of $25 million annually; and

	§		unless the Company has achieved a specified leverage ratio, 50% of proceeds from equity issuances, excluding those for permitted acquisitions or to meet the minimum liquidity requirements.

•

The availability under the $175.0 million revolving credit facility must be used for working capital, capital expenditures and other general corporate purposes and cannot be used to prepay the term loan.

Senior notes and other debt

As of January 1, 2009, the Company adopted Financial Accounting Standards Board (“FASB”) Staff Position (“FSP”) No. APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement) (“FSP 14-1”), with retrospective application to the terms of the 3.375% Convertible Senior Notes as they existed for all periods presented (See Note 13). The Consolidated Balance Sheet for December 31, 2008 has been restated to reflect the adoption which resulted in a $30.1 million increase to Capital in Excess of Par Value, a $9.5 million increase to Deferred Income Taxes, a $27.0 million decrease to Long-term Debt and an increase to Retained Deficit of $12.6 million. The Consolidated Statements of Operations for the three and six months ended June 30, 2008 have also been restated to reflect the adoption. The restatement of the Consolidated Statements of Operations for the three and six months ended June 30, 2008 resulted in the Company recognizing $0.6 million, $0.3 million, net of tax, in interest expense, or $0.003 per diluted share, related to discount amortization.

The carrying amount of the equity component of the 3.375% Convertible Senior Notes was $30.1 million at both June 30, 2009 and December 31, 2008. The principal amount of the liability component of the 3.375% Convertible Senior Notes, its unamortized discount and its net carrying amount was $95.9 million, $14.4 million and $81.5 million, respectively, as of June 30, 2009 and $161.8 million, $27.0 million and $134.8 million, respectively, as of December 31, 2008. The unamortized discount is being amortized to interest expense over the expected life of the 3.375% Convertible Senior Notes which ends June 3, 2013. During the three months ended June 30, 2009, the Company recognized $2.2 million, $1.5 million, net of tax, in interest expense, or $0.02 per diluted share, at an effective rate of 7.93%, of which $1.1 million related to the coupon rate of 3.375% and $1.1 million related to discount amortization. During the six months ended June 30, 2009, the Company recognized $4.9 million, $3.2 million, net of tax, in interest expense, or $0.04 per diluted share, at an effective rate of 7.93%, of which $2.5 million related to the coupon rate of 3.375% and $2.4 million related to discount amortization.

Upon maturity or redemption, the Company determined it has the intent and ability to settle the principal amount of its 3.375% Convertible Senior Notes in

HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED

cash, and any additional conversion consideration spread (the excess of conversion value over face value) in shares of the Company’s common stock (“Common Stock”).

The notes will be convertible under certain circumstances into shares of the Company’s Common Stock at an initial conversion rate of 19.9695 shares of Common Stock per $1,000 principal amount of notes, which is equal to an initial conversion price of approximately $50.08 per share. Upon conversion of a note, a holder will receive, at the Company’s election, shares of Common Stock, cash or a combination of cash and shares of Common Stock. At June 30, 2009 the number of conversion shares potentially issuable in relation to the 3.375% Convertible Senior Notes was 1.9 million.

In April 2009, the Company repurchased $20.0 million aggregate principal amount of the 3.375% Convertible Senior Notes for a cost of $6.1 million, resulting in a gain of $10.7 million. In addition, the Company expensed $0.4 million of unamortized issuance costs in connection with the retirement. In June 2009, the Company retired $45.8 million aggregate principal amount of its 3.375% Convertible Senior Notes in exchange for the issuance of 7,755,440 Common Stock valued at $4.38 per share and payment of accrued interest, resulting in a gain of $4.4 million. In addition, the Company expensed $1.0 million of unamortized issuance costs in connection with the retirement. In accordance with FSP 14-1, the settlement consideration was allocated to the extinguishment of the liability component in an amount equal to the fair value of that component immediately prior to extinguishment, with the difference between this allocation and the net carrying amount of the liability component and unamortized debt issuance costs recognized as a gain or loss on debt extinguishment. If there would have been any remaining settlement consideration, it would have been allocated to the reacquisition of the equity component and recognized as a reduction of Stockholders’ Equity.

The foreign overdraft facility, which was designed to manage local currency liquidity in Venezuela, was terminated in March 2009 and all outstanding amounts were repaid.

The fair value of the Company’s 3.375% Convertible Senior Notes and term loan facility is estimated based on quoted prices in active markets. The Company believes the carrying value of its short-term debt instruments outstanding at December 31, 2008 approximate fair value. The following table provides the carrying value and fair value of the Company’s long-term debt instruments:


	June 30, 2009				December 31, 2008
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(in millions)
Term Loan Facility, due July 2013	$	884.3	$	769.3	$	886.5	$	571.8
3.375% Convertible Senior Notes due June 2038		81.5		58.1		134.8		77.2
7.375% Senior Notes, due April 2018 (a)		3.5		n/a		3.5		n/a


(a)		The 7.375% Senior Notes have not been traded in recent periods and the Company believes that the fair value would not materially differ from the carrying value.

6. Derivative Instruments and Hedging

Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended (“SFAS No. 133(R)”), requires companies to recognize all of its derivative instruments as either assets or liabilities in the statement of financial position at fair value. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and further, on the type of hedging relationship. For those derivative instruments that are designated and qualify as hedging instruments, a company must designate the hedging instrument, based upon the exposure being hedged, as a fair value hedge, cash flow hedge, or a hedge of a net investment in a foreign operation.

The Company periodically uses derivative instruments to manage its exposure to interest rate risk, including interest rate swap agreements to effectively fix the interest rate on variable rate debt and interest rate collars to limit the interest rate range on variable rate debt. In accordance with SFAS No. 133(R), these hedge transactions are being accounted for as cash flow hedges.

For derivative instruments that are designated and qualify as a cash flow hedge, the effective portion of the gain or loss on the derivative instrument is reported as a component of other comprehensive income and reclassified into earnings in the same line item associated with the forecasted transaction and in the period or periods during which the hedged transaction affects earnings. The effective portion of the interest rate swaps and collars hedging the exposure to variability in expected future cash flows due to changes in interest rates is reclassified into interest expense. The remaining gain or loss on the derivative instrument in excess of the cumulative change in the present value of future cash flows of the hedged item, if any, or hedged components excluded from the assessment of effectiveness, is recognized in the Consolidated Statements of Operations during the current period. The Company did

HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED

not recognize a gain or loss due to hedge ineffectiveness in the Consolidated Statements of Operations for the three and six months ended June 30, 2009 and 2008 related to these hedging instruments. The Company expects to realize $17.9 million of unrealized loss in the Consolidated Statements of Operations over the next twelve months.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED

In May 2008 and July 2007, the Company entered into derivative instruments with the purpose of hedging future interest payments on its term loan facility. In May 2008, the Company entered into a floating to fixed interest rate swap with varying notional amounts beginning with $100.0 million with a settlement date of October 1, 2008 and ending with $75.0 million with a settlement date of December 31, 2009. The Company receives an interest rate of three-month LIBOR and pays a fixed coupon of 2.980% over six quarters. The terms and settlement dates of the swap match those of the term loan. In July 2007, the Company entered into a floating to fixed interest rate swap with decreasing notional amounts beginning with $400.0 million with a settlement date of December 31, 2007 and ending with $50.0 million which was settled on April 1, 2009. The Company received a payment equal to the product of three-month LIBOR and the notional amount and paid a fixed coupon of 5.307% on the notional amount over six quarters. The terms and settlement dates of the swap matched those of the term loan. In July 2007, the Company also entered into a zero cost LIBOR collar on $300.0 million of term loan principal with a final settlement date of October 1, 2010 with a ceiling of 5.75% and a floor of 4.99%. The counterparty is obligated to pay the Company in any quarter that actual LIBOR resets above 5.75% and the Company pays the counterparty in any quarter that actual LIBOR resets below 4.99%. The terms and settlement dates of the collar match those of the term loan.

The following table provides the schedule of notional amounts related to the May 2008 interest rate swap (in thousands):


July 1, 2009-September 30, 2009	$	175,000
October 1, 2009-December 30, 2009		75,000

The following table provides the fair values of the Company’s interest rate derivatives (in thousands):


As of June 30,			As of December 31,
2009			2008
Balance Sheet	Fair		Balance Sheet	Fair
Classification	Value		Classification	Value
Derivatives designated as hedging:
Interest rate contracts:
Other	$	41	Other	$	21

Total Asset Derivatives	$	41	Total Asset Derivatives	$	21

Other Current Liabilities	$	17,976	Other Current Liabilities	$	15,669

Other Liabilities		2,603	Other Liabilities		7,324

Total Liability Derivatives	$	20,579	Total Liability Derivatives	$	22,993

HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED

The following table provides the effect of the Company’s interest rate derivatives on the Consolidated Statements of Operations (in thousands):


Derivatives in	I.							III.
Statement 133	Three Months Ended							Three Months Ended
Cash Flow	June 30,							June 30,

Hedging Relationships	2009			2008			II.	2009			2008
Interest rate contracts	$	(605	)	$	2,936		Interest Expense	$	(3,989	)	$	(3,717	)

Derivatives in	I.							III.
Statement 133	Six Months Ended							Six Months Ended
Cash Flow	June 30,							June 30,

Hedging Relationships	2009			2008			II.	2009			2008
Interest rate contracts	$	(3,880	)	$	(4,448	)	Interest Expense	$	(8,403	)	$	(4,267	)


I.		Amount of Gain (Loss), Net of Taxes Recognized in Other Comprehensive Income on Derivative (Effective Portion)

II.		Classification of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion)

III.		Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion)

A summary of the changes in Accumulated Other Comprehensive Loss (in thousands):



Cumulative unrealized loss, net of tax of $8,040, as of December 31, 2008	$	(14,932	)
Reclassification of losses into net income, net of tax of $2,941		5,462
Other comprehensive losses, net of tax of $2,089		(3,880	)

Cumulative unrealized loss, net of tax of $7,188, as of June 30, 2009	$	(13,350	)

7. Fair Value Measurements

In January 2008, the Company adopted, without material impact to its consolidated financial statements, the provisions of SFAS No. 157 related to financial assets and liabilities and to nonfinancial assets and liabilities measured at fair value on a recurring basis. SFAS No. 157 defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements, rather, its application is made pursuant to other accounting pronouncements that require or permit fair value measurements. In February 2008, the FASB issued FSP SFAS No. 157-2, Effective Date of FASB Statement No. 157, which defers the effective date of SFAS No. 157 for one year for certain nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. Effective January 1, 2009, the Company adopted, without material impact on its consolidated financial statements, the provision for nonfinancial assets and liabilities that are not required or permitted to be measured at fair value on a recurring basis, which include those measured at fair value in impairment testing and those initially measured at fair value in a business combination.

In April 2009, the FASB issued FSP No. FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset and Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly (“FSP 157-4”). This FSP provides additional guidance on estimating fair value when the volume and level of transaction activity for an asset or liability have significantly decreased in relation to normal market activity for the asset or liability. The FSP also provides additional guidance on circumstances that may indicate that a transaction is not orderly. This statement is effective for interim or annual financial periods ending after June 15, 2009. Accordingly, the Company adopted FSP 157-4 in June 2009 with no impact to its financial statements.

Fair value measurements are generally based upon observable and unobservable inputs. Observable inputs reflect market data obtained from independent sources, while unobservable inputs reflect our view of market assumptions in the absence of observable market information. The Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. SFAS No. 157 includes a fair value hierarchy that is intended to increase consistency and comparability in fair value measurements and related disclosures. The fair value hierarchy consists of the following three levels:

HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED


		Level 3		—		Inputs are derived from valuation techniques in which one or more significant inputs or value drivers are unobservable.

The valuation techniques that may be used to measure fair value are as follows:

	(A)		Market approach — Uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities

	(B)		Income approach — Uses valuation techniques to convert future amounts to a single present amount based on current market expectations about those future amounts, including present value techniques, option-pricing models and excess earnings method

	(C)		Cost approach — Based on the amount that currently would be required to replace the service capacity of an asset (replacement cost)

The following table represents our derivative assets and liabilities measured at fair value on a recurring basis as of June 30, 2009 (in thousands):

Quoted Prices in

Total

Active Markets for

Fair Value

Identical Asset or

Significant Other

Significant

Measurement

Liability

Observable Inputs

Unobservable Inputs

Valuation

June 30, 2009

(Level 1)

(Level 2)

(Level 3)

Technique

Derivative Assets

—

Derivative Liabilities

20,579

—

20,579

—

The following table represents our assets measured at fair value on a non-recurring basis for which an impairment measurement was made as of June 30, 2009 (in thousands):

Quoted Prices in

Significant

Total

Active Markets for

Other

Significant

Fair Value

Identical Asset or

Observable

Unobservable

Measurement

Liability

Inputs

Valuation

Total

June 30, 2009

(Level 1)

(Level 2)

(Level 3)

Technique

Gain (Loss)

Assets Held for Sale

10,000

—

10,000

—

(26,882

)

In accordance with SFAS No. 144, Long-lived assets held for sale with a carrying amount of $36.7 million were written down to their fair value of $10.0 million, less cost to sell of $0.2 million (or net $9.8 million), resulting in an impairment charge of approximately $26.9 million ($13.1 million, net of tax) related to the write-down of the Hercules 110 to fair value less cost to sell (See Note 4).

8. Stock-based Compensation

The Company’s 2004 Long-Term Incentive Plan (the “2004 Plan”) provides for the granting of stock options, restricted stock, performance stock awards and other stock-based awards to selected employees and non-employee directors of the Company. At June 30, 2009, approximately 4.3 million shares were available for grant or award under the 2004 Plan.

During the six months ended June 30, 2009, the Company granted 1,773,125 stock options with a weighted average exercise price of $1.65 and 5,000 restricted stock awards with a weighted average grant-date fair value per share of $4.82.

The Company recognized $2.1 million and $4.1 million in stock-based compensation expense during the three and six months ended June 30, 2009, respectively, and $5.5 million and $7.9 million during the three and six months ended June 30, 2008, respectively. The excess income tax benefit, the tax deduction that is in excess of the tax benefit recognized in the consolidated financial statements related to stock-based compensation, recognized for the three and six months ended June 30, 2009 was $1.5 million and $4.2 million, respectively, and $5.1 million and $5.4 million for the three and six months ended June 30, 2008, respectively.

The unrecognized compensation cost related to the Company’s unvested stock options and restricted stock grants as of June 30, 2009 was $5.1 million and $6.9 million, respectively, and is expected to be recognized over a weighted-average period of 2.3 years

HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED

and 1.2 years, respectively.

9. Supplemental Cash Flow Information

During the six months ended June 30, 2009 and 2008, the Company had non-cash activities related to its interest rate derivatives of $1.6 million and $(1.7) million, respectively. In addition, the Company had non-cash financing activities related to its June 2009 retirement of $45.8 million aggregate principal amount of its 3.375% Convertible Senior Notes in exchange for the issuance of 7,755,440 Common Stock valued at $4.38 per share ($34.0 million) and payment of accrued interest, resulting in a gain of $4.4 million (See Note 5).


	Six Months Ended June 30,
	2009		2008
	(In thousands)
Cash paid during the period for:
Interest, net of capitalized interest of $333 and $2,675, respectively	$	14,982	$	13,538
Income taxes		12,038		32,994

10. Income Tax

In connection with the July 2007 acquisition of TODCO, the Company, as successor to TODCO, and TODCO’s former parent, Transocean Ltd., are parties to a tax sharing agreement that was originally entered into in connection with TODCO’s initial public offering in 2004. The tax sharing agreement was amended and restated in November 2006 in a negotiated settlement of disputes between Transocean and TODCO over the terms of the original tax sharing agreement. The tax sharing agreement continues to require that additional payments be made to Transocean based on a portion of the expected tax benefit from the exercise of certain compensatory stock options to acquire Transocean common stock attributable to current and former TODCO employees and board members. The estimated amount of payments to Transocean related to compensatory options that remain outstanding at June 30, 2009, assuming a Transocean stock price of $74.29 per share at the time of exercise of the compensatory options (the actual price of Transocean’s common stock at June 30, 2009), is approximately $1.5 million. The Company accounts for the exercise of Transocean stock options held by current and former TODCO employees and board members in the period in which such option is exercised. As tax deductions are generated from the exercise of the stock options and in accordance with SFAS No. 109, Accounting for the Income Taxes (“SFAS No. 109”) and SFAS No. 123R, Share Based Payment (“SFAS No. 123R”), the Company takes a current tax deduction for the value of the stock option tax deduction, pays Transocean for 55% of the value of the deduction and increases additional paid-in capital by 45% of the deduction. Because of the Company’s current NOL position, the tax benefit of the stock option deduction is reclassified as a reduction in net deferred tax liability. There is no certainty that the Company will realize future economic benefits from TODCO’s tax benefits equal to the amount of the payments required under the tax sharing agreement.

The Company’s tax filings for various periods are subject to audit by the tax authorities in most jurisdictions where we conduct business. Internationally, income tax returns from 1998 through 2006 are currently under examination. In addition, several state examinations have commenced or will soon commence. The timing and effect on the Company’s consolidated financial statements of the resolution of these income tax examinations is highly uncertain due to various underlying factors. These factors include, among other things, the amount and nature of additional taxes potentially asserted by local tax authorities; the willingness of local tax authorities to negotiate a reasonable and appropriate settlement through an administrative process; and the impartiality of the local courts. The amounts ultimately paid, if any, upon the resolution of the issues raised by the tax authorities in any audit may differ materially from the amounts accrued for each year. While it is possible that some of these examinations may be resolved in the next 12 months, the Company cannot predict or provide assurance as to the ultimate outcome of existing or future tax assessments.

In December 2002, TODCO received an assessment from SENIAT, the national Venezuelan tax authority, for approximately $20.7 million (based on the current exchange rates at the time of the assessment and inclusive of penalties) relating to calendar years 1998 through 2001. In March 2003, TODCO paid approximately $2.6 million of the assessment, plus approximately $0.3 million in interest, and we are contesting the remainder of the assessment with the Venezuelan Tax Court. After TODCO made the partial assessment payment, it received a revised assessment in September 2003 of approximately $16.7 million (based on the current exchange rates at the time of the assessment and inclusive of penalties). Thereafter, TODCO filed an administrative tax appeal with SENIAT and the tax authority rendered a decision that reduced the tax assessment to $8.1 million (based on the current exchange rates at the time of the decision). TODCO then initiated a judicial tax court appeal with the Venezuelan Tax Court to set aside the $8.1 million administrative tax assessment. In August 2008, the Venezuelan Tax Court ruled in favor of TODCO; however, SENIAT has the right to appeal this case to the Venezuelan Supreme Court. In July 2009, the Company settled the taxes and interest portion of the assessment for approximately 3.3 million Bolivares Fuertes, or approximately $1.5 million (based on the official exchange rate at the date of settlement). The Company is disputing any residual penalties which are currently assessed at 3.4 million Bolivares Fuertes, or $1.6 million (based on the official exchange rate at the date of assessment). The Company, as successor to TODCO, is fully

HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED

indemnified by TODCO’s former parent, Transocean Ltd. related to this settlement. The Company does not expect the ultimate resolution of this tax assessment and settlement to have a material impact on its consolidated results of operations, financial condition or cash flows. In January 2008, SENIAT commenced an audit for the 2003 calendar year, which was completed in the fourth quarter of 2008. The Company has not yet received any proposed adjustments from SENIAT for that year.

In March 2007, a subsidiary of the Company received an assessment from the Mexican tax authorities related to its operations for the 2004 tax year. This assessment contests the Company’s right to certain deductions and also claims it did not remit withholding tax due on certain of these deductions. The Company is pursuing its alternatives to resolve this assessment. In accordance with local statutory requirements, we have provided a surety bond for an amount equal to $13 million as of June 30, 2009, to contest these assessments. In 2008, the Mexican tax authorities commenced an audit for the 2005 tax year. Depending on the ultimate outcome of the 2004 assessment and the 2005 audit, the Company anticipates that the Mexican tax authorities could make similar assessments for other open tax years.

11. Segments

The Company reports its business activities in six business segments: (1) Domestic Offshore, (2) International Offshore, (3) Inland, (4) Domestic Liftboats, (5) International Liftboats and (6) Delta Towing. The financial information of the Company’s discontinued operation is not included in the financial information presented for the Company’s reporting segments. The Company eliminates inter-segment revenue and expenses, if any.

In January 2009, the Company reclassified four of its cold-stacked jackup rigs located in the U.S. Gulf of Mexico and 10 of its cold-stacked inland barges as retired. These rigs would require extensive refurbishment and currently are not expected to re-enter active service. The following describes the Company’s reporting segments as of June 30, 2009:

Domestic Offshore — includes 20 jackup rigs and three submersible rigs in the U.S. Gulf of Mexico that can drill in maximum water depths ranging from 85 to 350 feet. Eleven of the jackup rigs are either working on short-term contracts or available for contracts. Nine jackup rigs and all three submersibles are cold-stacked.

International Offshore — includes 11 jackup rigs and one platform rig outside of the U.S. Gulf of Mexico. The Company has one jackup rig working offshore in each of Qatar and Malaysia as well as one jackup rig warm-stacked in Gabon. The Company has two jackup rigs working offshore in each of India and Saudi Arabia and two jackup rigs and one platform rig operating in Mexico. In addition, the Company has one jackup rig currently in-transit to its operating location in Angola and one jackup rig cold-stacked in Trinidad. In June 2009, the company entered into an agreement to sell the Hercules 110, which is expected to occur on or before August 15, 2009 and is subject to customary closing conditions (See Note 4).

Inland — includes a fleet of 6 conventional and 11 posted barge rigs that operate inland in marshes, rivers, lakes and shallow bay or coastal waterways along the U.S. Gulf Coast. Three of the Company’s inland barges are either operating on short-term contracts or available and 14 are cold-stacked.

Domestic Liftboats — includes 45 liftboats in the U.S. Gulf of Mexico. Forty-two are operating in the U.S. Gulf of Mexico and three are cold-stacked.

International Liftboats — includes 20 liftboats. Eighteen are operating offshore West Africa, including five liftboats owned by a third party. One liftboat is in the Middle East region with an expected contract commencement date in the third quarter 2009 and one liftboat is in the Middle East region available for contracts.

Delta Towing — the Company’s Delta Towing business operates a fleet of 30 inland tugs, 14 offshore tugs, 34 crew boats, 46 deck barges, 17 shale barges and four spud barges along and in the U.S. Gulf of Mexico and along the Southeastern coast. As of June 30, 2009, 24 crew boats, 17 inland tugs and five offshore tugs were cold-stacked, and the remaining are working or available for contracts.

The Company’s jackup rigs, submersible rigs and platform rigs are used primarily for exploration and development drilling in shallow waters. The Company’s liftboats are self-propelled, self-elevating vessels that support a broad range of offshore maintenance and construction services throughout the life of an oil or natural gas well.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED

Information regarding reportable segments is as follows (in thousands):


	Three Months Ended June 30, 2009							Six Months Ended June 30, 2009
			Income (Loss)							Income (Loss)			Depreciation
			from			Depreciation &				from			&
	Revenue		Operations			Amortization		Revenue		Operations			Amortization
Domestic Offshore	$	36,970	$	(20,180	)	$	15,092	$	96,151	$	(32,120	)	$	30,132
International Offshore (a)		101,757		17,175			16,749		205,209		60,060			31,933
Inland		96		(17,372	)		8,283		13,009		(33,616	)		16,276
Domestic Liftboats		18,884		212			5,747		41,494		3,231			10,796
International Liftboats		20,747		8,378			2,278		39,389		15,238			4,662
Delta Towing		5,237		(3,065	)		2,142		11,930		(7,322	)		4,426

		183,691		(14,852	)		50,291		407,182		5,471			98,225
Corporate		—		(10,977	)		800		—		(22,191	)		1,712

Total Company	$	183,691	$	(25,829	)	$	51,091	$	407,182	$	(16,720	)	$	99,937


(a)		Income (Loss) from Operations for the Company’s International Offshore Segment includes a $26.9 million impairment of property and equipment charge for the three and six months ended June 30, 2009.


	Three Months Ended June 30, 2008							Six Months Ended June 30, 2008
			Income (Loss)							Income (Loss)			Depreciation
			from			Depreciation &				from			&
	Revenue		Operations			Amortization		Revenue		Operations			Amortization
Domestic Offshore	$	97,438	$	23,577		$	16,204	$	159,885	$	21,687		$	31,539
International Offshore		74,187		27,424			9,310		139,530		61,774			16,896
Inland		40,262		(2,914	)		10,520		80,530		(4,854	)		20,180
Domestic Liftboats		22,269		2,973			5,382		38,213		(1,578	)		11,334
International Liftboats		20,305		6,752			2,368		38,596		14,900			4,352
Delta Towing		15,645		2,453			2,706		25,846		1,961			5,275

		270,106		60,265			46,490		482,600		93,890			89,576
Corporate		—		(19,413	)		784		—		(31,674	)		1,318

Total Company	$	270,106	$	40,852		$	47,274	$	482,600	$	62,216		$	90,894


	Total Assets
	June 30,		December 31,
	2009		2008
Domestic Offshore	$	899,389	$	930,988
International Offshore (a)		1,015,601		955,911
Inland		175,941		217,477
Domestic Liftboats		140,722		148,307
International Liftboats		127,160		168,356
Delta Towing		72,396		92,371
Corporate		81,099		77,485

Total Company	$	2,512,308	$	2,590,895


(a)		Total Assets as of June 30, 2009 for the Company’s International Offshore Segment reflect a $26.9 million impairment of property and equipment. Included in Total Assets is $9.8 million and $37.8 million in Assets Held for Sale as of June 30, 2009 and December 31, 2008, respectively.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED

12. Commitments and Contingencies

Legal Proceedings

The Company is involved in various claims and lawsuits in the normal course of business. As of June 30, 2009, management did not believe any accruals were necessary in accordance with SFAS No. 5, Accounting for Contingencies.

In connection with the July 2007 acquisition of TODCO, the Company assumed certain material legal proceedings from TODCO and its subsidiaries.

In October 2001, TODCO was notified by the U.S. Environmental Protection Agency (“EPA”) that the EPA had identified a subsidiary of TODCO as a potentially responsible party under CERCLA in connection with the Palmer Barge Line superfund site located in Port Arthur, Jefferson County, Texas. Based upon the information provided by the EPA and the Company’s review of its internal records to date, the Company disputes the Company’s designation as a potentially responsible party and does not expect that the ultimate outcome of this case will have a material adverse effect on our consolidated results of operations, financial position or cash flows. The Company continues to monitor this matter.

Robert E. Aaron et al. vs. Phillips 66 Company et al. Circuit Court, Second Judicial District, Jones County, Mississippi. This is the case name used to refer to several cases that have been filed in the Circuit Courts of the State of Mississippi involving 768 persons that allege personal injury or whose heirs claim their deaths arose out of asbestos exposure in the course of their employment by the defendants between 1965 and 2002. The complaints name as defendants, among others, certain of TODCO’s subsidiaries and certain subsidiaries of TODCO’s former parent to whom TODCO may owe indemnity, and other unaffiliated defendant companies, including companies that allegedly manufactured drilling-related products containing asbestos that are the subject of the complaints. The number of unaffiliated defendant companies involved in each complaint ranges from approximately 20 to 70. The complaints allege that the defendant drilling contractors used asbestos-containing products in offshore drilling operations, land based drilling operations and in drilling structures, drilling rigs, vessels and other equipment and assert claims based on, among other things, negligence and strict liability, and claims authorized under the Jones Act. The plaintiffs seek, among other things, awards of unspecified compensatory and punitive damages. All of these cases were assigned to a special master who has approved a form of questionnaire to be completed by plaintiffs so that claims made would be properly served against specific defendants. As of the date of this report, approximately 700 questionnaires were returned and the remaining plaintiffs, who did not submit a questionnaire reply, have had their suits dismissed without prejudice. Of the respondents, approximately 100 shared periods of employment by TODCO and its former parent which could lead to claims against either company, even though many of these plaintiffs did not state in their questionnaire answers that the employment actually involved exposure to asbestos. After providing the questionnaire, each plaintiff was further required to file a separate and individual amended complaint naming only those defendants against whom they had a direct claim as identified in the questionnaire answers. Defendants not identified in the amended complaints were dismissed from the plaintiffs’ litigation. To date, three plaintiffs named TODCO as a defendant in their amended complaints. It is possible that some of the plaintiffs who have filed amended complaints and have not named TODCO as a defendant may attempt to add TODCO as a defendant in the future when case discovery begins and greater attention is given to each individual plaintiff’s employment background. The Company continues to monitor a small group of these other cases. The Company has not determined which entity would be responsible for such claims under the Master Separation Agreement between TODCO and its former parent. The Company intends to defend vigorously and, based on the limited information available at this time, does not expect the ultimate outcome of these lawsuits to have a material adverse effect on its consolidated results of operations, financial position or cash flows.

The Company and its subsidiaries are involved in a number of other lawsuits, all of which have arisen in the ordinary course of business. The Company does not believe that ultimate liability, if any, resulting from any such other pending litigation will have a material adverse effect on its business or consolidated financial position.

The Company cannot predict with certainty the outcome or effect of any of the litigation matters specifically described above or of any other pending litigation. There can be no assurance that the Company’s belief or expectations as to the outcome or effect of any lawsuit or other litigation matter will prove correct, and the eventual outcome of these matters could materially differ from management’s current estimates.

Insurance

The Company is self-insured for the deductible portion of its insurance coverage. Management believes adequate accruals have been made on known and estimated exposures up to the deductible portion of the Company’s insurance coverage. Management believes that claims and liabilities in excess of the amounts accrued are adequately insured. However, our insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect us against liability from all potential consequences.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED

The Company maintains insurance coverage that includes coverage for physical damage, third party liability, workers’ compensation and employers’ liability, general liability, vessel pollution and other coverages.

In May 2009, the Company completed the renewal of all of its key insurance policies. The Company’s primary marine package provides for hull and machinery coverage for the Company’s rigs and liftboats up to a scheduled value for each asset. The maximum coverage for these assets is $2.2 billion; however, coverage for U.S. Gulf of Mexico named windstorm damage is subject to an annual aggregate limit on liability of $100.0 million. The policies are subject to exclusions, limitations, deductibles, self-insured retention and other conditions. Deductibles for events that are not U.S. Gulf of Mexico named windstorm events are 12.5% of insured values per occurrence for drilling rigs, and $1.0 million per occurrence for liftboats, regardless of the insured value of the particular vessel. The deductibles for drilling rigs and liftboats in a U.S. Gulf of Mexico named windstorm event are the greater of $25.0 million or the operational deductible for each U.S. Gulf of Mexico named windstorm. The Company is self-insured for 15% above the deductibles for removal of wreck, sue and labor, collision, protection and indemnity general liability and hull and physical damage policies. The protection and indemnity coverage under the primary marine package has a $5.0 million limit per occurrence with excess liability coverage up to $200.0 million. The primary marine package also provides coverage for cargo and charterer’s legal liability. Vessel pollution is covered under a Water Quality Insurance Syndicate policy with a $3 million deductible proving limits as required. In addition to the marine package, the Company has separate policies providing coverage for onshore general liability, employer’s liability, auto liability and non-owned aircraft liability, with customary deductibles and coverage as well as a separate primary marine package for its Delta Towing business.

In 2009, in connection with the renewal of certain of its insurance policies, the Company entered into an agreement to finance a portion of its annual insurance premiums. Approximately $21.4 million was financed through this arrangement, and $19.3 million was outstanding at June 30, 2009. The interest rate on the note is 4.15% and the note is scheduled to mature in March 2010. The amounts financed in connection with the prior year renewal were fully paid as of March 31, 2009.

Surety Bonds and Unsecured Letters of Credit

The Company has $39.9 million outstanding related to surety bonds at June 30, 2009. The surety bonds guarantee our performance as it relates to the Company’s drilling contracts, insurance, tax and other obligations in various jurisdictions. These obligations could be called at any time prior to the expiration dates. The obligations that are the subject of the surety bonds are geographically concentrated primarily in Mexico.

The Company had $0.1 million in an unsecured letter of credit outstanding at June 30, 2009.

13. Accounting Pronouncements

In May 2009, the FASB issued SFAS No. 165, Subsequent Events (“SFAS No. 165”). SFAS No. 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date, but before financial statements are issued or are available to be issued. SFAS No. 165 requires disclosure of the date through which an entity has evaluated subsequent events and the basis for that date. This statement is effective for interim or annual financial periods ending after June 15, 2009. Accordingly, the Company adopted SFAS No. 165 in June 2009 with no impact to its financial statements.

In April 2009, the FASB issued FSP No. FAS 107-1 and APB 28-1 Interim Disclosures about Fair Value of Financial Instruments (“FSP 107-1”). This FSP extends the disclosure requirements of SFAS No. 107, Disclosures about Fair Value of Financial Instruments (“SFAS No. 107”), to interim financial statements of publicly traded companies as defined in APB Opinion No. 28, Interim Financial reporting.

In May 2008, the FASB issued FSP 14-1, which clarifies the accounting for convertible debt instruments that may be settled in cash (including partial cash settlement) upon conversion. FSP 14-1 requires issuers to account separately for the liability and equity components of certain convertible debt instruments in a manner that reflects the issuer’s nonconvertible debt (unsecured debt) borrowing rate when interest cost is recognized. FSP 14-1 requires bifurcation of a component of the debt, classification of that component in equity and the accretion of the resulting discount on the debt to be recognized as part of interest expense in the Company’s consolidated statement of operations. The interest rate to be used under FSP 14-1 will therefore be significantly higher

HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED

than the rate on the Company’s Convertible Senior Notes due 2038 that was previously used, which was equal to the coupon rate of 3.375 percent. As of January 1, 2009, the Company adopted FSP 14-1 with retrospective application to the terms of instruments as they existed for all periods presented (See Note 5).

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities (“SFAS No. 161”). SFAS No. 161 amends SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS No. 133”) requiring enhanced disclosures about an entity’s derivative and hedging activities, thereby improving the transparency of financial reporting. SFAS No. 161’s disclosures provide additional information on how and why derivative instruments are being used. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. Accordingly, the Company adopted SFAS No. 161 as of January 1, 2009 (See Note 6).

14. Subsequent Events

In accordance with SFAS No. 165, the Company evaluated all events or transactions that occurred after June 30, 2009 up through July 28, 2009, the date the Company issued these financial statements. During this period the Company did not have any material recognizable subsequent events. However, the Company did have nonrecognizable subsequent events related to the amendment of its Credit Agreement for its term loan and revolving credit facility as well as the settlement of the taxes and interest portions of the SENIAT assessment (See Note 5 and Note 10, respectively, for additional information).

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the accompanying unaudited consolidated financial statements as of June 30, 2009 and for the three and six months ended June 30, 2009 and June 30, 2008, included elsewhere herein, and with our annual report on Form 10-K for the year ended December 31, 2008. The following information contains forward-looking statements. Please read “Forward-Looking Statements” below for a discussion of certain limitations inherent in such statements. Please also read “Risk Factors” in Item 1A of our annual report for a discussion of certain risks facing our company.

OVERVIEW

We provide shallow-water drilling and marine services to the oil and natural gas exploration and production industry in the U.S. Gulf of Mexico and internationally. We provide these services to major integrated energy companies, independent oil and natural gas operators and national oil companies.

We operate our business as six divisions: (1) Domestic Offshore, (2) International Offshore, (3) Inland, (4) Domestic Liftboats, (5) International Liftboats, and (6) Delta Towing. Previously, we reported an “Other” segment that included Delta Towing and certain land rigs. The land rigs were sold in December 2007, and the results of the land rig operations are included in Discontinued Operation.

As of July 21, 2009, our business segments included the following:

International Offshore — includes 11 jackup rigs and one platform rig outside of the U.S. Gulf of Mexico. We have one jackup rig working offshore in each of Angola and Malaysia as well as one jackup rig warm-stacked in each of Gabon and Bahrain. We have two jackup rigs working offshore in each of India and Saudi Arabia and two jackup rigs and one platform rig operating in Mexico. In addition, we have one jackup rig cold-stacked in Trinidad. In June 2009, we entered into an agreement to sell the Hercules 110 which is expected to occur on or before August 15, 2009 and is subject to customary closing conditions.

Inland — includes a fleet of 6 conventional and 11 posted barge rigs that operate inland in marshes, rivers, lakes and shallow bay or coastal waterways along the U.S. Gulf Coast. Three of our inland barges are either operating on short-term contracts or available and 14 are cold-stacked.

Domestic Liftboats — includes 45 liftboats in the U.S. Gulf of Mexico. Forty-two are operating in the U.S. Gulf of Mexico and three are cold-stacked.

Delta Towing — our Delta Towing business operates a fleet of 30 inland tugs, 14 offshore tugs, 34 crew boats, 46 deck barges, 17 shale barges and four spud barges along and in the U.S. Gulf of Mexico and along the Southeastern coast. As of July 21, 2009, 24 crew boats, 17 inland tugs and five offshore tugs are cold-stacked, and the remaining are working or available for contracts.

In January 2009, we entered into agreements with Mosvold Middle East Jackup I Ltd. and Mosvold Middle East Jackup II Ltd. whereby we will market, manage and operate two high-specification new-build jackup drilling rigs each with a maximum water depth of 300 feet. The rigs, which have an independent leg cantilever design, are under construction in the Middle East and are expected to be available for operations in early to mid first quarter 2010 and second quarter 2010, respectively. We will have worldwide, exclusive marketing rights, except in U.S. sanctioned countries. All operating and capital expenses incurred to operate the rig will be paid for or reimbursed by Mosvold Middle East Jackup I Ltd. or Mosvold Middle East Jackup II Ltd., as applicable. Upon commencement of a drilling contract, we will receive a commencement fee and an ongoing management fee for the remainder of the contract. Additionally, in January 2009, we reclassified four of our cold-stacked jackup rigs located in the U.S. Gulf of Mexico and 10 of our cold-stacked inland barges as retired. These rigs would require extensive refurbishment and currently are not expected to re-enter active service.

Our jackup and submersible rigs and our barge rigs are used primarily for exploration and development drilling in shallow waters. Under most of our contracts, we are paid a fixed daily rental rate called a “dayrate,” and we are required to pay all costs

associated with our own crews as well as the upkeep and insurance of the rig and equipment.

Our liftboats are self-propelled, self-elevating vessels that support a broad range of offshore support services, including platform maintenance, platform construction, well intervention and decommissioning services throughout the life of an oil or natural gas well. Under most of our liftboat contracts, we are paid a fixed dayrate for the rental of the vessel, which typically includes the costs of a small crew of four to eight employees, and we also receive a variable rate for reimbursement of other operating costs such as catering, fuel, rental equipment and other items.

Our revenues are affected primarily by dayrates, fleet utilization, the number and type of units in our fleet and mobilization fees received from our customers. Utilization and dayrates, in turn, are influenced principally by the demand for rig and liftboat services from the exploration and production sectors of the oil and natural gas industry. Our contracts in the U.S. Gulf of Mexico tend to be short-term in nature and are heavily influenced by changes in the supply of units relative to the fluctuating expenditures for both drilling and production activity. Our international drilling contracts and some of our liftboat contracts in West Africa are longer-term in nature.

Our backlog at July 21, 2009 totaled approximately $563.3 million for our executed contracts. Approximately $157.8 million of this backlog is expected to be realized during the remainder of 2009. We calculate our backlog, or future contracted revenue, 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 and customer reimbursables. The amount of actual revenues earned and the actual periods during which revenues are earned will be different than the backlog disclosed or expected due to various factors. Downtime due to various operational factors, including unscheduled repairs, maintenance, weather and other factors (some of which are beyond our control), may result in lower dayrates than the full contractual operating dayrate. In some of the contracts, our customer has the right to terminate the contract without penalty and in certain instances, with little or no notice.

Our operating costs are primarily a function of fleet configuration and utilization levels. The most significant direct operating costs for our Domestic Offshore, International Offshore and Inland segments are wages paid to crews, maintenance and repairs to the rigs, and insurance. These costs do not vary significantly whether the rig is operating under contract or idle, unless we believe that the rig is unlikely to work for a prolonged period of time, in which case we may decide to “cold-stack” or “warm-stack” the rig. Cold-stacking is a common term used to describe a rig that is expected to be idle for a protracted period and typically for which routine maintenance is suspended and the crews are either redeployed or laid-off. When a rig is cold-stacked, operating expenses for the rig are significantly reduced because the crew is smaller and maintenance activities are suspended. Placing rigs in service that have been cold-stacked typically requires a lengthy reactivation project that can involve significant expenditures and potentially additional regulatory review, particularly if the rig has been cold-stacked for a long period of time. Warm-stacking is a term used for a rig expected to be idle for a period of time that is not as prolonged as is the case with a cold-stacked rig. Maintenance is continued for warm-stacked rigs. Crews are reduced but a small crew is retained. Warm-stacked rigs generally can be reactivated in three to four weeks.

The most significant costs for our Domestic Liftboats and International Liftboats segments are the wages paid to crews and the amortization of regulatory drydocking costs. Unlike our Domestic Offshore, International Offshore and Inland segments, a significant portion of the expenses incurred with operating each liftboat are paid for or reimbursed by the customer under contractual terms and prices. This includes catering, fuel, oil, rental equipment, crane overtime and other items. We record reimbursements from customers as revenues and the related expenses as operating costs. Our liftboats are required to undergo regulatory inspections every year and to be drydocked two times every five years; the drydocking expenses and length of time in drydock vary depending on the condition of the vessel. All costs associated with regulatory inspections, including related drydocking costs, are deferred and amortized over a period of twelve months.

RESULTS OF OPERATIONS

The following table sets forth financial information by operating segment and other selected information for the periods indicated:


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
				(Dollars in thousands)
				(As Adjusted)						(As Adjusted)
Domestic Offshore:
Number of rigs (as of end of period) (a)		23			27			23			27
Revenues	$	36,970		$	97,438		$	96,151		$	159,885
Operating expenses		40,746			56,275			95,159			104,047
Depreciation and amortization expense		15,092			16,204			30,132			31,539
General and administrative expenses		1,312			1,382			2,980			2,612

Operating income (loss)	$	(20,180	)	$	23,577		$	(32,120	)	$	21,687

International Offshore:
Number of rigs (as of end of period) (b)		12			12			12			12
Revenues	$	101,757		$	74,187		$	205,209		$	139,530
Operating expenses		39,128			37,308			83,269			60,100
Impairment of property and equipment		26,882			—			26,882			—
Depreciation and amortization expense		16,749			9,310			31,933			16,896
General and administrative expenses		1,823			145			3,065			760

Operating income	$	17,175		$	27,424		$	60,060		$	61,774

Inland:
Number of barges (as of end of period) (a)		17			27			17			27
Revenues	$	96		$	40,262		$	13,009		$	80,530
Operating expenses		8,857			31,306			29,121			63,232
Depreciation and amortization expense		8,283			10,520			16,276			20,180
General and administrative expenses		328			1,350			1,228			1,972

Operating loss	$	(17,372	)	$	(2,914	)	$	(33,616	)	$	(4,854	)

Domestic Liftboats:
Number of liftboats (as of end of period)		45			45			45			45
Revenues	$	18,884		$	22,269		$	41,494		$	38,213
Operating expenses		12,418			13,446			26,552			27,340
Depreciation and amortization expense		5,747			5,382			10,796			11,334
General and administrative expenses		507			468			915			1,117

Operating income (loss)	$	212		$	2,973		$	3,231		$	(1,578	)

International Liftboats:
Number of liftboats (as of end of period)		20			20			20			20
Revenues	$	20,747		$	20,305		$	39,389		$	38,596
Operating expenses		9,113			9,896			17,220			17,116
Depreciation and amortization expense		2,278			2,368			4,662			4,352
General and administrative expenses		978			1,289			2,269			2,228

Operating income	$	8,378		$	6,752		$	15,238		$	14,900


(a)		In January 2009, we retired four Domestic Offshore rigs and ten Inland barges.

(b)		In June 2009, we entered into an agreement to sell Hercules 110 which is cold stacked in Trinidad.


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
				(Dollars in thousands)
				(As Adjusted)						(As Adjusted)
Delta Towing:
Revenues	$	5,237		$	15,645		$	11,930		$	25,846
Operating expenses		5,835			9,783			14,020			17,325
Depreciation and amortization expense		2,142			2,706			4,426			5,275
General and administrative expenses		325			703			806			1,285

Operating income (loss)	$	(3,065	)	$	2,453		$	(7,322	)	$	1,961

Total Company:
Revenues	$	183,691		$	270,106		$	407,182		$	482,600
Operating expenses		116,097			158,014			265,341			289,160
Impairment of property and equipment		26,882			—			26,882			—
Depreciation and amortization expense		51,091			47,274			99,937			90,894
General and administrative expenses		15,450			23,966			31,742			40,330

Operating income (loss)		(25,829	)		40,852			(16,720	)		62,216
Interest expense		(14,561	)		(15,222	)		(30,350	)		(31,178	)
Gain on early retirement of debt, net		13,747			—			13,747			—
Other, net		3,346			250			2,690			2,275

Income (loss) before income taxes		(23,297	)		25,880			(30,633	)		33,313
Income tax benefit (provision)		11,510			(9,492	)		14,335			(12,050	)

Income (loss) from continuing operations		(11,787	)		16,388			(16,298	)		21,263
Loss from discontinued operation, net of taxes		(242	)		(209	)		(675	)		(598	)

Net income (loss)	$	(12,029	)	$	16,179		$	(16,973	)	$	20,665

The following table sets forth selected operational data by operating segment for the period indicated:


	Three Months Ended June 30, 2009
										Average
								Average		Operating
	Operating		Available					Revenue		Expense
	Days		Days		Utilization (1)			per Day (2)		per Day (3)
Domestic Offshore		706		1,136		62.1	%	$	52,365	$	35,868
International Offshore		788		910		86.6	%		129,133		42,998
Inland		—		303		0.0	%		n/a		29,231
Domestic Liftboats		2,444		3,842		63.6	%		7,727		3,232
International Liftboats		1,005		1,729		58.1	%		20,644		5,271


	Three Months Ended June 30, 2008
										Average
								Average		Operating
	Operating		Available					Revenue		Expense
	Days		Days		Utilization (1)			per Day (2)		per Day (3)
Domestic Offshore		1,612		2,024		79.6	%	$	60,445	$	27,804
International Offshore		642		732		87.7	%		115,556		50,967
Inland		1,017		1,486		68.4	%		39,589		21,067
Domestic Liftboats		2,466		3,871		63.7	%		9,030		3,474
International Liftboats		1,331		1,590		83.7	%		15,255		6,224


	Six Months Ended June 30, 2009
										Average
								Average		Operating
	Operating		Available					Revenue		Expense
	Days		Days		Utilization (1)			per Day (2)		per Day (3)
Domestic Offshore		1,570		2,520		62.3	%	$	61,243	$	37,762
International Offshore		1,583		1,757		90.1	%		129,633		47,393
Inland		298		1,026		29.0	%		43,654		28,383
Domestic Liftboats		4,883		7,712		63.3	%		8,498		3,443
International Liftboats		1,923		3,439		55.9	%		20,483		5,007


	Six Months Ended June 30, 2008
										Average
								Average		Operating
	Operating		Available					Revenue		Expense
	Days		Days		Utilization (1)			per Day (2)		per Day (3)
Domestic Offshore		2,710		4,026		67.3	%	$	58,998	$	25,844
International Offshore		1,296		1,441		89.9	%		107,662		41,707
Inland		1,955		3,033		64.5	%		41,192		20,848
Domestic Liftboats		4,066		8,057		50.5	%		9,398		3,393
International Liftboats		2,548		3,137		81.2	%		15,148		5,456


(1)		Utilization is defined as the total number of days our rigs or liftboats, as applicable, were under contract, known as operating days, in the period as a percentage of the total number of available days in the period. Days during which our rigs and liftboats were undergoing major refurbishments, upgrades or construction, and days during which our rigs and liftboats are cold-stacked, are not counted as available days. Days during which our liftboats are in the shipyard undergoing drydocking or inspection are considered available days for the purposes of calculating utilization.

(2)		Average revenue per rig or liftboat per day is defined as revenue earned by our rigs or liftboats, as applicable, in the period divided by the total number of operating days for our rigs or liftboats, as applicable, in the period. Included in International Offshore revenue is a total of $4.2 million and $8.0 million related to amortization of deferred mobilization revenue and contract specific capital expenditures reimbursed by the customer for the three and six months ended June 30, 2009, respectively and $4.2 million and $6.2 million for the three and six months ended June 30, 2008, respectively. Included in International Liftboats revenue is a total of $0.1 million related to amortization of deferred mobilization revenue for the six months ended June 30, 2009. There was no such revenue in the three months ended June 30, 2009, nor the three and six months ended June 30, 2008 for International Liftboats.

(3)		Average operating expense per rig or liftboat per day is defined as operating expenses, excluding depreciation and amortization, incurred by our rigs or liftboats, as applicable, in the period divided by the total number of available days in the period. We use available days to calculate average operating expense per rig or liftboat per day rather than operating days, which are used to calculate average revenue per rig or liftboat per day, because we incur operating expenses on our rigs and liftboats even when they are not under contract and earning a dayrate. In addition, the operating expenses we incur on our rigs and liftboats per day when they are not under contract are typically lower than the per-day expenses we incur when they are under contract. Included in International Offshore operating expense is a total of $0.7 million and $1.4 million related to amortization of deferred mobilization expenses for the three and six months ended June 30, 2009, respectively and $2.1 million and $3.0 million for the three and six months ended June 30, 2008, respectively.

For the Three Months Ended June 30, 2009 and 2008

Revenues

Consolidated. Total revenues for the three-month period ended June 30, 2009 (the “Current Quarter”) were $183.7 million compared with $270.1 million for the three-month period ended June 30, 2008 (the “Comparable Quarter”), a decrease of $86.4 million, or 32.0%. This decrease is further described below. Total revenues included $4.5 million in reimbursements from our customers for expenses paid by us in the Current Quarter compared with $3.9 million in the Comparable Quarter.

Domestic Offshore. Revenues for our Domestic Offshore segment were $37.0 million for the Current Quarter compared with $97.4 million for the Comparable Quarter, a decrease of $60.5 million, or 62.1%. This decrease resulted primarily from decreased operating days, 706 days during the Current Quarter as compared to 1,612 days during the Comparable Quarter, due to our cold stacking of rigs, and a 13.4% decrease in average dayrates during the Current Quarter as compared to the Comparable Quarter.

International Offshore. Revenues for our International Offshore segment were $101.8 million for the Current Quarter compared with $74.2 million for the Comparable Quarter, an increase of $27.6 million, or 37.2%. Approximately $59 million of this increase was due to increased operating days as a result of the commencement of the Hercules 260 in late April 2008, Hercules 258 in June 2008, Hercules 208 in August 2008, Hercules 261 in December 2008 and Hercules 262 in January 2009. These favorable increases were partially offset by approximately $28 million related to Hercules 185 being in the shipyard for an upgrade, Hercules 156 in warm stack and Hercules 110 in cold stack during the Current Quarter. Average revenue per rig per day increased to $129,133 in the Current Quarter from $115,556 in the Comparable Quarter due to higher average dayrates earned on the Hercules 260, including the associated revenue from the provision of marine services, and higher than the historical average dayrates earned on the Hercules 208, Hercules 261 and Hercules 262 in the Current Quarter.

Inland. The Inland segment had no operating days during the Current Quarter compared to 1,017 operating days in the Comparable Quarter. Available days declined to 303 from 1,486, or 79.6%, during the Current Quarter as compared to the Comparable Quarter, respectively, due to our cold stacking plan.

Domestic Liftboats. Revenues from our Domestic Liftboats segment were $18.9 million for the Current Quarter compared with $22.3 million in the Comparable Quarter, a decrease of $3.4 million, or 15.2%. This decrease resulted primarily from a decrease in the average revenue per vessel per day to $7,727 in the Current Quarter compared with $9,030 in the Comparable Quarter, or a per day decrease of $1,303. The decrease in average revenue per vessel per day was due to lower dayrates as well as mix of vessel class. Operating days and average utilization for the Current Quarter of 2,444 and 63.6%, respectively, were essentially flat as compared to the Comparable Quarter. Revenues for our Domestic Liftboats segment included $0.9 million and $1.3 million in reimbursements from our customers for expenses paid by us in the Current Quarter and the Comparable Quarter, respectively.

International Liftboats. Revenues for our International Liftboats segment were $20.7 million for the Current Quarter compared with $20.3 million in the Comparable Quarter, an increase of $0.4 million, or 2.2%. This increase resulted from higher average dayrates, which contributed $6.9 million of the increase, significantly offset by fewer operating days, which contributed a $6.5 million decrease. Operating days decreased to 1,005 days in the Current Quarter from 1,331 days in the Comparable Quarter. Average revenue per liftboat per day was $20,644 in the Current Quarter compared with $15,255 in the Comparable Quarter, with average utilization of 58.1% in the Current Quarter compared with 83.7% in the Comparable Quarter. Approximately $4,008 of the increase in average revenue per vessel per day was due to mix of vessel class and approximately $1,381 was due to higher dayrates. Revenues for our International Liftboats segment included $1.9 million and $1.6 million in reimbursements from our customers for expenses paid by us in the Current Quarter and Comparable Quarter, respectively.

Delta Towing. Revenues for our Delta Towing segment were $5.2 million for the Current Quarter compared with $15.6 million in the Comparable Quarter, a decrease of $10.4 million, or 66.5%, due to decreased activity in both offshore and in the transition zone.

Operating Expenses

Consolidated. Total operating expenses for the Current Quarter were $116.1 million compared with $158.0 million in the Comparable Quarter, a decrease of $41.9 million, or 26.5%. This decrease is further described below.

Domestic Offshore. Operating expenses for our Domestic Offshore segment were $40.7 million in the Current Quarter compared with $56.3 million in the Comparable Quarter, a decrease of $15.5 million, or 27.6%. The decrease was driven primarily by 888 fewer available days during the Current Quarter as compared to the Comparable Quarter, or a 43.9% decline, due to our cold stacking of rigs. As a part of our cold stacking plan, we reduced our labor force. Our cold stacking plan and lower activity on marketed rigs resulted in a reduction to our labor, repairs and maintenance and catering expenses. Average operating expenses per rig per day were $35,868 in the Current Quarter compared with $27,804 in the Comparable Quarter due in part to shore based support and cold-stacked rig costs being allocated over fewer available days.

International Offshore. Operating expenses for our International Offshore segment were $39.1 million in the Current Quarter compared with $37.3 million in the Comparable Quarter, an increase of $1.8 million, or 4.9%. Available days increased to 910 in the Current Quarter from 732 in the Comparable Quarter. Average operating expenses per rig per day were $42,998 in the Current Quarter compared with $50,967 in the Comparable Quarter. This average per day decrease related primarily to the warm stacking of Hercules 156 and the initial start-up costs incurred during the Comparable Quarter relating to our India operations.

Inland. Operating expenses for our Inland segment were $8.9 million in the Current Quarter compared with $31.3 million in the Comparable Quarter, a decrease of $22.4 million, or 71.7%. All of our barges were either cold stacked, warm stacked or ready stacked during the Current Quarter which coupled with the reduction in our labor force significantly reduced all of the segment’s variable operating costs. Average operating expenses per rig per day were $29,231 in the Current Quarter compared with $21,067 in the Comparable Quarter. The increase in cost per day was driven primarily by costs associated with shore based support and cold stacked rigs being allocated over fewer available days.

Domestic Liftboats. Operating expenses for our Domestic Liftboats segment were $12.4 million in the Current Quarter compared with $13.4 million in the Comparable Quarter, a decrease of $1.0 million, or 7.6%. Available days declined slightly to 3,842 in the Current Quarter from 3,871 in the Comparable Quarter due to the transfer of one liftboat to our International Liftboats segment in the second quarter of 2008, partially offset by additional cold stacking days in the Comparable Quarter. Average operating expenses per vessel per day were $3,232 in the Current Quarter compared with $3,474 in the Comparable Quarter. This decrease is primarily due to lower repairs and maintenance expense and costs related to fuel and oil.

International Liftboats. Operating expenses for our International Liftboats segment were $9.1 million for the Current Quarter compared with $9.9 million in the Comparable Quarter, a decrease of $0.8 million, or 7.9%. Available days increased to 1,729 in the Current Quarter from 1,590 in the Comparable Quarter due to the transfer of one liftboat to our International Liftboats segment in the second quarter of 2008 combined with a 200 class vessel placed in service late in the second quarter of 2008. Average operating expenses per liftboat per day were $5,271 in the Current Quarter compared with $6,224 in the Comparable Quarter due primarily to lower insurance costs in the Current Quarter and costs accrued for a payment to a former owner in the Comparable Quarter.

Delta Towing. Operating expenses for our Delta Towing segment were $5.8 million for the Current Quarter compared with $9.8 million in the Comparable Quarter, a decrease of $3.9 million, or 40.4%. Due to the decline in activity both offshore and the transition zone, we have cold stacked certain assets in our fleet which resulted in lower labor, repairs and maintenance and fuel and oil expenses during the Current Quarter.

Impairment of Property and Equipment

In June 2009, we entered into an agreement to sell Hercules 110, which is currently cold stacked in Trinidad, and incurred a $26.9 million impairment charge to write-down the rig to its fair value less costs to sell. There was no such charge incurred during the Comparable Quarter.

Depreciation and Amortization

Depreciation and amortization expense in the Current Quarter was $51.1 million compared with $47.3 million in the Comparable Quarter, an increase of $3.8 million, or 8.1%. This increase resulted primarily from additional depreciation related to the commencement of the Hercules 260 in late April 2008, Hercules 350 in June 2008, Hercules 208 in August 2008, Hercules 261 in December 2008 and Hercules 262 in January 2009. These increases are partially offset by reduced depreciation due to the impairment of certain rigs, barges and related equipment in the fourth quarter of 2008 and lower amortization of our international contract values.

General and Administrative Expenses

General and administrative expenses in the Current Quarter were $15.5 million compared with $24.0 million in the Comparable Quarter, a decrease of $8.5 million, or 35.5%. This decrease relates to the cost reduction initiatives implemented in late 2008 and in 2009 in response to the significant decline in activity in several of our business segments. In addition, the Comparable Quarter included $5.5 million in executive severance related costs.

Gain on Early Retirement of Debt

During the Current Quarter, we retired $65.8 million aggregate principal amount of the 3.375% Convertible Senior Notes for cash and equity consideration of approximately $40.1 million, resulting in a gain of $13.7 million, net of an associated write-off of a portion of our unamortized issuance costs.

Other, Net

Other income in the Current Quarter was $3.3 million compared with other income of $0.3 million in the Comparable Quarter, an increase of $3.1 million. This increase is primarily due to foreign currency exchange gains.

Income Tax Benefit (Provision)

Income tax benefit was $11.5 million on a pre-tax loss of $23.3 million during the Current Quarter, compared to a provision of $9.5 million on pre-tax income of $25.9 million for the Comparable Quarter. The effective tax rate changed to a tax benefit of 49.4% in the Current Quarter from a tax provision of 36.7% in the Comparable Quarter. The change in the effective tax rate is due to the jurisdictional mix of earnings (losses).

For the Six Months Ended June 30, 2009 and 2008

Revenues

Consolidated. Total revenues for the six-month period ended June 30, 2009 (the “Current Period”) were $407.2 million compared with $482.6 million for the six-month period ended June 30, 2008 (the “Comparable Period”), a decrease of $75.4 million, or 15.6%. This decrease is further described below. Total revenues included $8.0 million in reimbursements from our customers for expenses paid by us in the Current Period compared with $6.8 million in the Comparable Period.

Domestic Offshore. Revenues for our Domestic Offshore segment were $96.2 million for the Current Period compared with $159.9 million for the Comparable Period, a decrease of $63.7 million, or 39.9%. This decline resulted primarily from decreased operating days due to our cold stacking of rigs, which contributed $69.8 million of the decrease, partially offset by a $6.1 million increase due to higher average dayrates. Average utilization was 62.3% in the Current Period compared with 67.3% in the Comparable Period.

International Offshore. Revenues for our International Offshore segment were $205.2 million for the Current Period compared with $139.5 million for the Comparable Period, an increase of $65.7 million, or 47.1%. Approximately $116 million of this increase was due to increased operating days as a result of the commencement of the Hercules 260 in late April 2008, Hercules 258 in June 2008, Hercules 208 in August 2008, Hercules 261 in December 2008 and Hercules 262 in January 2009. These favorable increases were partially offset by approximately $46 million related to the Hercules 185 being in the shipyard for an upgrade, Hercules 156 in warm stack and the Hercules 110 in cold stack during the Current Period. Average revenue per rig per day increased to $129,633 in the Current Period from $107,662 in the Comparable Period due to higher average dayrates earned on the Hercules 260 and Hercules 258, including the associated revenue from the provision of marine services, and higher average dayrates earned on the Hercules 208, Hercules 261 and Hercules 262 in the Current Period.

Inland. Revenues for our Inland segment were $13.0 million in the Current Period compared with $80.5 million for the Comparable Period, a decrease of $67.5 million, or 83.8%. This decrease resulted from decreased operating days, as average revenue per rig per day was only slightly higher in the Current Period as compared to the Comparable Period. Available days declined 66.2% during the Current Period as compared to the Comparable Period due to our cold stacking plan. Furthermore, average utilization was 29.0% on fewer available days in the Current Period compared with 64.5% in the Comparable Period as demand in the segment declined.

Domestic Liftboats. Revenues for our Domestic Liftboats segment were $41.5 million for the Current Period compared with $38.2 million in the Comparable Period, an increase of $3.3 million, or 8.6%. This increase resulted primarily from increased operating days, which contributed $6.9 million of the increase, partially offset by a $3.6 million decrease due to lower average dayrates. Operating days increased to 4,883 in the Current Period from 4,066 in the Comparable Period. Average utilization also increased to 63.3% in the Current Period from 50.5% in the Comparable Period. Average revenue per vessel per day was $8,498 in the Current Period compared with $9,398 in the Comparable Period, a decrease of $900 per day. The decrease in average revenue per vessel per day was due primarily to lower dayrates with a slight decrease due to mix of vessel class. Revenues for our Domestic Liftboats segment included $2.0 million in reimbursements from our customers for expenses paid by us in both the Current Period and the Comparable Period.

International Liftboats. Revenues for our International Liftboats segment were $39.4 million for the Current Period compared with $38.6 million in the Comparable Period, an increase of $0.8 million, or 2.1%. This increase resulted from higher average dayrates, which contributed $13.3 million of the increase, significantly offset by fewer operating days, which contributed a $12.5 million decrease. Operating days decreased to 1,923 days in the Current Period from 2,548 days in the Comparable Period. Average revenue per liftboat per day was $20,483 in the Current Period compared with $15,148 in the Comparable Period, with average utilization of 55.9% in the Current Period compared with 81.2% in the Comparable Period. Approximately $3,763 of the increase in average revenue per vessel per day was due to mix of vessel class and approximately $1,572 was due to higher dayrates. Revenues for our International Liftboats segment included $3.2 million and $2.8 million in reimbursements from our customers for expenses paid by us in the Current Period and Comparable Period, respectively.

Delta Towing. Revenues for our Delta Towing segment were $11.9 million for the Current Period compared with $25.8 million in the Comparable Period, a decrease of $13.9 million, or 53.8%, due to decreased activity in both offshore and in the transition zone.

Operating Expenses

Consolidated. Total operating expenses for the Current Period were $265.3 million compared with $289.2 million in the Comparable Period, a decrease of $23.8 million, or 8.2%. This decrease is further described below.

Domestic Offshore. Operating expenses for our Domestic Offshore segment were $95.2 million in the Current Period compared

with $104.0 million in the Comparable Period, a decrease of $8.9 million, or 8.5%. The decrease was driven primarily by lower labor, catering and fuel and oil expenses, partially offset by higher workers’ compensation and repairs and maintenance expenses, including hurricane related repairs. Available days decreased to 2,520 in the Current Period from 4,026 in the Comparable Period due to our cold stacking of rigs. Average operating expenses per rig per day were $37,762 in the Current Period compared with $25,844 in the Comparable Period due in part to shore based support and cold stacked rig costs being allocated over fewer available days.

International Offshore. Operating expenses for our International Offshore segment were $83.3 million in the Current Period compared with $60.1 million in the Comparable Period, an increase of $23.2 million, or 38.6%. Available days increased to 1,757 in the Current Period from 1,441 in the Comparable Period. Average operating expenses per rig per day were $47,393 in the Current Period compared with $41,707 in the Comparable Period. This increase related primarily to the provisions for marine services included in our Hercules 258 and Hercules 260 contracts which are recovered through an incremental dayrate and the higher operating costs incurred in Saudi Arabia.

Inland. Operating expenses for our Inland segment were $29.1 million in the Current Period compared with $63.2 million in the Comparable Period, a decrease of $34.1 million, or 53.9%. By the end of the Current Period, all of our barges were either cold stacked, warm stacked or ready stacked which significantly reduced all of the segment’s variable operating costs. Average operating expenses per rig per day were $28,383 in the Current Period compared with $20,848 in the Comparable Period. The increase in cost per day was driven primarily by costs associated with shore based support and cold stacked rigs being allocated over fewer available days.

Domestic Liftboats. Operating expenses for our Domestic Liftboats segment were $26.6 million in the Current Period compared with $27.3 million in the Comparable Period, a decrease of $0.8 million, or 2.9% due primarily to lower fuel and oil and insurance costs. Available days decreased to 7,712 in the Current Period from 8,057 in the Comparable Period due to the transfer of two liftboats to our International Liftboats segment in the second quarter of 2008, as well as the cold stacking of two liftboats that were available in the Comparable Period. Average operating expenses per vessel per day remained static at approximately $3,400 per day during the Current and Comparable Periods.

International Liftboats. Operating expenses of $17.2 million for our International Liftboats segment were essentially flat during the Current Period as compared with Comparable Period. Average operating expenses per liftboat per day were $5,007 in the Current Period compared with $5,456 in the Comparable Period due to lower insurance expense and costs accrued for a payment to a former owner in the Comparable Period.

Delta Towing. Operating expenses for our Delta Towing segment were $14.0 million for the Current Period compared with $17.3 million in the Comparable Period, a decrease of $3.3 million, or 19.1%. Due to the decline in activity in both offshore and the transition zone, we have continued to cold stack certain assets in our fleet which resulted in lower labor, repairs and maintenance and fuel and oil expenses during the Current Period.

Impairment of Property and Equipment

Depreciation and Amortization

Depreciation and amortization expense in the Current Period was $99.9 million compared with $90.9 million in the Comparable Period, an increase of $9.0 million, or 9.9%. This increase resulted primarily from additional depreciation related to the commencement of the Hercules 260 in late April 2008, Hercules 350 in June 2008, Hercules 208 in August 2008, Hercules 261 in December 2008 and Hercules 262 in January 2009. These increases are partially offset by reduced depreciation due to the impairment of certain rigs, barges and related equipment in the fourth quarter of 2008 and lower amortization of our international contract values.

General and Administrative Expenses

General and administrative expenses in the Current Period were $31.7 million compared with $40.3 million in the Comparable Period, a decrease of $8.6 million, or 21.3%. This decrease relates to the cost reduction initiatives implemented in late 2008 and in 2009 in response to the significant decline in activity in several of our business segments. In addition, the Comparable Period included $5.5 million in executive severance related costs.

Gain on Early Retirement of Debt

During the Current Period, we retired $65.8 million aggregate principal amount of the 3.375% Convertible Senior Notes for cash

and equity consideration of approximately $40.1 million, resulting in a gain of $13.7 million, net of an associated write-off of a portion of our unamortized issuance costs.

Other, Net

Other income in the Current Period was $2.7 million compared with other income of $2.3 million in the Comparable Period, an increase of $0.4 million. This increase is primarily due to foreign currency exchange gains.

Income Tax Benefit (Provision)

Income tax benefit was $14.3 million on pre-tax loss of $30.6 million during the Current Period, compared to a provision of $12.1 million on pre-tax income of $33.3 million for the Comparable Period. The effective tax rate changed to a tax benefit of 46.8% in the Current Period from a tax provision of 36.2% in the Comparable Period. The change in the effective tax rate is due to the jurisdictional mix of earnings (losses).

CRITICAL ACCOUNTING POLICIES

Critical accounting policies are those that are important to our results of operations, financial condition and cash flows and require management’s most difficult, subjective or complex judgments. Different amounts would be reported under alternative assumptions. We have evaluated the accounting policies used in the preparation of the unaudited consolidated financial statements and related notes appearing elsewhere in this quarterly report. We apply those accounting policies that we believe best reflect the underlying business and economic events, consistent with accounting principles generally accepted in the United States. We believe that our policies are generally consistent with those used by other companies in our industry.

We periodically update the estimates used in the preparation of the financial statements based on our latest assessment of the current and projected business and general economic environment. During recent months, there has been substantial volatility and a decline in commodity prices. In addition, there has been uncertainty in the capital markets and available financing is limited. If these conditions persist for a prolonged length of time, our business and the businesses of our customers could be adversely impacted. This in turn could result in changes to estimates used in preparing our financial statements, including the assessment of certain of our assets for impairment.

We believe that our more critical accounting policies include those related to property and equipment, revenue recognition, income tax, allowance for doubtful accounts, deferred charges, stock-based compensation, cash and cash equivalents and marketable securities and intangible assets. Inherent in such policies are certain key assumptions and estimates. For additional information regarding our critical accounting policies, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies” in Item 7 of our annual report on Form 10-K for the year ended December 31, 2008.

OUTLOOK

Offshore

In general, demand for our drilling rigs is a function of our customers’ capital spending plans, which are largely driven by current commodity prices and their expectations of future commodity prices. Demand in the U.S. Gulf of Mexico is particularly driven by natural gas prices, with demand internationally typically driven by oil prices.

As of July 21, 2009, the spot price for Henry Hub natural gas was $3.48 per MMBtu, a significant decline from the high of $13.31 per MMBtu in July 2008. The twelve month strip, or the average of the next twelve month’s futures contract, was $5.10 per MMBtu on July 21, 2009, down from the high of $13.34 in July 2008. A myriad of factors have combined to cause the current depressed price of natural gas. The current worldwide economic downturn has reduced economic activity, which in turn has reduced energy consumption, creating a sharp decrease in the demand for natural gas. On the supply side, increases in onshore production in the U.S., driven by a significant increase in onshore drilling activity through mid-2008 and a large number of discoveries, have also put downward pressure on natural gas prices. Growing deepwater production and potential increased deliveries of liquefied natural gas are additional factors which have weighed on natural gas prices. These factors, together with decline rates, weather and industrial demand will likely remain key drivers in the natural gas market for the foreseeable future.

Oil prices declined significantly from mid-2008 to early 2009, before recovering somewhat the last several months. Since June 30, 2008, the price of West Texas intermediate crude (“WTI”) has declined from $140.00 to a multi-year low of $31.41 in December 2008 before partially rebounding to slightly above $70.00 in mid-June. The price of WTI has subsequently fallen to $64.72 as of July 21, 2009. The significant decline since mid-2008 was due primarily to the anticipated effects of global economic weakness, increase in oil inventories relative to consumption and a strengthening in the U.S. dollar.

Many of our customers have significantly reduced their capital spending plans relative to 2008 spending. While the substantial

recent declines in both natural gas and oil prices are a primary factor, the weak global economic outlook, shut-in production related to damage sustained during Hurricanes Gustav and Ike, and a more difficult environment to raise outside capital have all contributed to this curtailed level of capital spending. This is particularly applicable to our U.S. Gulf of Mexico focused customers whose drilling programs are shorter-term in nature and can be adjusted more quickly in response to commodity price fluctuations. Many of these U.S. Gulf of Mexico focused customers are smaller and employ more financial leverage and may face difficulty in raising outside funding for drilling programs. While international spending programs are much longer-term in nature, and the customers tend to have greater financial resources, international capital spending is also expected to decline in 2009, following nine years of growth, but to a lesser degree.

Global demand for jackup rigs has increased significantly over the last several years with international regions such as the Middle East, India and Mexico being particularly strong. Demand for jackups worldwide, excluding the U.S. Gulf of Mexico, increased from 200 in 2001 to 312 in July 2009.

Strong global demand for jackups over the past few years has encouraged newbuilds. According to ODS-Petrodata, as of July 21, 2009, approximately 68 new jackup rigs have been delivered since January 1, 2006. Further, 60 new jackup rigs remain either under construction or on order for delivery through 2011. Given the recent financial crisis and the weakened outlook, a number of orders have been cancelled, and we anticipate that several of these remaining orders will be delayed or cancelled. However, we expect the majority of these rigs will be delivered and will compete directly with our fleet. As a result of generally higher dayrates, longer duration contracts and lower insurance costs, which are prevalent internationally, among other factors, we believe the vast majority of the newbuild jackup rigs will target international regions rather than the U.S. Gulf of Mexico. Our ability to secure new contracts for our international fleet or to expand our international drilling operations may be limited by the increased supply of newbuild jackup rigs.

In addition to spurring newbuilds, this international demand has drawn available rigs from the U.S. Gulf of Mexico. As a result, the supply of jackup rigs in the U.S. Gulf of Mexico has declined considerably over the last several years from a high of 157 jackups in 2001 to only 71 currently.

While the overall current supply of jackup rigs in the U.S. Gulf of Mexico is 71, several of these rigs are either in the shipyard or cold-stacked, and the marketed supply is approximately 43 as of July 21, 2009. While the number of jackups located in the U.S. Gulf of Mexico has declined significantly over the last several years, current demand of approximately 17 jackups as of July 21, 2009 is also considerably lower than three years ago when 94 jackups were operating in July 2006. A combination of factors has resulted in this decline in the number of rigs from the levels experienced over the previous several years, including declining target reservoir sizes, increasing finding, development and lifting costs and lower current natural gas prices.

A further reduction in the number of rigs operating in the U.S. Gulf of Mexico is possible; however, the pace of migration of jackup rigs from the region to international regions will likely slow as much of the expected growth in international demand will be met by the aforementioned newbuild deliveries. Further, a modest reduction in the supply in the U.S. Gulf of Mexico will likely not be sufficient to offset the impact of weak demand resulting from our customers’ curtailed capital spending in 2009.

The global financial and credit crisis has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. The shortage of liquidity and credit combined with recent substantial losses in worldwide equity markets has led to an extended global recession. A further slowdown in economic activity caused by a recession would likely reduce demand for energy and result in lower oil and natural gas prices. Such a slowdown in economic activity would likely result in a corresponding decline in the demand for our jackup rigs and other services, which could have a material adverse effect on our revenue, profitability and liquidity.

While the outlook for drilling activity in 2009 has certainly been hampered by the aforementioned weaker commodity prices and the global credit crisis, a number of factors give us optimism for the longer term. First, with steep initial decline rates in many North American natural gas basins and a substantial reduction in the rig count, the recent strong natural gas market production growth could quickly slow or even reverse. With respect to international markets, which are typically driven by crude oil prices, the lack of any significant oil production growth over the last five years, despite a more than doubling of international exploration and production capital spending over this period, leads us to believe that production would decline in response to a decrease in exploration and production spending.

Furthermore, the offshore drilling market remains highly competitive and cyclical, and it has historically been difficult to forecast future market conditions. While future commodity price expectations have typically been a key driver for demand for drilling rigs, other factors also affect our customers’ drilling programs, including the quality of drilling prospects, exploration success, relative production costs, availability of insurance, and political and regulatory environments. Additionally, the offshore drilling business has historically been cyclical, marked by periods of low demand, excess rig supply and low dayrates, followed by periods of high demand, short rig supply and increasing dayrates. These cycles have been volatile and are subject to rapid change.

Inland

The activity for inland barge drilling in the U.S. generally follows the same drivers as drilling in the U.S. Gulf of Mexico with activity following operators’ expectations of prices for natural gas and, to a lesser degree, crude oil. Barge rig drilling activity

historically lags activity in the U.S. Gulf of Mexico due to a number of factors such as the lengthy permitting process that operators must go through prior to drilling a well in Louisiana, where the majority of our inland drilling takes place, and the predominance of smaller independent operators active in inland waters.

Inland barge drilling activity has slowed dramatically over the past year and dayrates have softened as a result of the number of the key operators that have curtailed or ceased their activity in the inland market for various reasons, including lack of funding, lack of drilling success and re-allocation of capital to onshore basins. As of July 21, 2009, two of our seventeen inland barges had contracts for work. While we may have some increased activity for our inland barges based on recent bidding activity, we expect activity levels to remain very low versus historic norms for the duration of 2009.

Liftboats

Demand for liftboats is typically a function of our customers’ demand for platform inspection and maintenance, well maintenance, offshore construction, well plugging and abandonment, and other related activities. Although activity levels for liftboats are not as closely correlated to movement in commodity prices as for offshore drilling rigs, commodity prices are still a key driver of the demand for liftboats. Despite the production maintenance related nature of the majority of the work, some of the work may be deferred from time to time.

Following the active 2005 hurricane season, which caused tremendous damage to the infrastructure in the U.S. Gulf of Mexico, liftboat utilization and dayrates in the region were stronger than historical levels for approximately two years. As activity levels declined to more typical levels and supply increased as approximately 18 new liftboats were delivered for work in the U.S. Gulf of Mexico since January 2007, dayrates softened.

Activity levels increased again in late 2008 as customers addressed damage caused by the hurricanes Gustav and Ike; however, the damage was not as extensive as from the 2005 hurricane season, so the higher activity levels continued only into the first quarter of 2009. Dayrates once again increased, responding to the tightened supply and demand balance but have already declined again as the preponderance of the higher priority repair work has been completed.

As of July 2, 2009, we believe that there were another 9 liftboats under construction or on order in the U.S., with anticipated delivery dates through 2010. Once delivered, these liftboats may further impact the demand and utilization of our domestic liftboat fleet.

Our customers’ growth in international capital spending for the last several years, coupled with an aging infrastructure and significant increases in the cost of alternatives for servicing this infrastructure, has generally resulted in strong demand for our liftboats in West Africa. As international markets mature and the focus shifts from exploration to development, in locations such as West Africa, the Middle East and Southeast Asia, we would expect to experience strong demand growth for liftboats. However, a reduction in exploration and production companies’ capital spending in international markets in 2009 will likely temporarily slow or reverse this trend. Over the longer term, we anticipate that there may be contract opportunities in international locations for liftboats currently working in the U.S. Gulf of Mexico and for newly constructed liftboats. In 2008, we mobilized two of our liftboats to the Middle East from the U.S. Gulf of Mexico. While we believe that international demand for liftboats will continue to increase over the longer term, the political instability in certain regions may negatively impact our customers’ capital spending plans.

LIQUIDITY AND CAPITAL RESOURCES

Recent Developments

On July 27, 2009, we amended the credit agreement (the “Credit Agreement”) governing our $1,132.0 million credit facility with a syndicate of financial institutions (the “Credit Amendment”), consisting of an $882.0 million term loan and a $250.0 million revolving credit facility. A fee of 0.50% was paid to lenders consenting to the Credit Amendment, based on their total commitment, which approximated $4.8 million.

The Credit Amendment reduced the revolving credit facility by $75.0 million to $175.0 million. The commitment fee on the revolving credit facility increased from 0.375% to 1.00%. Additionally, the Credit Amendment establishes a minimum London Interbank Offered Rate (“LIBOR”) rate of 2.00%, and 3.00%, with respect to our Alternative Base Rate (“ABR”) Loans and increases the margin applicable to Eurodollar Loans and ABR Loans, subject to a grid based on the aggregate principal amount of the Term Loans outstanding as follows ($ in millions):


Principal Amount Outstanding		Margin Applicable to:
Less than or	Greater	Eurodollar	ABR
equal to:	than:	Loans	Loans
$882.0	$684.25	6.50%	5.50%
684.25	484.25	5.00%	4.00%
484.25	—	4.00%	3.00%

The Credit Amendment also modifies certain provisions of the Credit Agreement to, among other things:

	•		Eliminate the requirement that we comply with the total leverage ratio financial covenant for the nine month period commencing October 1, 2009 and ending on June 30, 2010 and amend the maximum total leverage ratio that we must comply with following the expiration of the nine month period to be more favorable to us;

	•		Require us to maintain a minimum level of liquidity, measured as the amount of unrestricted cash and cash equivalents we have on hand and availability under the revolving credit facility, of (i) $100.0 million for the period between October 1, 2009 through December 31, 2010, (ii) $75.0 million during calendar year 2011 and (iii) $50.0 million thereafter;

	•		Revise the fixed charge coverage ratio definition and reduce the minimum fixed charge coverage ratio that we must maintain in a manner that is more favorable to us;

	•		Require mandatory prepayments of debt outstanding under the Credit Agreement with 100% of excess cash flow for the fiscal year ending December 31, 2009 and 50% of excess cash flow thereafter and with proceeds from:

	§		unsecured debt issuances, with the exception of refinancing, through June 30, 2010;

	§		secured debt issuances; and

	§		sales of assets in excess of $25 million annually; and

	§		unless we have achieved a specified leverage ratio, 50% of proceeds from equity issuances, excluding those for permitted acquisitions or to meet the minimum liquidity requirements.

In June, 2009, we entered into an agreement to sell our Hercules 100 and Hercules 110 jackup drilling rigs for a total purchase price of $12.0 million. The Hercules 100 is classified as “retired” and has been stacked in the United States since April 1999, and the Hercules 110 has been cold-stacked in Trinidad since August 2008. The closing of the sale of the Hercules 100 and Hercules 110 is expected to occur on or before August 15, 2009 and is subject to customary closing conditions.

Sources and Uses of Cash

Sources and uses of cash for the six-month period ended June 30, 2009 are as follows (in millions):


Net Cash Provided by Operating Activities	$	88.3
Net Cash Provided by (Used in) Investing Activities:
Additions of Property and Equipment		(62.0	)
Deferred Drydocking Expenditures		(9.7	)
Insurance Proceeds Received		8.7
Proceeds from Sale of Assets, Net		4.7

Total		(58.3	)
Net Cash Provided by (Used in) Financing Activities:
Debt Repayments, Net		(4.7	)
Redemption of 3.375% Convertible Senior Notes		(6.1	)
Excess Tax Benefit from Stock-Based Arrangements		4.2

Total		(6.6	)

Net Increase in Cash and Cash Equivalents	$	23.4

Sources of Liquidity and Financing Arrangements

Our liquidity is comprised of cash on hand, cash from operations and availability under our revolving credit facility. We also maintain a shelf registration statement covering the future issuance from time to time of various types of securities, including debt and equity securities. If we issue any debt securities off the shelf or otherwise incur debt, we would generally be required to allocate the proceeds of such debt to repay or refinance existing debt. We currently believe we will have adequate liquidity to fund our operations for the foreseeable future. However, to the extent we do not generate sufficient cash from operations we may need to raise additional funds through public or private debt or equity offerings to fund operations. Furthermore, we may need to raise additional funds through public or private debt or equity offerings or asset sales to meet certain covenants under the Credit Agreement, to refinance existing debt or for general corporate purposes.

Our Credit Agreement requires that we meet certain financial ratios and tests, which we currently meet. Our failure to comply with such covenants would result in an event of default under the Credit Agreement. An event of default could prevent us from borrowing under the revolving credit facility, which would in turn have a material adverse effect on our available liquidity. Additionally, an event of default could result in us having to immediately repay all amounts outstanding under the term loan facility and the revolving credit facility and in the foreclosure of liens on our assets.

Cash Requirements and Contractual Obligations

Debt

Our current debt structure is used to fund our business operations.

The credit facility governed by the Credit Agreement, consists of an $882.0 million term loan which matures on July 11, 2013 and a $175.0 million revolving credit facility which matures on July 11, 2012. The availability under the $175.0 million revolving credit facility must be used for working capital, capital expenditures and other general corporate purposes and cannot be used to prepay our term loan. As of July 27, 2009, no amounts were outstanding and $14.0 million in stand-by letters of credit had been issued under the revolving credit facility, therefore the remaining availability under this revolving credit facility was $161.0 million. The revolving credit facility requires interest-only payments on a quarterly basis until the maturity date.

As of June 30, 2009, $884.3 million was outstanding on the term loan facility and the interest rate was 2.96%. The annualized effective interest rate was 5.09% for the six months ended June 30, 2009 after giving consideration to revolver fees and derivative activity. The interest rate on the term loan facility increased to 8.50% upon effectiveness of the Credit Amendment on July 27, 2009.

Other covenants contained in the Credit Agreement restrict, among other things, asset dispositions, mergers and acquisitions, dividends, stock repurchases and redemptions, other restricted payments, debt issuances, liens, investments, convertible notes repurchases and affiliate transactions.

In May 2008 and July 2007, we entered into derivative instruments with the purpose of hedging future interest payments on our term loan facility. We entered into a floating-to-fixed interest rate swap with varying notional amounts beginning with $100.0 million with a settlement date of October 1, 2008 and ending with $75.0 million with a settlement date of December 31, 2009. We receive an interest rate of three-month LIBOR and pay a fixed coupon of 2.980% over six quarters. The terms and settlement dates of the swap match those of the term loan. We also entered into a zero cost LIBOR collar on $300.0 million of term loan principal with a final settlement date of October 1, 2010 with a ceiling of 5.75% and a floor of 4.99%. The counterparty is obligated to pay us in any quarter that actual LIBOR resets above 5.75% and we pay the counterparty in any quarter that actual LIBOR resets below 4.99%. The terms and settlement dates of the collar match those of the term loan. The change in the fair value of our hedging instruments resulted in a decrease in derivative liabilities of $2.4 million during the six months ended June 30, 2009. We had net unrealized gains on hedge transactions of $2.0 million, net of tax of $1.1 million, and $1.6 million, net of tax of $0.9 million for the three and six months ended June 30, 2009, respectively and $5.4 million, net of tax of $2.9 million for the three months ended June 30, 2008. We had unrealized losses on hedge transactions of $1.7 million, net of tax of $0.9 million for the six months ended June 30, 2008. We did not recognize a gain or loss due to hedge ineffectiveness in the Consolidated Statements of Operations for the three and six months ended June 30, 2009 and for the three and six months ended June 30, 2008 related to these hedging instruments. In addition, our interest expense was increased by $4.0 million and $8.4 million during the three and six months ended June 30, 2009, respectively and $3.7 million and $4.3 million during the three and six months ended June 30, 2008, respectively, as a result of our interest rate derivative instruments.

On June 3, 2008, we completed an offering of $250.0 million convertible senior notes at a coupon rate of 3.375% (“3.375% Convertible Senior Notes”) with a maturity in June 2038. As of June 30, 2009, $95.9 million notional amount of the $250.0 million 3.375% Convertible Senior Notes was outstanding. The carrying amount of the 3.375% Convertible Senior Notes was $81.5 million at June 30, 2009.

The interest on the 3.375% Convertible Senior Notes is payable in cash semi-annually in arrears, on June 1 and December 1 of each year until June 1, 2013, after which the principal will accrete at an annual yield to maturity of 3.375% per year. We will also pay contingent interest during any six-month interest period commencing June 1, 2013, for which the trading price of these notes for a specified period of time equals or exceeds 120% of their accreted principal amount. The notes will be convertible under certain circumstances into shares of our common stock (“Common Stock”) at an initial conversion rate of 19.9695 shares of Common Stock per $1,000 principal amount of notes, which is equal to an initial conversion price of approximately $50.08 per share. Upon conversion of a note, a holder will receive, at our election, shares of Common Stock, cash or a combination of cash and shares of Common Stock. We may redeem the notes at our option beginning June 6, 2013, and holders of the notes will have the right to require us to repurchase the notes on June 1, 2013 and certain dates thereafter or on the occurrence of a fundamental change.

During December 2008 and April 2009, we repurchased $88.2 million and $20.0 million aggregate principal amount of the 3.375% Convertible Senior Notes, respectively, for a cost of $44.8 million and $6.1 million, respectively. In addition, during December 2008 and April 2009 we expensed $2.1 million and $0.4 million of unamortized issuance costs, respectively, in connection with the retirement. In June 2009, we retired $45.8 million aggregate principal amount of its 3.375% Convertible Senior Notes in exchange for the issuance of 7,755,440 Common Shares valued at $4.38 per share and payment of accrued interest, resulting in a gain of $4.4 million. In addition, we expensed $1.0 million of unamortized issuance costs in connection with the retirement. In accordance with FSP 14-1, the settlement consideration was allocated to the extinguishment of the liability component in an amount equal to the fair value of that component immediately prior to extinguishment, with the difference between this allocation and the net carrying amount of the liability component and unamortized debt issuance costs recognized as a gain or loss on debt extinguishment. If there would have been any remaining settlement consideration, it, would have been allocated to the reacquisition of the equity component and recognized as a reduction of Stockholders’ Equity.

The foreign overdraft facility, which was designed to manage local currency liquidity in Venezuela, was terminated in March 2009 and all outstanding amounts were repaid.

The fair value of our 3.375% Convertible Senior Notes and term loan facility is estimated based on quoted prices in active markets. We believe the carrying value of our short-term debt instruments outstanding at December 31, 2008 approximate fair value. The following table provides the carrying value and fair value of our long-term debt instruments:


	June 30, 2009				December 31, 2008
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
			(in millions)
Term Loan Facility, due July 2013	$	884.3	$	769.3	$	886.5	$	571.8
3.375% Convertible Senior Notes due June 2038		81.5		58.1		134.8		77.2
7.375% Senior Notes, due April 2018 (a)		3.5		n/a		3.5		n/a


(a)		The 7.375% Senior Notes have not been traded in recent periods and we believe that the fair value would not materially differ from the carrying value.

In May 2009, we completed the renewal of all of our key insurance policies. Our primary marine package provides for hull and machinery coverage for our rigs and liftboats up to a scheduled value for each asset. The maximum coverage for these assets is $2.2 billion; however, coverage for U.S. Gulf of Mexico named windstorm damage is subject to an annual aggregate limit on liability of $100.0 million. The policies are subject to exclusions, limitations, deductibles, self-insured retention and other conditions. Deductibles for events that are not U.S. Gulf of Mexico named windstorm events are 12.5 % of insured values per occurrence for drilling rigs, and $1.0 million per occurrence for liftboats, regardless of the insured value of the particular vessel. The deductibles for drilling rigs and liftboats in a U.S. Gulf of Mexico named windstorm event are the greater of $25.0 million or the operational deductible for each U.S. Gulf of Mexico named windstorm. We are self-insured for 15% above the deductibles for removal of wreck, sue and labor, collision, protection and indemnity general liability and hull and physical damage policies. The protection and indemnity coverage under the primary marine package has a $5.0 million limit per occurrence with excess liability coverage up to $200.0 million. The primary marine package also provides coverage for cargo and charterer’s legal liability. Vessel pollution is covered under a Water Quality Insurance Syndicate policy with a $3 million deductible proving limits as required. In addition to the marine package, we have separate policies providing coverage for onshore general liability, employer’s liability, auto liability and non-owned aircraft liability, with customary deductibles and coverage as well as a separate primary marine package for our Delta Towing business.

In 2009, in connection with the renewal of certain of our insurance policies, we entered into an agreement to finance a portion of our annual insurance premiums. Approximately $21.4 million was financed through this arrangement, and $19.3 million was outstanding at June 30, 2009. The interest rate on the note is 4.15% and the note is scheduled to mature in March 2010. The amounts financed in connection with the prior year renewal were fully paid as of March 31, 2009.

Capital Expenditures

We expect to spend approximately $40 million on capital expenditures and drydocking, during the remainder of 2009. Planned capital expenditures include refurbishment or upgrades to certain of our rigs, liftboats, and other marine vessels. The timing and amounts we actually spend in connection with our plans to upgrade and refurbish other selected rigs and liftboats are subject to our discretion and will depend on our view of market conditions and our cash flows.

Costs associated with refurbishment or upgrade activities which substantially extend the useful life or operating capabilities of the asset are capitalized. Refurbishment entails replacing or rebuilding the operating equipment. An upgrade entails increasing the operating capabilities of a rig or liftboat. This can be accomplished by a number of means, including adding new or higher specification equipment to the unit, increasing the water depth capabilities or increasing the capacity of the living quarters, or a combination of each.

We are required to inspect and drydock our liftboats on a periodic basis to meet U.S. Coast Guard requirements. The amount of expenditures is impacted by a number of factors, including, among others, our ongoing maintenance expenditures, adverse weather, changes in regulatory requirements and operating conditions. In addition, from time to time we agree to perform modifications to our rigs and liftboats as part of a contract with a customer. When market conditions allow, we attempt to recover these costs as part of the contract cash flow.

From time to time, we may review possible acquisitions of rigs, liftboats or businesses, joint ventures, mergers or other business combinations, and we may have outstanding from time to time bids to acquire certain assets from other companies. We may not, however, be successful in our acquisition efforts. We are generally restricted by our Credit Agreement from making acquisitions for cash consideration, except to the extent the acquisition is funded by an issuance of our stock or cash proceeds from the issuance of stock, or unless we are in compliance with our financial covenants as they existed prior to the Credit Amendment. If we acquire

additional assets, we would expect that the ongoing capital expenditures for our company as a whole would increase in order to maintain our equipment in a competitive condition.

Our ability to fund capital expenditures would be adversely affected if conditions deteriorate in our business or if we experience poor results in our operations.

Off-Balance Sheet Arrangements

Guarantees

Our obligations under the credit facility are secured by liens on a majority of our vessels and substantially all of our other personal property. Substantially all of our domestic subsidiaries, and several of our international subsidiaries, guarantee the obligations under the Credit Agreement and have granted similar liens on several of their vessels and substantially all of their other personal property.

Letters of Credit and Surety Bonds

We execute letters of credit and surety bonds in the normal course of business. While these obligations are not normally called, these obligations could be called by the beneficiaries at any time before the expiration date should we breach certain contractual or payment obligations. As of June 30, 2009, we had $54.1 million of letters of credit and surety bonds outstanding, consisting of $0.1 million in an unsecured outstanding letter of credit, $14.1 million letters of credit outstanding under our revolver and $39.9 million outstanding in surety bonds that guarantee our performance as it relates to our drilling contracts, insurance, tax and other obligations in various jurisdictions. If the beneficiaries called these letters of credit and surety bonds, the called amount would become an on-balance sheet liability, and our available liquidity would be reduced by the amount called.

Contractual Obligations

Our contractual obligations and commitments principally include obligations associated with our outstanding indebtedness, Financial Accounting Standards Board (“FASB”) Interpretation No. 48, Accounting for Uncertainty in Income Taxes (“FIN 48”) liability, surety bonds, letters of credit, future minimum operating lease obligations, purchase commitments and management compensation obligations. Except for the following, during the first six months of 2009, there were no material changes outside the ordinary course of business in the specified contractual obligations:

	•		Retired $65.8 million aggregate principal amount of the 3.375% Convertible Senior Notes;

	•		Settled the $11.1 million insurance note payable outstanding at December 31, 2008; and

	•		Financed $21.4 million related to the renewal of certain of our insurance policies.

For additional information about our contractual obligations as of December 31, 2008, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources— Contractual Obligations” in Item 7 of our annual report on Form 10-K for the year ended December 31, 2008.

Accounting Pronouncements

See Note 13 to our condensed consolidated financial statements included elsewhere in this report.

FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q includes “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 outlook, 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:

	•		our ability to enter into new contracts for our rigs and liftboats and future utilization rates and dayrates for the units;

	•		demand for our rigs and our liftboats and our earnings;

	•		activity levels of our customers and their expectations of future energy prices;

	•		sufficiency and availability of funds for required capital expenditures, working capital and debt service;

	•		success of our cost cutting measures and plans to dispose of certain assets;

	•		expected completion times for our refurbishment and upgrade projects;

	•		our plans to increase international operations;

	•		expected useful lives of our rigs and liftboats;

	•		future capital expenditures and refurbishment, repair and upgrade costs;

	•		our ability to effectively reactivate rigs that we have recently stacked;

	•		liabilities under laws and regulations protecting the environment;

	•		expected outcomes of litigation, claims and disputes and their expected effects on our financial condition and results of operations; and

	•		expectations regarding offshore drilling activity and dayrates, market conditions, demand for our rigs and liftboats, operating revenues, operating and maintenance expense, insurance coverage, insurance expense and deductibles, interest expense, debt levels and other matters with regard to outlook.

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. Forward-looking statements by their nature involve substantial risks and uncertainties that could significantly affect expected results, and actual future results could differ materially from those described in such statements. Although it is not possible to identify all factors, we continue to face many risks and uncertainties. Among the factors that could cause actual future results to differ materially are the risks and uncertainties described under “Risk Factors” in Item 1A of our annual report on Form 10-K for the year ended December 31, 2008 and the following:

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

	•		demand for offshore jackup rigs, inland barge rigs and liftboats;

	•		our ability to enter into and the terms of future contracts;

	•		the worldwide military and political environment, uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or other crises in the Middle East, West Africa and other oil and natural gas producing regions or acts of terrorism or piracy;

	•		the impact of governmental laws and regulations;

	•		the adequacy and costs of sources of credit and liquidity;

	•		uncertainties relating to the level of activity in offshore oil and natural gas exploration, development and production;

	•		competition and market conditions in the contract drilling and liftboat industries;

	•		the availability of skilled personnel in view of recent reductions in our personnel;

	•		labor relations and work stoppages, particularly in the West African and Mexican labor environments;

	•		operating hazards such as hurricanes, severe weather and seas, fires, cratering, blowouts, war, terrorism and cancellation or unavailability of insurance coverage, or insufficient coverage;

	•		the effect of litigation and contingencies; and

	•		our inability to achieve our plans or carry out our strategy.

Many of these factors are beyond our ability to control or predict. Any of these factors, or a combination of these factors, could materially affect our future financial condition or results of operations and the ultimate accuracy of the forward-looking statements. These forward-looking statements are not guarantees of our future performance, and our actual results and future developments may differ materially from those projected in the forward-looking statements. Management cautions against putting undue reliance on forward-looking statements or projecting any future results based on such statements or present or prior earnings levels. In addition, each forward-looking statement speaks only as of the date of the particular statement, and we undertake no obligation to publicly update or revise any forward-looking statements except as required by applicable law.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are currently exposed to market risk from changes in interest rates. From time to time, we may enter into derivative financial instrument transactions to manage or reduce our market risk, but we do not enter into derivative transactions for speculative purposes. A discussion of our market risk exposure in financial instruments follows.

Interest Rate Exposure

We are subject to interest rate risk on our fixed-interest and variable-interest rate borrowings. Variable rate debt, where the interest rate fluctuates periodically, exposes us to short-term changes in market interest rates. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes us to changes in market interest rates reflected in the fair value of the debt and to the risk that we may need to refinance maturing debt with new debt at a higher rate.

As of June 30, 2009, the long-term borrowings that were outstanding subject to fixed interest rate risk consisted of the 7.375% Senior Notes due April 2018 and the 3.375% Convertible Senior Notes due June 2038. The carrying amount of the 7.375% Senior Notes was $3.5 million. The carrying amount of the 3.375% Convertible Senior Notes was $81.5 million.

As of June 30, 2009, the interest rate for the $884.3 million outstanding under the term loan was 2.96%. If the interest rate averaged 1% more for 2009 than the rates as of June 30, 2009, annual interest expense would increase by approximately $8.8 million. This sensitivity analysis assumes there are no changes in our financial structure and excludes the impact of our hedging activities.


	June 30, 2009				December 31, 2008
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
			(in millions)
Term Loan Facility, due July 2013	$	884.3	$	769.3	$	886.5	$	571.8
3.375% Convertible Senior Notes due June 2038		81.5		58.1		134.8		77.2
7.375% Senior Notes, due April 2018 (a)		3.5		n/a		3.5		n/a


(a)		The 7.375% Senior Notes have not been traded in recent periods and we believe that the fair value would not materially differ from the carrying value.

Interest Rate Swaps and Derivatives

We manage our debt portfolio to achieve an overall desired position of fixed and floating rates and may employ hedge transactions such as interest rate swaps and zero cost LIBOR collars as tools to achieve that goal. The major risks from interest rate derivatives include changes in the interest rates affecting the fair value of such instruments, potential increases in interest expense due to market decreases in floating interest rates and the creditworthiness of the counterparties in such transactions. The counterparties to our interest rate swaps and zero cost LIBOR collar are creditworthy multinational commercial banks. We believe that the risk of counterparty nonperformance is not currently material, but counterparty risk has recently increased throughout the financial system. Our interest expense was increased by $4.0 million and $8.4 million for the three and six months ended June 30, 2009, respectively and $3.7 million and $4.3 million for the three and six months ended June 30, 2008, respectively, as a result of our interest rate derivative transactions. (See the information set forth under the caption “Debt” in Part 1, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations- Liquidity and Capital Resources.)

In connection with the credit facility, in July 2007, we entered into hedge transactions with the purpose of fixing the interest rate on decreasing notional amounts beginning with $400.0 million with a settlement date of December 31, 2007 and ending with $50.0 million which was settled on April 1, 2009. We also entered into a zero cost LIBOR collar on $300.0 million of term loan principal with a final settlement date of October 1, 2010 with a ceiling of 5.75% and a floor of 4.99%.

In addition, as it relates to our credit facility, in May 2008 we entered into a floating to fixed interest rate swap with the purpose of fixing the interest rate on varying notional amounts beginning with $100.0 million with a settlement date of October 1, 2008 and ending with $75.0 million with a settlement date of December 31, 2009. The table below provides the schedule of notional amounts related to the interest rate swap (in thousands):


July 1, 2009-September 30, 2009	$	175,000
October 1, 2009-December 30, 2009		75,000

ITEM 4. CONTROLS AND PROCEDURES

We carried out an evaluation, under the supervision and with the participation of our management, including John T. Rynd, our Chief Executive Officer and President, and Lisa W. Rodriguez, 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, Mr. Rynd and Ms. Rodriguez, acting in their capacities as our principal executive officer and our principal financial officer, concluded that, as of June 30, 2009, our disclosure controls and procedures were effective, in all material respects, 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 most recent fiscal quarter 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 under the caption “Legal Proceedings” in Note 12 of the Notes to Unaudited Consolidated Financial Statements in Item 1 of Part 1 of this report is incorporated by reference in response to this item.

ITEM 1A. RISK FACTORS

Except for the additional and updated disclosures set forth below, for additional information about our risk factors, see Item 1A of our annual report on Form 10-K for the year ended December 31, 2008.

Our business depends on the level of activity in the oil and natural gas industry, which is significantly affected by volatile oil and natural gas prices.

Our business depends on the level of activity in oil and natural gas exploration, development and production in the U.S. Gulf of Mexico and internationally, and in particular, the level of exploration, development and production expenditures of our customers. Demand for our drilling services is adversely affected by declines associated with depressed oil and natural gas prices. Even the perceived risk of a decline in oil or natural gas prices often causes oil and gas companies to reduce spending on exploration, development and production. Reductions in capital expenditures of our customers have reduced rig utilization and day rates. In particular, changes in the price of natural gas materially affect our operations because drilling in the shallow-water U.S. Gulf of Mexico is primarily focused on developing and producing natural gas reserves. However, higher prices do not necessarily translate into increased drilling activity since our clients’ expectations about future commodity prices typically drive demand for our services. Oil and natural gas prices are extremely volatile and have recently declined considerably. On July 2, 2008 natural gas prices were $13.31 per million British thermal unit, or MMBtu, at the Henry Hub. They subsequently declined sharply, reaching a low of $3.17 per MMBtu at the Henry Hub on July 13, 2009. As of July 21, 2009, the closing price of natural gas at the Henry Hub was $3.48 per MMBtu. The spot price for West Texas intermediate crude has recently ranged from a high of $145.29 as of July 3, 2008, to a low of $31.41 as of December 22, 2008, with a closing price of $64.72 as of July 21, 2009. Commodity prices are affected by numerous factors, including the following:

	•		the demand for oil and natural gas in the United States and elsewhere;

	•		the cost of exploring for, developing, producing and delivering oil and natural gas, and the relative cost of onshore production or importation of natural gas;

	•		political, economic and weather conditions in the United States and elsewhere;

	•		imports of liquefied natural gas;

	•		expectations regarding future commodity prices;

	•		advances in exploration, development and production technology;

	•		the ability of the Organization of Petroleum Exporting Countries, commonly called “OPEC,” to set and maintain production levels and pricing;

	•		the level of production in non-OPEC countries;

	•		domestic and international tax policies and governmental regulations;

	•		the development and exploitation of alternative fuels, and the competitive, social and political position of natural gas as a source of energy compared with other energy sources;

	•		the policies of various governments regarding exploration and development of their oil and natural gas reserves;

	•		the worldwide military and political environment and uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or other crises in the Middle East, West Africa and other significant oil and natural gas producing regions; and

	•		acts of terrorism or piracy that affect our areas of operations, especially in Nigeria, where armed conflict, civil unrest and acts of terrorism have recently increased.

As a result of the worldwide recession, reduction in the demand for drilling and liftboat services has materially eroded dayrates and utilization rates for our units, adversely affecting our financial condition and results of operations. Continued hostilities in the Middle East and West Africa and the occurrence or threat of terrorist attacks against the United States or other countries could contribute to the current downturn in the economies of the United States and other countries where we operate. The current worldwide economic downturn has led to a sharp decline in energy consumption, which has materially and adversely affected our results of operations.

The offshore service industry is highly cyclical and is currently experiencing low demand and low dayrates. The volatility of the industry, coupled with our short-term contracts, could result in sharp declines in our profitability.

Historically, the offshore service industry has been highly cyclical, with periods of high demand and high dayrates often followed by periods of low demand and low dayrates. Periods of low demand, such as the current recession, intensify the competition in the industry and often result in rigs or liftboats being idle for long periods of time. In response to the current recession, we have stacked additional rigs and liftboats and entered into lower dayrate contracts. As a result of the cyclicality of our industry, we expect our results of operations to be volatile and to decrease during market declines such as the current recession.

Maintaining idle rigs or the sale of assets below their then carrying value may cause us to experience losses and may result in impairment charges.

Prolonged periods of low rig utilization and dayrates, the cold stacking of idle rigs or the sale of assets below their then carrying value may cause us to experience losses. These events may also result in the recognition of impairment charges on certain of our drilling rigs if future cash flow estimates, based upon information available to management at the time, indicate that their carrying value may not be recoverable or if we sell assets at below their then current carrying value. We recognized impairments of property and equipment of approximately $26.9 million and $376.7 million for the six months ended June 30, 2009 and the year ended December 31, 2008, respectively. We may be required to recognize additional impairments in the future.

Our industry is highly competitive, with intense price competition. Our inability to compete successfully may reduce our profitability.

Our industry is highly competitive. Our contracts are traditionally awarded on a competitive bid basis. Pricing is often the primary factor in determining which qualified contractor is awarded a job, although rig and liftboat availability, location and technical capability and each contractor’s safety performance record and reputation for quality also can be key factors in the determination. Dayrates also depend on the supply of rigs and vessels. Generally, excess capacity puts downward pressure on dayrates, and we have recently experienced declines in utilization and dayrates. Excess capacity can occur when newly constructed rigs and vessels enter service, when rigs and vessels are mobilized between geographic areas and when non-marketed rigs and vessels are re-activated.

Some of our competitors also are incorporated in tax-haven countries outside the United States, which provides them with significant tax advantages that are not available to us as a U.S. company, which may materially impair our ability to compete with them for many projects that would be beneficial to our company.

We have a significant level of debt, and could incur additional debt in the future. Our debt could have significant consequences for our business and future prospects.

As of June 30, 2009, we had total outstanding debt of approximately $969.2 million. This debt represented approximately 50.4% of our total book capitalization. As of June 30, 2009, we had $235.9 million of available capacity under our revolving credit facility, after the commitment of $14.1 million for standby letters of credit. Pursuant to our recent Credit Amendment, the size of our revolving credit facility has been reduced by $75.0 million to $175.0 million, leaving $161.0 million of available capacity at July 27, 2009 under our revolving credit facility after taking into account outstanding letters of credit. We may continue to borrow under our revolving credit facility to fund working capital or other needs in the near term up to the remaining availability. Our debt and the limitations imposed on us by our existing or future debt agreements could have significant consequences for our business and future prospects, including the following:

	•		we may not be able to obtain necessary financing in the future for working capital, capital expenditures, acquisitions, debt service requirements or other purposes and we may be required under the terms of the amendment to our credit facility to use the proceeds of any financing we obtain to repay or prepay existing debt;

	•		we will be required to dedicate a substantial portion of our cash flow from operations to payments of principal and interest on our debt;

	•		we may be exposed to risks inherent in interest rate fluctuations because our borrowings generally are at variable rates of interest, which will result in higher interest expense to the extent that we do not hedge such risk in the event of increases in interest rates;

	•		we could be more vulnerable during downturns in our business and be less able to take advantage of significant business opportunities and to react to changes in our business and in market or industry conditions; and

	•		we may have a competitive disadvantage relative to our competitors that have less debt.

Our ability to make payments on and to refinance our indebtedness, including the convertible notes issued by us in June 2008, and to fund planned capital expenditures will depend on our ability to generate cash in the future, which is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. Our future cash flows may be insufficient to meet all of our debt obligations and other commitments, and any insufficiency could negatively impact our business. To the extent we are unable to repay our indebtedness as it becomes due or at maturity with cash on hand, we will need to refinance our debt, sell assets or repay the debt with the proceeds from equity offerings. Additional indebtedness or equity financing may not be available to us in the future for the refinancing or repayment of existing indebtedness, and we may not be able to complete asset sales in a timely manner sufficient to make such repayments.

Our amended Credit Agreement imposes significant additional costs and operating and financial restrictions on us, which may prevent us from capitalizing on business opportunities and taking certain actions.

Our amended Credit Agreement imposes significant additional costs and operating and financial restrictions on us. These restrictions limit our ability to, among other things:

	•		make certain types of loans and investments;

	•		pay dividends, redeem or repurchase stock, prepay, redeem or repurchase other debt or make other restricted payments;

	•		incur or guarantee additional indebtedness;

	•		use proceeds from asset sales, new indebtedness or equity issuances for general corporate purposes or investment into our current business;

	•		invest in new joint ventures;

	•		create or incur liens;

	•		place restrictions on our subsidiaries’ ability to make dividends or other payments to us;

	•		sell our assets or consolidate or merge with or into other companies;

	•		engage in transactions with affiliates; and

	•		enter into new lines of business.

In addition, under our Credit Agreement, we are required to prepay our term loan with 100% of our excess cash flow for the fiscal year ending December 31, 2009 and, thereafter, 50% of our excess cash flow through the fiscal year ending December 31, 2012. The amended Credit Agreement imposes additional costs on us, including higher interest rates with respect to the debt outstanding under our credit facility. Our amended Credit Agreement also imposes significant financial and operating restrictions on us. These restrictions will further limit our ability to acquire assets, except in cases in which the consideration is equity (the net cash proceeds of an issuance thereof) or we are in compliance with our financial covenants as they existed prior to the amendment of the Credit Agreement. Our compliance with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures, finance our acquisitions, equipment purchases and development expenditures, or withstand the present or any future downturn in our business.

If we are unable to comply with the restrictions and covenants in our amended Credit Agreement, there could be a default, which could result in an acceleration of repayment of funds that we have borrowed.

Our Credit Agreement requires that we meet certain financial ratios and tests. As of June 30, 2009, we were in compliance with all of our financial covenants under the Credit Agreement. Effective July 27, 2009, we entered into an amendment of our Credit Agreement to provide additional flexibility in certain financial covenants. However, there can be no assurance that we will be able to comply with the modified financial covenants. Furthermore, the amendment to our Credit Agreement also imposes additional and different covenants and restrictions, including the imposition of a requirement to maintain a minimum level of liquidity at all times. Our ability to comply with these financial covenants and restrictions can be affected by events beyond our control. Our failure to comply with such covenants would result in an event of default under the Credit Agreement. An event of default could prevent us from borrowing under our revolving credit facility, which could in turn have a material adverse effect on our available liquidity. In addition, an event of default could result in our having to immediately repay all amounts outstanding under the Credit Facility and in foreclosure of liens on our assets.

The continuing worldwide economic recession is materially reducing our revenue, profitability and cash flows.

The current worldwide recession has reduced the availability of liquidity and credit to fund business operations worldwide, and has adversely affected our customers, suppliers and lenders. The recession has reduced worldwide demand for energy and resulted in lower oil and natural gas prices. Forecasted crude oil prices and natural gas for 2009 have dropped substantially over the past year. Demand for our services depends on oil and natural gas industry activity and capital expenditure levels that are directly affected by trends in oil and natural gas prices. Any prolonged reduction in oil and natural gas prices will further depress the current levels of exploration, development and production activity. Perceptions of longer-term lower oil and natural gas prices by oil and gas companies can similarly reduce or defer major expenditures. Lower levels of activity result in a corresponding decline in the demand for our services, which could have a material adverse effect on our revenue and profitability.

We may require additional capital in the future, which may not be available to us or may be at a cost which reduces our cash flow and profitability.

Our business is capital-intensive and, to the extent we do not generate sufficient cash from operations, we may need to raise additional funds through public or private debt (which could increase our interest costs) or equity financings to execute our business strategy, to fund capital expenditures or to meet our covenants under the Credit Agreement. Adequate sources of capital funding may not be available when needed or may not be available on acceptable terms and under the terms of the amendment to our credit facility, we may be required to use the proceeds of any capital that we raise to repay existing indebtedness. If we raise additional funds by issuing additional equity securities, existing stockholders may experience dilution. If funding is insufficient at any time in the future, we may be unable to fund maintenance of our vessels, take advantage of business opportunities or respond to competitive pressures, any of which could harm our business.

Asset sales are currently an important component of our business strategy for the purpose of reducing our debt. We may be unable to identify appropriate buyers with access to financing or to complete any sales on acceptable terms.

We are currently considering sales or other dispositions of certain of our assets, and any such disposition could be significant and could significantly affect the results of operations of one or more of our business segments. In the current economic recession, asset sales may occur on less favorable terms than terms that might be available at other times in the business cycle. At any given time, discussions with one or more potential buyers may be at different stages. However, any such discussions may or may not result in the consummation of an asset sale. We may not be able to identify buyers with access to financing or complete any sales on acceptable terms.

Our contracts are generally short term, and we will experience reduced profitability if our customers reduce activity levels or terminate or seek to renegotiate our drilling or liftboat contracts or if we experience downtime, operational difficulties, or safety-related issues.

Currently, all of our drilling contracts with major customers are dayrate contracts, where we charge a fixed charge per day regardless of the number of days needed to drill the well. Likewise, under our current liftboat contracts, we charge a fixed fee per day regardless of the success of the operations that are being conducted by our customer utilizing our liftboat. During depressed market conditions, a customer may no longer need a rig or liftboat that is currently under contract or may be able to obtain a comparable rig or liftboat at a lower daily rate. As a result, customers may seek to renegotiate the terms of their existing drilling contracts or avoid their obligations under those contracts. In addition, our customers may have the right to terminate, or may seek to renegotiate, existing contracts if we experience downtime, operational problems above the contractual limit or safety-related issues, if the rig or liftboat is a total loss, if the rig or liftboat is not delivered to the customer within the period specified in the contract or in other specified circumstances, which include events beyond the control of either party.

In the U.S. Gulf of Mexico, contracts are generally short term, and oil and natural gas companies tend to reduce activity levels quickly in response to downward changes in oil and natural gas prices. Due to the short-term nature of most of our contracts, a decline in market conditions can quickly affect our business if customers reduce their levels of operations.

Some of our contracts with our customers include terms allowing them to terminate contracts without cause, with little or no prior notice and without penalty or early termination payments. In addition, we could be required to pay penalties if some of our contracts

with our customers are terminated due to downtime, operational problems or failure to deliver. Some of our other contracts with customers may be cancelable at the option of the customer upon payment of a penalty, which may not fully compensate us for the loss of the contract. Early termination of a contract may result in a rig or liftboat being idle for an extended period of time. The likelihood that a customer may seek to terminate a contract is increased during periods of market weakness. In the first two quarters of 2009, certain of our customers, both domestically and internationally, have sought early termination of their contracts with us. Our largest domestic customer, Chevron Corporation, recently notified us that it will no longer utilize two of our domestic rigs which have been continuously working for Chevron for many years. If our customers cancel some of our significant contracts, such as the contracts in our International Offshore segment, and we are unable to secure new contracts on substantially similar terms, our revenues and profitability would be materially reduced.

An increase in supply of rigs or liftboats could adversely affect our financial condition and results of operations.

Reactivation of non-marketed rigs or liftboats, mobilization of rigs or liftboats back to the U.S. Gulf of Mexico or new construction of rigs or liftboats could result in excess supply in the region, and our dayrates and utilization could be reduced.

If market conditions improve, inactive rigs and liftboats that are not currently being marketed could be reactivated to meet an increase in demand. Improved market conditions in the U.S. Gulf of Mexico, particularly relative to other markets, could also lead to jackup rigs, other mobile offshore drilling units and liftboats being moved into the U.S. Gulf of Mexico. Improved market conditions in any region worldwide could lead to increased construction and upgrade programs by our competitors. Some of our competitors have already announced plans to upgrade existing equipment or build additional jackup rigs with higher specifications than our rigs. According to ODS-Petrodata, as of July 21, 2009, 60 jackup rigs were under construction or on order by industry participants, national oil companies and financial investors for delivery through 2011. Not all of the rigs currently under construction have been contracted for future work, which may intensify price competition as scheduled delivery dates occur. In addition, as of July 2, 2009, we believe there were also 9 liftboats under construction or on order in the United States that may be used in the U.S. Gulf of Mexico. A significant increase in the supply of jackup rigs, other mobile offshore drilling units or liftboats could adversely affect both our utilization and dayrates.

Our business involves numerous operating hazards, and our insurance may not be adequate to cover our losses.

Our operations are subject to the usual hazards inherent in the drilling and operation of oil and natural gas wells, such as blowouts, reservoir damage, loss of production, loss of well control, punchthroughs, craterings, fires and pollution. The occurrence of these events could result in the suspension of drilling or production operations, claims by the operator, severe damage to or destruction of the property and equipment involved, injury or death to rig or liftboat personnel, and environmental damage. We may also be subject to personal injury and other claims of rig or liftboat personnel as a result of our drilling and liftboat operations. Operations also may be suspended because of machinery breakdowns, abnormal operating conditions, failure of subcontractors to perform or supply goods or services and personnel shortages.

In addition, our drilling and liftboat operations are subject to perils of marine operations, including capsizing, grounding, collision and loss or damage from severe weather. Tropical storms, hurricanes and other severe weather prevalent in the U.S. Gulf of Mexico, such as Hurricanes Gustav and Ike in September 2008, Hurricane Rita in September 2005, Hurricane Katrina in August 2005 and Hurricane Ivan in September 2004, could have a material adverse effect on our operations. During such severe weather conditions, our liftboats typically leave location and cease to earn a full dayrate. Under U.S. Coast Guard guidelines, the liftboats cannot return to work until the weather improves and seas are less than five feet. In addition, damage to our rigs, liftboats, shorebases and corporate infrastructure caused by high winds, turbulent seas, or unstable sea bottom conditions could potentially cause us to curtail operations for significant periods of time until the damages can be repaired.

Damage to the environment could result from our operations, particularly through oil spillage or extensive uncontrolled fires. We may also be subject to property, environmental and other damage claims by oil and natural gas companies and other businesses operating offshore and in coastal areas. Our insurance policies and contractual rights to indemnity may not adequately cover losses, and we may not have insurance coverage or rights to indemnity for all risks. Moreover, pollution and environmental risks generally are subject to significant deductibles and are not totally insurable.

A significant portion of our business is conducted in shallow-water areas of the U.S. Gulf of Mexico. The mature nature of this region could result in less drilling activity in the area, thereby reducing demand for our services.

The U.S. Gulf of Mexico, and in particular the shallow-water region of the U.S. Gulf of Mexico, is a mature oil and natural gas production region that has experienced substantial seismic survey and exploration activity for many years. Because a large number of oil and natural gas prospects in this region have already been drilled, additional prospects of sufficient size and quality could be more difficult to identify. According to the U.S. Energy Information Administration, the average size of the U.S. Gulf of Mexico discoveries has declined significantly since the early 1990s. In addition, the amount of natural gas production in the shallow-water U.S. Gulf of Mexico has declined over the last decade. Moreover, oil and natural gas companies may be unable to obtain financing necessary to drill prospects in this region. The decrease in the size of oil and natural gas prospects, the decrease in production or the failure to obtain such financing may result in reduced drilling activity in the U.S. Gulf of Mexico and reduced demand for our services.

We can provide no assurance that our current backlog of contract drilling revenue will be ultimately realized.

As of July 21, 2009, our total contract drilling backlog for our Domestic Offshore, International Offshore and Inland segments was approximately $563.3 million. We may not be able to perform under these contracts due to events beyond our control, such as adverse weather events in the Gulf of Mexico, and our customers may seek to cancel or renegotiate our contracts for various reasons, including the financial crisis or falling commodity prices. Our inability or the inability of our customers to perform under our or their contractual obligations may have a material adverse effect on our financial position, results of operations and cash flows.

Our insurance coverage has become more expensive, may become unavailable in the future, and may be inadequate to cover our losses.

Our insurance coverage is subject to certain significant deductibles and levels of self-insurance, does not cover all types of losses and, in some situations, may not provide full coverage for losses or liabilities resulting from our operations. In addition, due to the losses sustained by us and the offshore drilling industry in recent years, primarily as a result of Gulf of Mexico hurricanes, we are likely to continue experiencing increased costs for available insurance coverage, which may impose higher deductibles and limit maximum aggregated recoveries, including for hurricane-related windstorm damage or loss. Our 2009 insurance renewal provided significantly reduced coverage at premium levels similar to those we incurred in our 2008 insurance renewal.

Further, we may not be able to obtain windstorm coverage in the future, thus putting us at a greater risk of loss due to severe weather conditions and other hazards. If a significant accident or other event resulting in damage to our rigs or liftboats, including severe weather, terrorist acts, piracy, war, civil disturbances, pollution or environmental damage, occurs and is not fully covered by insurance or a recoverable indemnity from a customer, it could adversely affect our financial condition and results of operations. Moreover, we may not be able to maintain adequate insurance in the future at rates we consider reasonable or be able to obtain insurance against certain risks.

As a result of a number of recent catastrophic events like Hurricanes Gustav, Ike, Ivan, Katrina and Rita, insurance underwriters increased insurance premiums for many of the coverages historically maintained and issued general notices of cancellation and significant changes for a wide variety of insurance coverages. The oil and natural gas industry suffered extensive damage from Hurricanes Gustav, Ike, Ivan, Katrina and Rita. As a result, over the past four years our insurance costs increased significantly, our deductibles increased and our coverage for named windstorm damage was restricted. Any additional severe storm activity in the energy producing areas of the U.S. Gulf of Mexico in the future could cause insurance underwriters to no longer insure U.S. Gulf of Mexico assets against weather-related damage. A number of our customers that produce oil and natural gas have previously maintained business interruption insurance for their production. This insurance is less available and may cease to be available in the future, which could adversely impact our customers’ business prospects in the U.S. Gulf of Mexico and reduce demand for our services.

Our customers may be unable or unwilling to indemnify us.

Consistent with standard industry practice, our clients generally assume, and indemnify us against, well control and subsurface risks under dayrate contracts. These risks are those associated with the loss of control of a well, such as blowout or cratering, the cost to regain control or redrill the well and associated pollution. There can be no assurance, however, that these clients will necessarily be financially able to indemnify us against all these risks. Also, we may be effectively prevented from enforcing these indemnities because of the nature of our relationship with some of our larger clients. Additionally, from time to time we may not be able to obtain agreement from our customer to indemnify us for such damages and risks.

Our international operations are subject to additional political, economic, and other uncertainties not generally associated with domestic operations.

An element of our business strategy is to continue to expand into international oil and natural gas producing areas such as West Africa, the Middle East and the Asia-Pacific region. We operate liftboats in West Africa, including Nigeria, and in the Middle East. We also operate drilling rigs in India, Southeast Asia, Saudi Arabia, Mexico and West Africa. Our international operations are subject to a number of risks inherent in any business operating in foreign countries, including:

	•		political, social and economic instability, war and acts of terrorism;

	•		potential seizure, expropriation or nationalization of assets;

	•		damage to our equipment or violence directed at our employees, including kidnappings and piracy;

	•		increased operating costs;

	•		complications associated with repairing and replacing equipment in remote locations;

	•		repudiation, modification or renegotiation of contracts, disputes and legal proceedings in international jurisdictions;

	•		limitations on insurance coverage, such as war risk coverage in certain areas;

	•		import-export quotas;

	•		confiscatory taxation;

	•		work stoppages or strikes, particularly in the West African and Mexican labor environments;

	•		unexpected changes in regulatory requirements;

	•		wage and price controls;

	•		imposition of trade barriers;

	•		imposition or changes in enforcement of local content laws;

	•		restrictions on currency or capital repatriations;

	•		currency fluctuations and devaluations; and

	•		other forms of government regulation and economic conditions that are beyond our control.

Recently, political unrest, acts of terrorism, piracy and armed conflict have increased in Nigeria. Several recent acts of terrorism and piracy have apparently been directed at assets and operations of our largest customer, Chevron Corporation. In the past, many of our customers in Nigeria, including Chevron, have interrupted their activities during these episodes of increased terrorism, piracy and armed conflict. These interruptions in activity can be prolonged, during which time we may not receive dayrates for our liftboats.

Many governments favor or effectively require that liftboat or drilling contracts be awarded to local contractors or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These practices may result in inefficiencies or put us at a disadvantage when bidding for contracts against local competitors.

Our non-U.S. contract drilling and liftboat operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to the equipment and operation of drilling rigs and liftboats, currency conversions and repatriation, oil and natural gas exploration and development, taxation of offshore earnings and earnings of expatriate personnel, the use of local employees and suppliers by foreign contractors and duties on the importation and exportation of units and other equipment. Governments in some foreign countries have become increasingly active in regulating and controlling the ownership of concessions and companies holding concessions, the exploration for oil and natural gas and other aspects of the oil and natural gas industries in their countries. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by major oil and natural gas companies and may continue to do so. Operations in developing countries can be subject to legal systems which are not as predictable as those in more developed countries, which can lead to greater risk and uncertainty in legal matters and proceedings.

Due to our international operations, we may experience currency exchange losses when revenues are received and expenses are paid in nonconvertible currencies or when we do not hedge an exposure to a foreign currency. We may also incur losses as a result of an inability to collect revenues because of a shortage of convertible currency available to the country of operation, controls over currency exchange or controls over the repatriation of income or capital.

A few customers account for a significant portion of our revenues, and the loss of one or more of these customers could adversely affect our financial condition and results of operations.

We derive a significant amount of our revenues from a few energy companies. Our financial condition and results of operations will be materially adversely affected if one or more of these customers interrupts or curtails their activities, terminates their contracts with us, fails to renew their existing contracts or refuses to award new contracts to us and we are unable to enter into contracts with new customers at comparable dayrates.

Our jackup rigs are at a relative disadvantage to higher specification rigs, which may be more likely to obtain contracts than lower specification jackup rigs such as ours.

Many of our competitors have jackup fleets with generally higher specification rigs than those in our jackup fleet. In addition, the announced construction of new rigs includes approximately 60 higher specification jackup rigs. Further, 22 of our 31 jackup rigs are mat-supported, which are generally limited to geographic areas with soft bottom conditions like much of the Gulf of Mexico. Most of the new rigs available in the second half of 2009 and beyond are currently without contracts, which may intensify price competition as scheduled delivery dates occur. Particularly in markets in which there is decreased rig demand, such as the current market, higher specification rigs may be more likely to obtain contracts than lower specification jackup rigs such as ours. In the past, lower specification rigs have been stacked earlier in the cycle of decreased rig demand than higher specification rigs and have been reactivated later in the cycle, which may adversely impact our business. In addition, higher specification rigs may be more adaptable

to different operating conditions and therefore have greater flexibility to move to areas of demand in response to changes in market conditions. Because a majority of our rigs were designed specifically for drilling in the shallow-water U.S. Gulf of Mexico, our ability to move them to other regions in response to changes in market conditions is limited.

Furthermore, in recent years, an increasing amount of exploration and production expenditures have been concentrated in deepwater drilling programs and deeper formations, including deep natural gas prospects, requiring higher specification jackup rigs, semisubmersible drilling rigs or drillships. This trend is expected to continue and could result in a decline in demand for lower specification jackup rigs like ours, which could have an adverse impact on our financial condition and results of operations. One of our customers, Pemex Exploración y Producción (“PEMEX”), has indicated a shifting focus in drilling rig requirements since the beginning of 2008, with more emphasis placed on independent leg cantilever rigs rated for 205 foot water depth or greater, versus mat cantilever rigs rated for 200 foot water depth. It is possible that demand in Mexico for our 200 foot mat cantilever fleet could decline and the future contracting opportunities for such rigs in Mexico could diminish.

We may consider future acquisitions and may be unable to complete and finance future acquisitions on acceptable terms. In addition, we may fail to successfully integrate acquired assets or businesses we acquire or incorrectly predict operating results.

We may consider future acquisitions which could involve the payment by us of a substantial amount of cash, the incurrence of a substantial amount of debt or the issuance of a substantial amount of equity. Unless we have achieved a specified leverage ratio, the Credit Agreement restricts our ability to make acquisitions involving the payment of cash or the incurrence of debt. If we are restricted from using cash or incurring debt to fund a potential acquisition, we may not be able to issue, on terms we find acceptable, sufficient equity that may be required for any such permitted acquisition or investment. In addition, barring any restrictions under the Credit Agreement, we still may not be able to obtain, on terms we find acceptable, sufficient financing or funding that may be required for any such acquisition or investment.

We cannot predict the effect, if any, that any announcement or consummation of an acquisition would have on the trading price of our common stock.

Any future acquisitions could present a number of risks, including:

	•		the risk of incorrect assumptions regarding the future results of acquired operations or assets or expected cost reductions or other synergies expected to be realized as a result of acquiring operations or assets;

	•		the risk of failing to integrate the operations or management of any acquired operations or assets successfully and timely; and

	•		the risk of diversion of management’s attention from existing operations or other priorities.

If we are unsuccessful in integrating our acquisitions in a timely and cost-effective manner, our financial condition and results of operations could be adversely affected.

Governmental laws and regulations may add to our costs or limit drilling activity and liftboat operations.

Our operations are affected in varying degrees by governmental laws and regulations. We are also subject to the jurisdiction of the United States Coast Guard, the National Transportation Safety Board and the United States Customs and Border Protection Service, as well as private industry organizations such as the American Bureau of Shipping. We may be required to make significant capital expenditures to comply with laws and the applicable regulations and standards of those authorities and organizations. Moreover, the cost of compliance could be higher than anticipated. Similarly, our international operations are subject to compliance with the U.S. Foreign Corrupt Practices Act, certain international conventions and the laws, regulations and standards of other foreign countries in which we operate. It is also possible that these conventions, laws, regulations and standards may in the future add significantly to our operating costs or limit our activities.

In addition, as our vessels age, the costs of drydocking the vessels in order to comply with governmental laws and regulations and to maintain their class certifications are expected to increase, which could adversely affect our financial condition and results of operations.

Compliance with or a breach of environmental laws can be costly and could limit our operations.

Our operations are subject to regulations that require us to obtain and maintain specified permits or other governmental approvals, control the discharge of materials into the environment, require the removal and cleanup of materials that may harm the environment or otherwise relate to the protection of the environment. For example, as an operator of mobile offshore drilling units and liftboats in navigable U.S. waters and some offshore areas, we may be liable for damages and costs incurred in connection with oil spills or other unauthorized discharges of chemicals or wastes resulting from those operations. Laws and regulations protecting the environment have become more stringent in recent years, and may in some cases impose strict liability, rendering a person liable for environmental damage without regard to negligence or fault on the part of such person. Some of these laws and regulations may expose us to liability for the conduct of or conditions caused by others or for acts that were in compliance with all applicable laws at the time they were performed. The application of these requirements, the modification of existing laws or regulations or the adoption of new requirements, both in U.S. waters and internationally, could have a material adverse effect on our financial condition and

results of operations.

We may not be able to maintain or replace our rigs and liftboats as they age.

The capital associated with the repair and maintenance of our fleet increases with age. We may not be able to maintain our fleet by extending the economic life of existing rigs and liftboats, and our financial resources may not be sufficient to enable us to make expenditures necessary for these purposes or to acquire or build replacement units.

Our operating and maintenance costs with respect to our rigs include fixed costs that will not decline in proportion to decreases in dayrates.

We do not expect our operating and maintenance costs with respect to our rigs to necessarily fluctuate in proportion to changes in operating revenues. Operating revenues may fluctuate as a function of changes in dayrate, but costs for operating a rig are generally fixed or only semi-variable regardless of the dayrate being earned. Additionally, if our rigs incur idle time between contracts, we typically do not de-man those rigs because we will use the crew to prepare the rig for its next contract. During times of reduced activity, reductions in costs may not be immediate as portions of the crew may be required to prepare our rigs for stacking, after which time the crew members are assigned to active rigs or dismissed. Moreover, as our rigs are mobilized from one geographic location to another, the labor and other operating and maintenance costs can vary significantly. In general, labor costs increase primarily due to higher salary levels and inflation. Equipment maintenance expenses fluctuate depending upon the type of activity the unit is performing and the age and condition of the equipment. Contract preparation expenses vary based on the scope and length of contract preparation required and the duration of the firm contractual period over which such expenditures are amortized.

Upgrade, refurbishment and repair projects are subject to risks, including delays and cost overruns, which could have an adverse impact on our available cash resources and results of operations.

We make upgrade, refurbishment and repair expenditures for our fleet from time to time, including when we acquire units or when repairs or upgrades are required by law, in response to an inspection by a governmental authority or when a unit is damaged. We also regularly make certain upgrades or modifications to our drilling rigs to meet customer or contract specific requirements. Upgrade, refurbishment and repair projects are subject to the risks of delay or cost overruns inherent in any large construction project, including costs or delays resulting from the following:

	•		unexpectedly long delivery times for, or shortages of, key equipment, parts and materials;

	•		shortages of skilled labor and other shipyard personnel necessary to perform the work;

	•		unforeseen increases in the cost of equipment, labor and raw materials, particularly steel;

	•		unforeseen design and engineering problems;

	•		latent damages to or deterioration of hull, equipment and machinery in excess of engineering estimates and assumptions;

	•		unanticipated actual or purported change orders;

	•		work stoppages;

	•		failure or delay of third-party service providers and labor disputes;

	•		disputes with shipyards and suppliers;

	•		delays and unexpected costs of incorporating parts and materials needed for the completion of projects;

	•		failure or delay in obtaining acceptance of the rig from our customer;

	•		financial or other difficulties at shipyards;

	•		adverse weather conditions; and

	•		inability or delay in obtaining customer acceptance or flag-state, classification society, certificate of inspection, or regulatory approvals.

Significant cost overruns or delays would adversely affect our financial condition and results of operations. Additionally, capital expenditures for rig upgrade and refurbishment projects could exceed our planned capital expenditures. Failure to complete an upgrade, refurbishment or repair project on time may, in some circumstances, result in the delay, renegotiation or cancellation of a drilling or liftboat contract and could put at risk our planned arrangements to commence operations on schedule. We also could be exposed to penalties for failure to complete an upgrade, refurbishment or repair project and commence operations in a timely manner.

Our rigs and liftboats undergoing upgrade, refurbishment or repair generally do not earn a dayrate during the period they are out of service.

We are subject to litigation that could have an adverse effect on us.

We are from time to time involved in various litigation matters. The numerous operating hazards inherent in our business increases our exposure to litigation, including personal injury litigation brought against us by our employees that are injured operating our rigs and liftboats. These matters may include, among other things, contract dispute, personal injury, environmental, asbestos and other toxic tort, employment, tax and securities litigation, and litigation that arises in the ordinary course of our business. We have extensive litigation brought against us in federal and state courts located in Louisiana, Mississippi and South Texas, areas that were significantly impacted by the hurricanes in 2005 and, more recently, by Hurricanes Gustav and Ike. The jury pools in these areas have become increasingly more hostile to defendants, particularly corporate defendants in the oil and gas industry. We cannot predict with certainty the outcome or effect of any claim or other litigation matter. Litigation may have an adverse effect on us because of potential negative outcomes, the costs associated with defending the lawsuits, the diversion of our management’s resources and other factors.

TODCO’s tax sharing agreement with Transocean may require continuing substantial payments.

We, as successor to TODCO, and TODCO’s former parent Transocean Holdings Inc., or Transocean, are parties to a tax sharing agreement that was originally entered into in connection with TODCO’s initial public offering in 2004. The tax sharing agreement was amended and restated in November 2006. The tax sharing agreement required us to make an acceleration payment to Transocean upon completion of the TODCO acquisition. Additionally, the tax sharing agreement continues to require that additional payments be made to Transocean based on a portion of the expected tax benefit from the exercise of certain compensatory stock options to acquire Transocean common stock attributable to current and former TODCO employees and board members. The estimated amount of payments to Transocean related to compensatory options that remained outstanding at June 30, 2009, assuming a Transocean stock price of $74.29 per share at the time of exercise of the compensatory options (the actual price of Transocean’s common stock at June 30, 2009), was approximately $1.5 million. There is no certainty that we will realize future economic benefits from TODCO’s tax benefits equal to the amount of the payments required under the tax sharing agreement.

Changes in effective tax rates, taxation of our foreign subsidiaries, limitations on utilization of our net operating losses or adverse outcomes resulting from examination of our tax returns could adversely affect our operating results and financial results.

Our future effective tax rates could be adversely affected by changes in tax laws, both domestically and internationally. From time to time, Congress and foreign, state and local governments consider legislation that could increase our effective tax rates. In May 2009, President Obama’s administration proposed significant changes to the U.S. tax laws, including changes that would limit U.S. tax deductions for expenses related to unrepatriated foreign-source income and modify the U.S. foreign tax credit. We cannot determine whether, or in what form, legislation implementing the administration’s proposals will ultimately be enacted or what the impact of any such legislation would be on our profitability. If these or other changes to U.S. tax laws are enacted, our profitability could be negatively impacted.

Our future effective tax rates could also be adversely affected by changes in the valuation of our deferred tax assets and liabilities, or by changes in tax treaties, regulations, accounting principles or interpretations thereof in one or more countries in which we operate. In addition, we are subject to the potential examination of our income tax returns by the Internal Revenue Service and other tax authorities where we file tax returns. We regularly assess the likelihood of adverse outcomes resulting from these examinations to determine the adequacy of our provision for taxes. There can be no assurance that such examinations will not have an adverse effect on our operating results and financial condition.

Our business would be adversely affected if we failed to comply with the provisions of U.S. law on coastwise trade, or if those provisions were modified, repealed or waived.

We are subject to U.S. federal laws that restrict maritime transportation, including liftboat services, between points in the United States to vessels built and registered in the United States and owned and manned by U.S. citizens. We are responsible for monitoring the ownership of our common stock. If we do not comply with these restrictions, we would be prohibited from operating our liftboats in U.S. coastwise trade, and under certain circumstances we would be deemed to have undertaken an unapproved foreign transfer, resulting in severe penalties, including permanent loss of U.S. coastwise trading rights for our liftboats, fines or forfeiture of the liftboats.

During the past several years, interest groups have lobbied Congress to repeal these restrictions to facilitate foreign flag competition for trades currently reserved for U.S.-flag vessels under the federal laws. We believe that interest groups may continue efforts to modify or repeal these laws currently benefiting U.S.-flag vessels. If these efforts are successful, it could result in increased competition, which could adversely affect our results of operations.

Our liquidity depends upon cash on hand, cash from operations and availability under our revolving credit facility.

Our liquidity depends upon cash on hand, cash from operations and availability under our revolving credit facility, as amended. In the amendment to our Credit Facility, we reduced the size of our revolving credit facility from $250.0 million to $175.0 million. The availability under the revolving credit facility is to be used for working capital, capital expenditures and other general corporate

purposes and cannot be used to prepay outstanding term loans under our credit facility. All borrowings under the revolving credit facility mature on July 11, 2012, and the revolving credit facility requires interest-only payments on a quarterly basis until the maturity date. No amounts were outstanding under the revolving credit facility as of June 30, 2009, although $14.1 million in stand-by letters of credit had been issued under it. The remaining availability under the revolving credit facility, as amended, is $161.0 million at July 27, 2009.

We also maintain a shelf registration statement covering the future issuance from time to time of various types of securities, including debt and equity securities. If we issue any debt securities off the shelf registration statement or otherwise incur debt, we may be required to make payments on our term loan. We currently believe we will have adequate liquidity to fund our operations for the foreseeable future. However, to the extent we do not generate sufficient cash from operations, we may need to raise additional funds through public or private debt or equity offerings to fund operations and under the terms of the amendment to our credit facility, we may be required to use the proceeds of any capital that we raise to repay existing indebtedness. Furthermore, we may need to raise additional funds through public or private debt or equity offerings or asset sales to avoid a breach of our financial covenants in our Credit Facility, even as amended, to refinance our indebtedness or for general corporate purposes.

We are a holding company, and we are dependent upon cash flow from subsidiaries to meet our obligations.

We currently conduct our operations through, and most of our assets are owned by, both U.S. and foreign subsidiaries, and our operating income and cash flow are generated by our subsidiaries. As a result, cash we obtain from our subsidiaries is the principal source of funds necessary to meet our debt service obligations. Contractual provisions or laws, as well as our subsidiaries’ financial condition and operating requirements, may limit our ability to obtain cash from our subsidiaries that we require to pay our debt service obligations, including payments on our convertible notes. Applicable tax laws may also subject such payments to us by our subsidiaries to further taxation.

The inability to transfer cash from our subsidiaries to us may mean that, even though we may have sufficient resources on a consolidated basis to meet our obligations, we may not be permitted to make the necessary transfers from subsidiaries to the parent company in order to provide funds for the payment of the parent company’s obligations.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

In June 2009, we entered into separate exchange agreements with certain holders of our 3.375% Convertible Senior Notes, pursuant to which holders of approximately $45.8 million in aggregate principal amount of these notes agreed to exchange their notes for an aggregate of 7,755,440 shares of our Common Stock and the payment of accrued interest. The issuance of the shares of our Common Stock will not be registered under the Securities Act of 1933, as amended (“the Act”), in reliance of an exemption under Section 4(2) of the Act and Rule 506 of Regulation D, as the exchange was not public.

The following table set forth for the periods indicated certain information with respect to our purchases of our Common Stock:

Total Number of

Shares Purchased

Maximum Number

as Part of a

of Shares That

Total Number

Publicly

May Yet Be

of Shares

Average Price

Announced Plan

Purchased Under

Period

Purchased(1)

Paid per Share

(2)

Plan (2)

April 1-30, 2009

415

3.12

N/A

May 1-31, 2009

314

4.14

N/A

June 1-30, 2009

872

4.82

N/A

Total

1,601

4.25

N/A


(1)		Represents the surrender of shares of common stock to satisfy tax withholding obligations in connection with the vesting of restricted stock issued to employees under our stockholder-approved long-term incentive plan.

(2)		We did not have at any time during the quarter, and currently do not have, a share repurchase program in place.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Our annual meeting of stockholders was held in Houston, Texas on April 23, 2009 for the purpose of voting on the proposals described below. Proxies for the meeting were solicited pursuant to Section 14(a) of the Securities Exchange Act of 1934 and there was no solicitation in opposition to management’s solicitation.

Stockholders elected three directors to the class of directors whose term will expire at the 2012 annual meeting of stockholders by the following votes:


Name	For		Withheld
Thomas N. Amonett		69,577,480		8,774,833
John T. Rynd		69,779,660		8,572,653
Steven A. Webster		60,361,057		17,991,256

The terms of office of directors Suzanne V. Baer, Thomas R. Bates, Jr., Thomas M Hamilton, Thomas J. Madonna, F. Gardner Parker, Thierry Pilenko and John T. Reynolds continued beyond the meeting date.

Stockholders ratified the appointment of Ernst & Young LLP as our independent registered public accounting firm for the year ending December 31, 2009 by the following vote:


For			77,722,300
Against			265,243
Abstain			355,864
Broker Non-Vote			8,906

ITEM 6. EXHIBITS


4.1*		Amendment No. 2 dated as of July 23, 2009, to the Credit Agreement dated July 11, 2007, among Hercules Offshore, Inc., as borrower, its subsidiaries party thereto, as guarantors, and UBS AG, Stamford Branch, as issuing bank, administrative agent and collateral agent, and the lenders party thereto.

10.1		Waiver of Executive Employment Agreement between the Company and John T. Rynd, dated April 27, 2009 (incorporated by reference to Exhibit 10.1 to Hercules’ Current Report on Form 8-K dated April 28, 2009).

10.2		Waiver of Executive Employment Agreement between the Company and Lisa W. Rodriguez, dated April 27, 2009 (incorporated by reference to Exhibit 10.2 to Hercules’ Current Report on Form 8-K dated April 28, 2009).

10.3		Waiver of Executive Employment Agreement between the Company and James W. Noe, dated April 27, 2009 (incorporated by reference to Exhibit 10.3 to Hercules’ Current Report on Form 8-K dated April 28, 2009).

10.4		Waiver of Executive Employment Agreement between the Company and Terrell L. Carr, dated April 27, 2009 (incorporated by reference to Exhibit 10.4 to Hercules’ Current Report on Form 8-K dated April 28, 2009).

10.5		Waiver of Executive Employment Agreement between the Company and Todd A. Pellegrin, dated April 27, 2009 (incorporated by reference to Exhibit 10.5 to Hercules’ Current Report on Form 8-K dated April 28, 2009).

10.6		Basic Form of Exchange Agreement between the Company and certain holders of our 3.375% Convertible Senior Notes due 2038 (incorporated by reference to Exhibit 10.1 to Hercules’ Current Report on Form 8-K dated June 18, 2009).

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

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

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


*		Filed herewith

SIGNATURES

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


		HERCULES OFFSHORE, INC.

		By:		/s/ John T. Rynd

				John T. Rynd
				Chief Executive Officer and President
				(Principal Executive Officer)

		By:		/s/ Lisa W. Rodriguez

				Lisa W. Rodriguez
				Senior Vice President and Chief Financial Officer
				(Principal Financial Officer)

		By:		/s/ Troy L. Carson

				Troy L. Carson
				Vice President and Corporate Controller
				(Principal Accounting Officer)

Date: July 28, 2009