Edgar Filing: HERCULES OFFSHORE, INC.

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 March 31, 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 April 24, 2009
		88,029,655

HERCULES OFFSHORE, INC.

INDEX


		Page No.
PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements:
	Consolidated Balance Sheets as of March 31, 2009 and December 31, 2008		3
	Consolidated Statements of Operations for the three months ended March 31, 2009, and March 31, 2008		4
	Consolidated Statements of Cash Flows for the three months ended March 31, 2009 and March 31, 2008		5
	Consolidated Statements of Comprehensive Loss for the three months ended March 31 2009, and March 31, 2008		6
	Notes to Unaudited Consolidated Financial Statements		7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		20
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		33
Item 4.	Controls and Procedures		34

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings		35
Item 1A.	Risk Factors		35
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		35
Item 6.	Exhibits		35

	Signatures		36
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)


	March 31,			December 31,
	2009			2008
				(As Adjusted)
ASSETS
Current Assets:
Cash and Cash Equivalents	$	158,737		$	106,455
Accounts Receivable, Net		240,657			293,089
Prepaids		14,578			23,033
Current Deferred Tax Asset		17,598			17,379
Other		20,654			20,069

		452,224			460,025
Property and Equipment, Net		2,075,412			2,088,530
Other Assets, Net		47,239			42,340

	$	2,574,875		$	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		—			11,126
Accounts Payable		80,597			99,823
Accrued Liabilities		82,239			83,424
Taxes Payable		36,503			32,440
Other Current Liabilities		56,093			36,472

		264,432			274,740
Long-term Debt, Net of Current Portion		1,017,079			1,015,764
Other Liabilities		36,295			35,529
Deferred Income Taxes		332,504			339,547
Commitments and Contingencies
Stockholders’ Equity:
Common Stock, $0.01 Par Value; 200,000 Shares Authorized; 89,524 and 89,459 Shares Issued, Respectively; 88,027 and 87,976 Shares Outstanding, Respectively		895			895
Capital in Excess of Par Value		1,790,102			1,785,462
Treasury Stock, at Cost, 1,497 Shares and 1,483 Shares, Respectively		(50,121	)		(50,081	)
Accumulated Other Comprehensive Loss		(15,338	)		(14,932	)
Retained Deficit		(800,973	)		(796,029	)

		924,565			925,315

	$	2,574,875		$	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 March 31,
	2009			2008
Revenues	$	223,491		$	212,494
Costs and Expenses:
Operating Expenses		149,244			131,146
Depreciation and Amortization		48,846			43,620
General and Administrative		16,292			16,364

		214,382			191,130

Operating Income		9,109			21,364
Other Income (Expense):
Interest Expense		(15,789	)		(15,956	)
Other, Net		(656	)		2,025

Income (Loss) Before Income Taxes		(7,336	)		7,433
Income Tax Benefit (Provision)		2,825			(2,558	)

Income (Loss) from Continuing Operations		(4,511	)		4,875
Loss from Discontinued Operation, Net of Taxes		(433	)		(389	)

Net Income (Loss)	$	(4,944	)	$	4,486

Basic Earnings (Loss) Per Share:
Income (Loss) from Continuing Operations	$	(0.05	)	$	0.05
Loss from Discontinued Operation		(0.01	)		—

Net Income (Loss)	$	(0.06	)	$	0.05

Diluted Earnings (Loss) Per Share:
Income (Loss) from Continuing Operations	$	(0.05	)	$	0.05
Loss from Discontinued Operation		(0.01	)		—

Net Income (Loss)	$	(0.06	)	$	0.05

Weighted Average Shares Outstanding:
Basic		88,002			88,859
Diluted		88,002			89,572

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

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Three Months Ended March 31,
	2009			2008
Cash Flows from Operating Activities:
Net Income (Loss)	$	(4,944	)	$	4,486
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:
Depreciation and Amortization		48,846			43,626
Stock-Based Compensation Expense		1,965			2,413
Deferred Income Taxes		(7,529	)		1,218
Provision for Doubtful Accounts Receivable		507			137
Amortization of Deferred Financing Fees		1,058			760
Amortization of Original Issue Discount		1,315			—
Gain on Insurance Settlement		(8,700	)		—
(Gain) Loss on Disposal of Assets		216			(45	)
Excess Tax Benefit from Stock-Based Arrangements		(2,686	)		(324	)
(Increase) Decrease in Operating Assets -
Accounts Receivable		51,925			13,802
Insurance Claims Receivable		(468	)		(42	)
Prepaid Expenses and Other		8,958			7,020
Increase (Decrease) in Operating Liabilities -
Accounts Payable		(19,226	)		(2,868	)
Insurance Note Payable		(11,126	)		(10,110	)
Other Current Liabilities		14,906			(16,712	)
Other Liabilities		2,953			1,297

Net Cash Provided by Operating Activities		77,970			44,658
Cash Flows from Investing Activities:
Acquisition of Assets		—			(230,045	)
Additions of Property and Equipment		(32,568	)		(45,813	)
Deferred Drydocking Expenditures		(4,009	)		(5,546	)
Proceeds from Sale of Marketable Securities		—			39,300
Insurance Proceeds Received		8,709			19,355
Proceeds from Sale of Assets, Net		1,960			2,047

Net Cash Used in Investing Activities		(25,908	)		(220,702	)
Cash Flows from Financing Activities:
Short-term Debt Repayments, Net		(2,455	)		—
Long-term Debt Repayments		—			(2,250	)
Excess Tax Benefit from Stock-Based Arrangements		2,686			324
Other		(11	)		—

Net Cash Provided by (Used in) Financing Activities		220			(1,926	)

Net Increase (Decrease) in Cash and Cash Equivalents		52,282			(177,970	)
Cash and Cash Equivalents at Beginning of Period		106,455			212,452

Cash and Cash Equivalents at End of Period	$	158,737		$	34,482

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

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(In thousands)

(Unaudited)


	Three Months Ended March 31,
	2009			2008
Net Income (Loss)	$	(4,944	)	$	4,486
Other Comprehensive Loss, Net of Taxes:
Changes Related to Hedge Transactions		(406	)		(7,026	)

Comprehensive Loss	$	(5,350	)	$	(2,540	)

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 10). At March 31, 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 an agreement with Mosvold Middle East Jackup Ltd. whereby it will market, manage and operate two 300 foot, high-specification new-build jackup drilling rigs. 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 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 March 31, 2009, Consolidated Statements of Operations, Consolidated Statements of Comprehensive Loss and Consolidated Statements of Cash Flows for the three months ended March 31, 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 months ended March 31, 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.

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 March 31,
	2009		2008
Mobilization revenue deferred	$	12,000	$	3,827
Mobilization expense deferred		132		3,398
Mobilization revenue recognized		3,916		1,970
Mobilization expense recognized		693		814

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

UNAUDITED

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 $3.5 million and $2.9 million for the three months ended March 31, 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. Drydock 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 March 31, 2009 and December 31, 2008, were $6.0 million and $6.5 million, respectively. Amortization expense for drydocking costs was $3.8 million and $5.1 million for the three months ended March 31, 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 March 31, 2009 and December 31, 2008 were $17.2 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 $1.1 million and $0.8 million for the three months ended March 31, 2009 and 2008, respectively.

Other Intangible Assets

As of March 31, 2009 and December 31, 2008, the Company had certain international customer contracts with a carrying value of $5.7 million and $7.2 million, net of accumulated amortization of $11.9 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 $1.5 million and $2.0 million for the three months ended March 31, 2009 and 2008, respectively. Future estimated amortization expense for the carrying amount of these intangible assets as of March 31, 2009 is expected to be as follows (in thousands):


Remainder of 2009	$	3,279
2010		1,814
2011		658
2012		—
2013		—

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 March 31, 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 three months ended March 31, 2008. There were no realized or unrealized gains or losses related to these securities in the three months ended March 31, 2009 and 2008.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

UNAUDITED

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 March 31,
	2009		2008
Denominator:
Weighted average basic shares		88,002		88,859
Add effect of stock equivalents		—		713

Weighted average diluted shares		88,002		89,572

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 3,855,630 and 909,404 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 months ended March 31, 2009 and 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. Discontinued Operation

During the fourth quarter of 2007, the Company sold its nine land rigs and related assets for gross proceeds of $107.0 million, which approximated the carrying value of these assets. The results of operations of the land rig operations are reflected in the Consolidated Statements of Operations as a discontinued operation for all periods presented.

Operating results and wind down costs of the land rigs were as follows (in thousands):


	Three Months Ended March 31,
	2009			2008
Revenues	$	222		$	892


Loss Before Income Taxes	$	(666	)	$	(599	)
Income Tax Benefit		233			210

Loss from Discontinued Operation, Net of Taxes	$	(433	)	$	(389	)

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

UNAUDITED

5. Debt

Debt is comprised of the following (in thousands):


	March 31, 2009		December 31, 2008
			(As Adjusted)
Term Loan Facility, due July 2013	$	886,500	$	886,500
3.375% Convertible Senior Notes due June 2038		136,067		134,752
7.375% Senior Notes, due April 2018		3,512		3,512
Foreign Overdraft Facility		—		2,455

Total Debt		1,026,079		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	$	1,017,079	$	1,015,764

Senior secured credit agreement

The Company has a $1,150.0 million credit facility, consisting of a $900.0 million term loan facility and a $250.0 million revolving credit facility. In connection with the credit facility, the Company entered into derivative instruments with the purpose of hedging future interest payments (See Note 6).

The availability under the revolving credit facility is to be used for working capital, capital expenditures and other general corporate purposes. This facility includes a diverse group of lenders with no single commitment greater than $30.0 million. No amounts were outstanding and $14.1 million in standby letters of credit had been issued under the revolving credit facility as of March 31, 2009. The remaining availability under this revolving credit facility was $235.9 million at March 31, 2009.

As of March 31, 2009, $886.5 million was outstanding on the term loan facility and the interest rate was 3.21%. The annualized effective rate of interest was 5.31% for the three months ended March 31, 2009 after giving consideration to derivative activities. The fair value of the amount outstanding on the term loan facility as of March 31, 2009 approximated $613.9 million.

The Company’s obligations under the credit agreement are secured by liens on several 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 Company’s liquidity is comprised of cash on hand, cash from operations and availability under the revolving credit facility. The Company also maintains a shelf registration statement covering the future issuance from time to time of various types of securities, including debt and equity securities. If the Company issues any debt securities off the shelf or otherwise incurs debt, it would be required to make prepayments on the term loan to the extent the debt is not permitted under the term loan. The Company currently believes it will have adequate liquidity to fund its operations for the foreseeable future. However, to the extent the Company does not generate sufficient cash from operations, it may need to raise additional funds through public or private debt or equity offerings to fund operations. Furthermore, the Company may need to raise additional funds through public or private debt or equity offerings or asset sales to avoid a breach of the financial covenants in its term loan agreement, to refinance its indebtedness or for general corporate purposes.

The Company’s term loan agreement requires that it meet certain financial ratios and tests, which it currently meets. However, if the market for the Company’s services does not improve or continues to decline over the near-term, it may not be able to meet the financial ratios and tests, which would result in an event of default under the credit agreement and 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 term loan facility and the revolving credit facility and in the foreclosure of liens on its assets or to refinance or seek an amendment of its senior secured credit agreement at materially increased cost. In the event of an amendment, the lenders may impose additional operational and financial restrictions which could further limit the Company’s ability to adequately respond to changing business conditions and from capitalizing on future business opportunities.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

UNAUDITED

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 12). 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 carrying amount of the equity component of the 3.375% Convertible Senior Notes was $30.1 million at both March 31, 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 $161.8 million, $25.7 million and $136.1 million, respectively, as of March 31, 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 March 31, 2009, the Company recognized $2.7 million, $1.7 million, net of tax, in interest expense, or $0.02 per diluted share, at an effective rate of 7.93%, of which $1.4 million related to the coupon rate of 3.375% and $1.3 million related to discount amortization. There is no interest expense related to the three months ended March 31, 2008 as the 3.375 % Convertible Senior Notes were not issued until June 3, 2008.

The Company determined it has the intent and ability to settle the principal amount of its 3.375% Convertible Senior Notes in 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 March 31, 2009 the number of conversion shares potentially issuable in relation to the 3.375% Convertible Senior Notes was 3.2 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. In accordance with FSP 14-1, the settlement consideration will be allocated to the extinguishment of the liability component in an amount equal to the fair value of that component immediately prior to extinguishment, with any 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. The remaining settlement consideration, if any, would be allocated to the reacquisition of the equity component and recognized as a reduction of Stockholders’ Equity (See Note 13).

The fair value of the 3.375% Convertible Senior Notes was $49.9 million at March 31, 2009.

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.

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

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

UNAUDITED

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, are recognized in the Consolidated Statements of Operations during the current period. The Company did not recognize a gain or loss due to hedge ineffectiveness in the Consolidated Statements of Operations for the three months ended March 31, 2009 and 2008 related to these hedging instruments. The Company expects to realize $18.5 million of unrealized loss in the Consolidated Statements of Operations over the next twelve months.

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 with a settlement date of April 1, 2009. The Company will receive a payment equal to the product of three-month LIBOR and the notional amount and will pay a fixed coupon of 5.307% on the notional amount over six quarters. The terms and settlement dates of the swap match 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 over three years, 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):


April 1, 2009-June 30, 2009	$	250,000
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):


Derivatives
As of March 31,			As of December 31,
2009			2008
Balance Sheet	Fair		Balance Sheet	Fair
Classification	Value		Classification	Value
Derivatives designated as hedging:
Interest rate contracts:
Other	$	7	Other	$	21

Total asset derivatives	$	7	Total asset derivatives	$	21

Other Current Liabilities	$	18,501	Other Current Liabilities	$	15,669
Other Liabilities		5,104	Other Liabilities		7,324

Total liability derivatives	$	23,605	Total liability derivatives	$	22,993

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	March 31,							March 31,
Hedging Relationships	2009			2008			II.	2009			2008
Interest rate contracts	$	(3,275	)	$	(7,383	)	Interest Expense	$	(4,414	)	$	(549	)


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

II.		Classification of Gain (Loss), Net of Taxes 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)

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

UNAUDITED

A Summary of the Changes in Other Comprehensive Loss, Net of Taxes (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 $1,545		2,869
Other comprehensive losses, net of tax of 1,764		(3,275	)

Cumulative unrealized loss, net of tax of $8,259, as of March 31, 2009	$	(15,338	)

The following table represents our derivative assets and liabilities measured at fair value on a recurring basis as of March 31, 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

March 31, 2009

(Level 1)

(Level 2)

(Level 3)

Technique

Derivative Assets

—

Derivative Liabilities

23,605

—

23,605

—

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:



Level 1	-	Inputs are quoted prices in active markets for identical assets or liabilities.

Level 2	-	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.

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)

7. 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 March 31, 2009, approximately 4.2 million shares were available for grant or award under the 2004 Plan.

During the three months ended March 31, 2009, the Company granted 1,753,125 stock options with a weighted average exercise price of $1.64. There were no grants of restricted stock during the three months ended March 31, 2009.

The Company recognized $2.0 million and $2.4 million in stock-based compensation expense during the three months ended March 31, 2009 and 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 months ended March 31, 2009 and 2008 was $2.7 million and $0.3 million, respectively.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

UNAUDITED

The unrecognized compensation cost related to the Company’s unvested stock options and restricted stock grants as of March 31, 2009 was $5.9 million and $8.2 million, respectively, and is expected to be recognized over a weighted-average period of 2.5 years and 1.4 years, respectively.

8. Supplemental Cash Flow Information

During the three months ended March 31, 2009 and 2008, the Company had non-cash activities related to its interest rate derivatives of $(0.4) million and $(7.0) million, respectively.


	Three Months Ended March 31,
	2009			2008
	(In thousands)
Cash paid during the period for:
Interest, net of capitalized interest of $333 and $804, respectively	$	(64	)	$	14,476
Income taxes		4,577			22,332

9. 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 March 31, 2009, assuming a Transocean stock price of $58.84 per share at the time of exercise of the compensatory options (the actual price of Transocean’s common stock at March 31, 2009), is approximately $2.9 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.

Our 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. We do not expect the ultimate resolution of this assessment to have a material impact on our 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.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

UNAUDITED

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 March 31, 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.

10. 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 (See Note 4) 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 March 31, 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. Fourteen of the jackup rigs are either working on short-term contracts or available. One is in the shipyard for maintenance and five are cold-stacked. 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 undergoing an upgrade in Namibia and one jackup rig cold-stacked in Trinidad.

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. Seven of the Company’s inland barges are either operating on short-term contracts or available and ten are cold-stacked.

Domestic Liftboats — includes 45 liftboats in the U.S. Gulf of Mexico. Forty-three are operating in the U.S. Gulf of Mexico and two 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 operating offshore Middle East. One liftboat is in a Middle Eastern shipyard undergoing refurbishment and is being marketed in the Middle East region.

Delta Towing — the Company’s Delta Towing business operates a fleet of 30 inland tugs, 15 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 March 31, 2009, 24 crew boats, 13 inland tugs and six offshore tugs were cold-stacked.

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 March 31, 2009
			Income (Loss)			Depreciation &
	Revenue		from Operations			Amortization
Domestic Offshore	$	59,181	$	(11,940	)	$	15,040
International Offshore		103,452		42,885			15,184
Inland		12,913		(16,244	)		7,993
Domestic Liftboats		22,610		3,019			5,049
International Liftboats		18,642		6,860			2,384
Delta Towing		6,693		(4,257	)		2,284

		223,491		20,323			47,934
Corporate		—		(11,214	)		912

Total Company	$	223,491	$	9,109		$	48,846


	Three Months Ended March 31, 2008
			Income (Loss)			Depreciation &
	Revenue		from Operations			Amortization
Domestic Offshore	$	62,447	$	(1,890	)	$	15,335
International Offshore		65,343		34,350			7,586
Inland		40,268		(1,940	)		9,660
Domestic Liftboats		15,944		(4,551	)		5,952
International Liftboats		18,291		8,148			1,984
Delta Towing		10,201		(492	)		2,569

		212,494		33,625			43,086
Corporate		—		(12,261	)		534

Total Company	$	212,494	$	21,364		$	43,620


	Total Assets
	March 31,		December 31,
	2009		2008
Domestic Offshore	$	930,269	$	930,988
International Offshore		977,456		955,911
Inland		187,409		217,477
Domestic Liftboats		141,062		148,307
International Liftboats		151,259		168,356
Delta Towing		78,475		92,371
Corporate		108,945		77,485

Total Company	$	2,574,875	$	2,590,895

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

UNAUDITED

11. Commitments and Contingencies

Legal Proceedings

The Company is involved in various claims and lawsuits in the normal course of business. As of March 31, 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 2008, 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 $2.9 billion; however, coverage for U.S. Gulf of Mexico named windstorm damage is subject to an annual aggregate limit on liability of $200.0 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 10% of insured values per occurrence for drilling rigs, and range from $0.3 million to $1.0 million per occurrence for liftboats, depending on 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 $10.0 million or the operational deductible for each U.S. Gulf of Mexico named windstorm. The Company is self-insured for 10% 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. 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 2008, in connection with the renewal of certain of its insurance policies, the Company entered into agreements to finance a portion of its annual insurance premiums. Approximately $35.2 million was financed through these arrangements. The interest rate on these notes was 4.42% and the notes were scheduled to mature in April 2009. However, these notes were fully paid as of March 31, 2009.

Surety Bonds and Unsecured Letters of Credit

The Company has $42.7 million outstanding related to surety bonds at March 31, 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 March 31, 2009.

12. Accounting Pronouncements

In April 2009, the FASB issued FSP SFAS 141R-1 Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies, (“FSP SFAS No. 141R-1”). This FSP amends and clarifies SFAS No. 141 (revised 2007), Business Combinations (“SFAS No. 141R”), to require that an acquirer recognize at fair value, at the acquisition date, an asset acquired or a liability assumed in a business combination that arises from a contingency if the acquisition-date fair value of that asset or liability can be determined during the measurement period. If the acquisition-date fair value of such an asset acquired or liability assumed cannot be determined, the acquirer should apply the provisions of SFAS 5, Accounting for Contingencies, to determine whether the contingency should be recognized at the acquisition date or after it. FSP SFAS 141R-1 is effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is after the beginning of the first annual reporting period beginning after December 15, 2008. In December 2007, the FASB issued SFAS No. 141R which replaces SFAS No. 141, Business Combinations (“SFAS No. 141”), and applies to all transactions and other events in which one entity obtains control over one or more other businesses. SFAS No. 141R requires an acquirer, upon initially obtaining control of another entity, to recognize the assets, liabilities and any non-controlling interest in the acquiree at fair value as of the acquisition date. Contingent consideration is required to be recognized and measured at fair value on the date of acquisition rather than at a later date when the amount of that consideration may be determinable beyond a reasonable doubt. SFAS No. 141R requires acquirers to expense acquisition-related costs as incurred rather than allocating such costs to the assets acquired and liabilities assumed, as was previously the case under SFAS No. 141. The Company adopted both FSP SFAS No. 141R-1 and SFAS No. 141R as of January 1, 2009 with no significant impact as there have been no acquisitions in the current year. However FSP SFAS No. 141R-1 and SFAS No. 141R may have a significant impact on the Company’s accounting for any business combinations closing in the future.

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

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

UNAUDITED

significantly higher 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).

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.

13. Subsequent Event

During 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 (See Note 5). In accordance with FSP 14-1, the settlement consideration will be allocated to the extinguishment of the liability component in an amount equal to the fair value of that component immediately prior to extinguishment, with any 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. The remaining settlement consideration, if any, would be allocated to the reacquisition of the equity component and recognized as a reduction of Stockholders’ Equity.

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 March 31, 2009 and for the three months ended March 31, 2009 and March 31, 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 April 23, 2009, our business segments included the following:

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. Fourteen of the jackup rigs are either working on short-term contracts or available for contracts. Six jackup rigs and all three submersibles are cold-stacked.

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. Four of the Company’s inland barges are either operating on short-term contracts or available and thirteen are cold-stacked.

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

Delta Towing — the Company’s Delta Towing business operates a fleet of 30 inland tugs, 15 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 April 23, 2009, 24 crew boats, 13 inland tugs and six offshore tugs are cold-stacked, and the remaining are working or available for contracts.

In January 2009, we entered into an agreement with Mosvold Middle East Jackup Ltd. whereby we will market, manage and operate two 300 foot, high-specification new-build jackup drilling rigs. 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 Ltd. 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 April 23, 2009 totaled approximately $647.3 million for our executed contracts. Approximately $246.4 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
	March 31,
	2009			2008
	(Dollars in thousands)
Domestic Offshore:
Number of rigs (as of end of period) (a)		23			28
Revenues	$	59,181		$	62,447
Operating expenses		54,413			47,772
Depreciation and amortization expense		15,040			15,335
General and administrative expenses		1,668			1,230

Operating loss	$	(11,940	)	$	(1,890	)

International Offshore:
Number of rigs (as of end of period)		12			11
Revenues	$	103,452		$	65,343
Operating expenses		44,141			22,792
Depreciation and amortization expense		15,184			7,586
General and administrative expenses		1,242			615

Operating income	$	42,885		$	34,350

Inland:
Number of barges (as of end of period) (a)		17			27
Revenues	$	12,913		$	40,268
Operating expenses		20,264			31,926
Depreciation and amortization expense		7,993			9,660
General and administrative expenses		900			622

Operating loss	$	(16,244	)	$	(1,940	)

Domestic Liftboats:
Number of liftboats (as of end of period)		45			47
Revenues	$	22,610		$	15,944
Operating expenses		14,134			13,894
Depreciation and amortization expense		5,049			5,952
General and administrative expenses		408			649

Operating income (loss)	$	3,019		$	(4,551	)

International Liftboats:
Number of liftboats (as of end of period)		20			18
Revenues	$	18,642		$	18,291
Operating expenses		8,107			7,220
Depreciation and amortization expense		2,384			1,984
General and administrative expenses		1,291			939

Operating income	$	6,860		$	8,148


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


	Three Months Ended
	March 31,
	2009			2008
Delta Towing:
Revenues	$	6,693		$	10,201
Operating expenses		8,185			7,542
Depreciation and amortization expense		2,284			2,569
General and administrative expenses		481			582

Operating loss	$	(4,257	)	$	(492	)

Total Company:
Revenues	$	223,491		$	212,494
Operating expenses		149,244			131,146
Depreciation and amortization expense		48,846			43,620
General and administrative expenses		16,292			16,364

Operating income		9,109			21,364
Interest expense		(15,789	)		(15,956	)
Other, net		(656	)		2,025

Income (loss) before income taxes		(7,336	)		7,433
Income tax benefit (provision)		2,825			(2,558	)

Income (loss) from continuing operations		(4,511	)		4,875
Loss from discontinued operation, net of taxes		(433	)		(389	)

Net income (loss)	$	(4,944	)	$	4,486

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


	Three Months Ended March 31, 2009
										Average
								Average		Operating
	Operating		Available					Revenue		Expense
	Days		Days		Utilization (1)			per Day (2)		per Day (3)
Domestic Offshore		864		1,384		62.4	%	$	68,497	$	39,316
International Offshore		795		847		93.9	%		130,128		52,115
Inland		298		723		41.2	%		43,332		28,028
Domestic Liftboats		2,439		3,870		63.0	%		9,270		3,652
International Liftboats		918		1,710		53.7	%		20,307		4,741


	Three Months Ended March 31, 2008
										Average
								Average		Operating
	Operating		Available					Revenue		Expense
	Days		Days		Utilization (1)			per Day (2)		per Day (3)
Domestic Offshore		1,098		2,002		54.8	%	$	56,873	$	23,862
International Offshore		654		709		92.2	%		99,913		32,147
Inland		938		1,547		60.6	%		42,930		20,637
Domestic Liftboats		1,600		4,186		38.2	%		9,965		3,319
International Liftboats		1,217		1,547		78.7	%		15,030		4,667


(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 $3.8 million and $2.0 million related to amortization of deferred mobilization revenue and contract specific capital expenditures reimbursed by the customer for the three months ended March 31, 2009 and 2008, respectively. Included in International Liftboats revenue is a total of $0.1 million related to amortization of deferred mobilization revenue for the three months ended March 31, 2009. There was no such revenue in the three months ended March 31, 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 $0.8 million related to amortization of deferred mobilization expenses for the three months ended March 31, 2009 and 2008, respectively.

For the Three Months Ended March 31, 2009 and 2008

Revenues

Consolidated. Total revenues for the three-month period ended March 31, 2009 (the “Current Quarter”) were $223.5 million compared with $212.5 million for the three-month period ended March 31, 2008 (the “Comparable Quarter”), an increase of $11.0 million, or 5.2%. This increase is further described below. Total revenues included $3.5 million in reimbursements from our customers for expenses paid by us in the Current Quarter compared with $2.9 million in the Comparable Quarter.

Domestic Offshore. Revenues for our Domestic Offshore segment were $59.2 million for the Current Quarter compared with $62.4 million for the Comparable Quarter, a decrease of $3.3 million, or 5.2%. This decrease resulted primarily from decreased operating days due to our cold stacking of rigs, which contributed $16.0 million of the decrease, partially offset by a $12.7 million increase due to higher average dayrates. Average utilization was 62.4% in the Current Quarter compared with 54.8% in the Comparable Quarter.

International Offshore. Revenues for our International Offshore segment were $103.5 million for the Current Quarter compared with $65.3 million for the Comparable Quarter, an increase of $38.1 million, or 58.3%, of which $19.8 million was due to higher average dayrates in the Current Quarter, and $18.3 million was due to increased operating days as a result of the commencement of the Hercules 260 in April 2008 and the associated revenue from the provision of marine services, as well as the commencement of the Hercules 208 in August 2008, Hercules 261 in December 2008 and Hercules 262 in January of 2009. These favorable increases were partially offset by the Hercules 156 rolling off contract and the Hercules 185 being in the shipyard for an upgrade during the Current Quarter. Average revenue per rig per day increased to $130,128 in the Current Quarter from $99,913 in the Comparable Quarter due to higher average dayrates for the Hercules 260, Hercules 261 and Hercules 258 in the Current Quarter.

Inland. Revenues for our Inland segment were $12.9 million in the Current Quarter compared with $40.3 million for the Comparable Quarter, a decrease of $27.4 million, or 67.9%. This decrease resulted from decreased operating days, as average revenue per rig per day was essentially the same in both periods. Available days declined 53% during the Current Quarter as compared to the Comparable Quarter due to our cold stacking plan. Furthermore, average utilization was 41.2% on fewer available days in the Current Quarter compared with 60.6% in the Comparable Quarter as demand in the segment declined.

Domestic Liftboats. Revenues for our Domestic Liftboats segment were $22.6 million for the Current Quarter compared with $15.9 million in the Comparable Quarter, an increase of $6.7 million, or 41.8%. This increase resulted primarily from increased operating days, which contributed $7.8 million of the increase, partially offset by a $1.1 million decrease due to lower average dayrates. Operating days increased to 2,439 in the Current Quarter from 1,600 in the Comparable Quarter. Average utilization also increased to 63.0% in the Current Quarter from 38.2% in the Comparable Quarter. Average revenue per vessel per day was $9,270 in the Current Quarter compared with $9,965 in the Comparable Quarter, a decrease of $695. The decrease in average revenue per vessel per day was due to lower dayrates, partially offset in part to mix of vessel class. Revenues for our Domestic Liftboats segment included $1.2 million and $0.7 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 $18.6 million for the Current Quarter compared with $18.3 million in the Comparable Quarter, an increase of $0.4 million, or 1.9%. This increase resulted from higher average dayrates, which contributed $6.5 million of the increase, significantly offset by fewer operating days, which contributed a $6.1 million decrease. Operating days decreased to 918 days in the Current Quarter from 1,217 days in the Comparable Quarter. Average revenue per liftboat per day was $20,307 in the Current Quarter compared with $15,030 in the Comparable Quarter, with average utilization of 53.7% in the Current Quarter compared with 78.7% in the Comparable Quarter. Approximately $3,679 of the increase in average revenue per vessel per day was due to mix of vessel class and approximately $1,598 was due to higher dayrates. Revenues for our International Liftboats segment included $1.3 million and $1.2 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 $6.7 million for the Current Quarter compared with $10.2 million in the Comparable Quarter, a decrease of $3.5 million, or 34.4%, due to decreased activity in both offshore and in the transition zone.

Operating Expenses

Consolidated. Total operating expenses for the Current Quarter were $149.2 million compared with $131.1 million in the Comparable Quarter, an increase of $18.1 million, or 13.8%. This increase is further described below.

Domestic Offshore. Operating expenses for our Domestic Offshore segment were $54.4 million in the Current Quarter compared with $47.8 million in the Comparable Quarter, an increase of $6.6 million, or 13.9%. The increase was driven primarily by costs related to labor, workers’ compensation, repairs and maintenance, including hurricane related repairs, and insurance, partially offset by a $6.3 million insurance settlement related to hurricane damage. Available days decreased to 1,384 in the Current Quarter from 2,002 in the Comparable Quarter due to our cold stacking of rigs. Average operating expenses per rig per day were $39,316 in the Current Quarter compared with $23,862 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 $44.1 million in the Current Quarter compared with $22.8 million in the Comparable Quarter, an increase of $21.3 million, or 93.7%. Available days increased to 847 in the Current Quarter from 709 in the Comparable Quarter. Average operating expenses per rig per day were $52,115 in the Current Quarter compared with $32,147 in the Comparable Quarter. 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 $20.3 million in the Current Quarter compared with $31.9 million in the Comparable Quarter, a decrease of $11.7 million, or 36.5%. Average operating expenses per rig per day were $28,028 in the Current Quarter compared with $20,637 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 $14.1 million in the Current Quarter compared with $13.9 million in the Comparable Quarter, an increase of $0.2 million, or 1.7%. Available days decreased to 3,870 in the Current Quarter from 4,186 in the Comparable Quarter 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 Quarter. Average operating expenses per vessel per day were $3,652 in the Current Quarter compared with $3,319 in the Comparable Quarter. This increase is primarily due to higher costs related to labor and repairs and maintenance.

International Liftboats. Operating expenses for our International Liftboats segment were $8.1 million for the Current Quarter compared with $7.2 million in the Comparable Quarter, an increase of $0.9 million, or 12.3%. Average operating expenses per liftboat per day were $4,741 in the Current Quarter compared with $4,667 in the Comparable Quarter due primarily to the costs associated with the start up of our Middle East operations.

Delta Towing. Operating expenses for our Delta Towing segment were $8.2 million for the Current Quarter compared with $7.5 million in the Comparable Quarter, an increase of $0.6 million, or 8.5%, due to higher equipment rentals in the Current Quarter.

Depreciation and Amortization

Depreciation and amortization expense in the Current Quarter was $48.8 million compared with $43.6 million in the Comparable Quarter, an increase of $5.2 million, or 12.0%. This increase resulted primarily from additional depreciation related to the Hercules 350, Hercules 262, and Hercules 261 purchased in 2008, as well as depreciation on the Hercules 208 and Hercules 260 which had not been placed in service in the Comparable Quarter. 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 intangible asset.

Other Income (Expense)

Other expense in the Current Quarter was $0.7 million compared with other income of $2.0 million in the Comparable Quarter, a decrease of $2.7 million. This decrease is primarily due to foreign currency exchange losses.

Income Tax Benefit (Provision)

Income tax benefit was $2.8 million on pre-tax loss of $7.3 million during the Current Quarter, compared to a provision of $2.6 million on pre-tax income of $7.4 million for the Comparable Quarter. The effective tax rate changed to a tax benefit of 38.5% in the Current Quarter from a tax provision of 34.4% in the Comparable Quarter. The change in the effective tax rate is due to the 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 April 23, 2009, the spot price for Henry Hub natural gas was $3.47 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 $4.61 per MMBtu on April 23, 2009, down from the high of $13.34 in July 2008. Along with the negative impact the financial crisis has had on demand, increases in onshore production in the U.S., driven by a significant increase in onshore drilling activity through mid 2008, have put downward pressure on natural gas prices. Growing deepwater production and potential increased deliveries of liquefied natural gas are also factors which have weighed on 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 have also declined significantly over the last several months, relative to the levels of the past several years. Since June 30, 2008, the price of WTI has declined from $140.00 to a multi-year low of $31.41 in December 2008 before rebounding slightly to $48.82 on April 23, 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 significant 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 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, 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 323 in April 2009.

Strong global demand for jackups over the past few years has encouraged newbuilds. According to ODS-Petrodata, as of April 23, 2009, 71 jackup rigs have been ordered by industry participants, national oil companies and financial investors for delivery through 2011. Given the recent financial crisis and the weakened outlook, a number of orders have already 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 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 73 currently, according to published industry sources.

While the overall current supply of jackup rigs in the U.S. Gulf of Mexico is 73, several of these rigs are either in the shipyard or cold-stacked, and the marketed supply is approximately 53. While the number of jackups located in the U.S. Gulf of Mexico has declined significantly over the last several years, current demand of 33 jackups as of April 23, 2009 is also considerably lower than three years ago when 88 jackups were operating in January 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 and increasing finding, development and lifting costs.

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 declining 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 could lead 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 5 years, despite a more than doubling of international exploration and production capital spending over this period, leads us to believe that production would quickly respond to a decline 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 other onshore basins. As of April 23, none of our seventeen inland barges had contracts for work. While we are likely to have some 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 17 new liftboats were delivered for work in the U.S. Gulf of Mexico over the past two years, 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 are expected only to continue into the first quarter of 2009. Dayrates once again increased, responding to the tightened supply and demand balance but are already declining as the preponderance of the higher priority repair work has been completed.

As of April 2009, we believe that there were another 11 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. We recently mobilized two of our liftboats to the Middle East from the U.S. Gulf of Mexico and are actively marketing the vessels for use on projects with short and long-term contract opportunities. 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

Sources and Uses of Cash

Sources and uses of cash for the three-month period ended March 31, 2009 are as follows (in millions):


Net Cash Provided by Operating Activities:	$	78.0
Net Cash Provided by (Used in) Investing Activities:
Additions of Property and Equipment		(32.6	)
Deferred Drydocking Expenditures		(4.0	)
Insurance Proceeds Received		8.7
Proceeds from Sale of Assets, Net		2.0

Total		(25.9	)
Net Cash Provided by (Used in) Financing Activities:
Short-term Debt Repayments, Net		(2.5	)
Excess Tax Benefit from Stock-Based Arrangements		2.7

Total		0.2

Net Increase in Cash and Cash Equivalents	$	52.3

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 be required to make prepayments on our term loan to the extent the debt is not permitted under the 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. 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 term loan agreement, to refinance our indebtedness or for general corporate purposes.

Our term loan agreement requires that we meet certain financial ratios and tests, which we currently meet. However, if the market for our services does not improve or continues to decline over the near-term, we may not be able to meet the financial ratios and tests, which would result in an event of default under our credit agreement and could prevent us from borrowing under our 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 our term loan facility and our revolving credit facility and in the foreclosure of liens on our assets or to refinance or seek an amendment of our senior secured credit agreement at materially increased cost. In the event of an amendment, the lenders may impose additional operational and financial restrictions which could further limit our ability to adequately respond to changing business conditions and from capitalizing on future business opportunities.

Cash Requirements and Contractual Obligations

Debt

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

We currently have a $1,150.0 million credit facility, consisting of a $900.0 million term loan and a $250.0 million revolving credit facility. The availability under the revolving credit facility is to be used for working capital, capital expenditures and other general corporate purposes. 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. The facility includes a diverse group of lenders with no single commitment greater than $30.0 million. No amounts were outstanding and $14.1 million in stand-by letters of credit

had been issued under the revolving credit facility as of March 31, 2009. The remaining availability under this revolving credit facility was $235.9 million at March 31, 2009.

As of March 31, 2009, $886.5 million was outstanding on the term loan facility and the interest rate was 3.21%. The annualized effective interest rate was 5.31% for the three months ended March 31, 2009 after giving consideration to derivative activity. The fair value of the amount outstanding on the term loan facility as of March 31, 2009 approximated $613.9 million.

The revolving credit facility and our term loan are governed by a credit agreement that includes customary events of default and two financial covenants that are tested quarterly: a fixed charge coverage ratio and a leverage ratio. Both financial covenants incorporate our last 12 months of EBITDA, as defined in the credit agreement. We were in compliance with these covenants at March 31, 2009. However, if the market for our services does not improve or continues to decline over the near-term, we may not be able to meet the financial ratios and tests, which would result in an event of default under our credit agreement and could prevent us from borrowing under our 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 our term loan facility and our revolving credit facility and in the foreclosure of liens on our assets. 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, liens, investments 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 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 with a settlement date of April 1, 2009. We receive an interest rate of three-month LIBOR and pay a fixed coupon of 5.307% 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 over three years, 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 these hedging instruments resulted in an increase in derivative liabilities of $0.6 million during the three months ended March 31, 2009. We had net unrealized losses on hedge transactions of $0.4 million, net of tax of $0.2 million, and $7.0 million, net of tax of $3.8 million for the three months ended March 31, 2009 and 2008, respectively. We did not recognize a gain or loss due to hedge ineffectiveness in the Consolidated Statements of Operations for the three months ended March 31, 2009 and 2008 related to these hedging instruments. In addition, our interest expense was increased by $4.4 million and $0.5 million during the three months ended March 31, 2009 and 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. The interest on the 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, we repurchased $88.2 million aggregate principal amount of the 3.375% Convertible Senior Notes for a cost of $44.8 million. The carrying amount and fair value of the 3.375% Convertible Senior Notes was $136.1 million and $49.9 million, respectively, at March 31, 2009.

During April 2009, we repurchased $20.0 million aggregate principal amount of the 3.375% Convertible Senior Notes for a cost of $6.1 million. In accordance with FSP 14-1, the settlement consideration will be allocated to the extinguishment of the liability component in an amount equal to the fair value of that component immediately prior to extinguishment, with any 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. The remaining settlement consideration, if any, would be 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.

In 2008, in connection with the renewal of certain of our insurance policies, we entered into agreements to finance a portion of our annual insurance premiums. Approximately $35.2 million was financed through these arrangements. However, all amounts due related to these notes were paid during the three months ended March 31, 2009. The interest rate on these notes was 4.42% and the notes were scheduled to mature in April 2009.

Our principal insurance policy period ends in May 2009. We are currently in the process of renewing the policy. Competitors with assets in the Gulf of Mexico that have completed their renewals in 2009 are experiencing a difficult market environment with insurance underwriters. As a result of damage sustained by the oil and natural gas industry from hurricanes and other named wind storms in the U.S. Gulf of Mexico over the last few years, insurance underwriters have significantly reduced the availability of insurance for U.S. Gulf of Mexico assets with respect to weather-related damage and have significantly increased the cost of obtaining such insurance. In addition, insurers are requiring higher deductibles and limiting the amount of insurance proceeds that are available per occurrence and in the aggregate, particularly for damage from a named wind storm. As a result, we anticipate that insurance costs for damage as result of windstorms in the U.S. Gulf of Mexico may increase significantly after the end of our current policy period and/or that the amount of our coverage will be significantly reduced. We may determine that the limits and costs of such insurance are not reasonable and we may, therefore, determine to self insure a large portion or all of our U.S. Gulf of Mexico related risks.

Capital Expenditures

We expect to spend approximately $60 million on capital expenditures, excluding asset acquisitions, during the remainder of 2009. Planned capital expenditures include refurbishment and an upgrade to certain of our rigs, liftboats, and other marine vessels.

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.

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. 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. If we do complete any such acquisitions, we may make significant capital commitments for such purposes. Any such transactions could involve the payment by us of a substantial amount of cash. We would likely fund the cash portion of such transactions, if any, through cash balances on hand, the incurrence of additional debt, or sales of assets, equity interests or other securities or a combination thereof. 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, we experience poor results in our operations or we fail to meet covenants under our term loan facility.

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. During the first three months of 2009, there were no material changes outside the ordinary course of business in the specified contractual obligations.

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

Off-Balance Sheet Arrangements

Guarantees

Our obligations under the credit facility are secured by liens on several 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 March 31, 2009, we had $56.9 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 $42.7 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.

Accounting Pronouncements

See Note 12 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 for the units;

	•		the correlation between demand for our rigs and our liftboats and our earnings and customers’ expectations of energy prices;

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

	•		expected completion times for our refurbishment and upgrade projects;

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

	•		our plans regarding increased international operations;

	•		expected useful lives of our rigs and liftboats;

	•		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 improvements in offshore drilling activity and dayrates, market conditions, demand for our rigs and liftboats, operating revenues, operating and maintenance expense, 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 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 and other oil and natural gas producing regions, or further acts of terrorism in the United States, or elsewhere;

	•		the impact of governmental laws and regulations;

	•		the adequacy 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;

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

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

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 March 31, 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 and fair value of the 3.375% Convertible Senior Notes was $136.1 million and $49.9 million, respectively.

As of March 31, 2009, the interest rate for the $886.5 million outstanding under the term loan was 3.21%. If the interest rate averaged 1% more for 2009 than the rates as of March 31, 2009, annual interest expense would increase by approximately $8.9 million. This sensitivity analysis assumes there are no changes in our financial structure and excludes the impact of our hedging activities. The fair value of the amount outstanding on the term loan facility as of March 31, 2009 approximated $613.9 million.

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 $4.4 million and $0.5 million for the three months ended March 31, 2009 and 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 with a settlement date of April 1, 2009. We also entered into a zero cost LIBOR collar on $300.0 million of term loan principal over three years, 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):


April 1, 2009-June 30, 2009	$	250,000
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 March 31, 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 11 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

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.

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

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)

January 1-31, 2009

—

N/A

February 1-28, 2009

13,451

2.89

N/A

March 1-31, 2009

481

1.93

N/A

Total

13,932

2.85

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 6. EXHIBITS

10.1		Form of Stock Option Award Agreement (incorporated by reference to Exhibit 10.1 to Hercules’ Current Report on Form 8-K dated March 3, 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: April 28, 2009

INDEX TO EXHIBITS


Exhibit Number		Description

10.1		Form of Stock Option Award Agreement (incorporated by reference to Exhibit 10.1 to Hercules’ Current Report on Form 8-K dated March 3, 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

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