UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

 

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

For the quarterly period ended March 31, 2008

or

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.

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     x     NO     ¨

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

Large accelerated filer x				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     ¨     NO     x

     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 28, 2008
		88,862,361

 

HERCULES OFFSHORE, INC.

INDEX

		Page No.
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of March 31, 2008 and December 31, 2007			2
Consolidated Statements of Operations for the three months ended March 31, 2008 and March 31, 2007			3
Consolidated Statements of Cash Flows for the three months ended March 31, 2008 and March 31, 2007			4
Consolidated Statements of Comprehensive Income (Loss) for the three months ended March 31, 2008 and March 31, 2007			5
Notes to Unaudited Consolidated Financial Statements			6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			19
Item 3. Quantitative and Qualitative Disclosures about Market Risk			32
Item 4. Controls and Procedures			33
PART II. OTHER INFORMATION
Item 1. Legal Proceedings			33
Item 1A. Risk Factors			33
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			34
Item 6. Exhibits			34
Signatures			35
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO and CFO pursuant to Section 906

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

		March 31,				December 31,
		2008				2007
		(Unaudited)
ASSETS
Current Assets:
Cash and Cash Equivalents		$	34,482			$	212,452
Marketable Securities			—				39,300
Accounts Receivable, Net			207,724				221,663
Insurance Claims Receivable			10,880				43,342
Supplies			2,489				2,494
Prepaids			21,595				31,417
Current Deferred Tax Asset			17,551				17,551
Other			23,909				23,565
			318,630				591,784
Property and Equipment, Net			2,286,665				2,060,224
Goodwill			942,138				940,241
Other Assets, Net			52,583				50,290
		$	3,600,016			$	3,642,539
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term Debt and Current Portion of Long-term Debt		$	21,593			$	21,653
Insurance Note Payable			6,821				16,931
Accounts Payable			102,659				105,527
Accrued Liabilities			74,216				80,138
Taxes Payable			2,148				23,006
Other Current Liabilities			16,766				16,845
			224,203				264,100
Long-term Debt, Net of Current Portion			887,762				890,013
Other Liabilities			26,996				19,518
Deferred Income Taxes			449,464				457,475
Commitments and Contingencies
Stockholders’ Equity:
Common Stock, $0.01 Par Value; 200,000 Shares Authorized; 88,881 and 88,876 Shares Issued, Respectively; 88,861 and 88,857 Shares Outstanding, Respectively			889				889
Capital in Excess of Par Value			1,734,622				1,731,882
Treasury Stock, at Cost, 21 Shares and 19 Shares, Respectively			(624	)			(582	)
Accumulated Other Comprehensive Loss			(15,143	)			(8,117	)
Retained Earnings			291,847				287,361
			2,011,591				2,011,433
		$	3,600,016			$	3,642,539

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

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

		Three Months Ended March 31,
		2008				2007
Revenues		$	213,386			$	110,464
Costs and Expenses:
Operating Expenses			132,809				41,527
Depreciation and Amortization			43,626				11,730
General and Administrative			16,364				9,163
			192,799				62,420
Operating Income			20,587				48,044
Other Income (Expense):
Interest Expense			(15,960	)			(2,090	)
Other, Net			2,207				1,275
Income Before Income Taxes			6,834				47,229
Income Tax Provision			(2,348	)			(13,838	)
Net Income		$	4,486			$	33,391
Earnings Per Share:
Basic		$	0.05			$	1.04
Diluted		$	0.05			$	1.03
Weighted Average Shares Outstanding:
Basic			88,859				31,975
Diluted			89,572				32,471

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

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

		Three Months Ended March 31,
		2008				2007
Cash Flows from Operating Activities:
Net Income		$	4,486			$	33,391
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Depreciation and Amortization			43,626				11,730
Stock-Based Compensation Expense			2,413				1,151
Deferred Income Taxes			1,218				3,261
Amortization of Deferred Financing Fees			760				180
Gain on Disposal of Assets			(45	)			(296	)
Excess Tax Benefit from Stock-based Arrangements			(324	)			(715	)
(Increase) Decrease in Operating Assets—
Accounts Receivable			13,939				5,900
Insurance Claims Receivable			(42	)			(3,626	)
Prepaid Expenses and Other			7,020				3,243
Increase (Decrease) in Operating Liabilities—
Accounts Payable			(2,868	)			6,383
Insurance Note Payable			(10,110	)			(6,058	)
Other Current Liabilities			(16,712	)			(1,700	)
Other Liabilities			1,297				(209	)
Net Cash Provided by Operating Activities			44,658				52,635
Cash Flows from Investing Activities:
Acquisition of Assets			(230,045	)			—
Investment in Marketable Securities			—				(34,000	)
Proceeds from Sale of Marketable Securities			39,300				—
Additions of Property and Equipment			(45,813	)			(13,719	)
Deferred Drydocking Expenditures			(5,546	)			(5,486	)
Insurance Proceeds Received			19,355				—
Proceeds from Sale of Assets, Net			2,047				610
Net Cash Used in Investing Activities			(220,702	)			(52,595	)
Cash Flows from Financing Activities:
Long-term Debt Repayments			(2,250	)			(350	)
Proceeds from Exercise of Stock Options			—				960
Excess Tax Benefit from Stock-Based Arrangements			324				715
Net Cash Provided by (Used in) Financing Activities			(1,926	)			1,325
Net Increase (Decrease) in Cash and Cash Equivalents			(177,970	)			1,365
Cash and Cash Equivalents at Beginning of Period			212,452				72,772
Cash and Cash Equivalents at End of Period		$	34,482			$	74,137
Cash Paid for Interest		$	14,476			$	2,196
Cash Paid for Taxes		$	22,332			$	8,273

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

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

		Three Months Ended
		March 31,
		2008				2007
Net Income		$	4,486			$	33,391
Other Comprehensive Loss, Net of Tax:
Unrealized Losses on Hedge Transactions			(7,026	)			(160	)
Comprehensive Income (Loss)		$	(2,540	)		$	33,231

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

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

1. General

     Hercules Offshore, Inc. provides shallow-water drilling and marine services to the oil and 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 Other segments (See Note 10). On July 11, 2007, the Company completed the acquisition of TODCO (See Note 3), a provider of contract oil and gas drilling services in the U.S. Gulf of Mexico and international locations. TODCO owned and operated 24 jackup rigs, 27 barge rigs, three submersible rigs, nine land rigs, one platform rig and a fleet of marine support vessels. During the fourth quarter of 2007, the Company sold the nine land rigs and related assets (See Note 4). At March 31, 2008, the Company owned a fleet of 35 jackup rigs, 27 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 third parties. The Company currently operates in nine countries on four continents.

     The consolidated financial statements of Hercules Offshore, Inc. and its majority owned subsidiaries (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, 2008, Consolidated Statements of Operations, Consolidated Statements of Comprehensive Income (Loss) and Consolidated Statements of Cash Flows for the three months ended March 31, 2008 and 2007. 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, 2007 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, 2008 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 and goodwill, 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 over the term of the related drilling contract. Amounts related to mobilization fees are summarized below (in thousands):

		Three Months Ended March 31,
		2008				2007
Mobilization revenue deferred		$	3,827			$	—
Mobilization expense deferred			3,398				—
Mobilization revenue recognized			1,970				1,755
Mobilization expense recognized			814				1,171

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 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 $2.9 million and $3.2 million for the three months ended March 31, 2008 and 2007, respectively.

 Other Assets

     Other assets consist of drydocking costs for marine vessels, other intangible assets, deferred costs, financing fees, derivative assets, 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, 2008 and December 31, 2007 were $8.6 million and $8.2 million, respectively. Amortization expense for drydocking costs was $5.1 million and $4.1 million for the three months ended March 31, 2008 and 2007, respectively.

     Financing fees are deferred and amortized over the life of the applicable debt investment. Unamortized deferred financing fees at March 31, 2008 and December 31, 2007 were $15.5 million and $16.2 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 $0.8 million and $0.2 million for the three months ended March 31, 2008 and 2007, respectively.

 Other Intangible Assets

     In connection with the acquisition of TODCO (See Note 3), the Company allocated $17.6 million in value to certain international customer contracts. The estimated fair value of these acquired contracts is based on preliminary valuations and is subject to change when final valuations are obtained. These contracts are being amortized over the life of the contracts. As of March 31, 2008, the customer contracts had a carrying value of $12.9 million, net of accumulated amortization of $4.7 million, and are included in Other Assets, Net on the Consolidated Balance Sheet.

     Amortization expense was $2.0 million for the three months ended March 31, 2008. Future estimated amortization expense for the carrying amount of intangible assets as of March 31, 2008 is expected to be as follows (in thousands):

Remainder of 2008		$	5,897
2009			4,658
2010			1,691
2011			607
2012			—

 Cash and Cash Equivalents and Marketable Securities

     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, 2008, the Company had no investments in marketable securities. 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.

     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. 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.

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, except per share data):

		Three Months Ended March 31,
		2008				2007
Numerator:
Net income		$	4,486			$	33,391
Denominator:
Weighted average basic shares			88,859				31,975
Add effect of stock equivalents			713				496
Weighted average diluted shares			89,572				32,471
Basic earnings per share		$	0.05			$	1.04
Diluted earnings per share		$	0.05			$	1.03

     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. Stock equivalents of 909,404 and 8,333 were anti-dilutive and are excluded from the calculation of the dilutive effect of stock equivalents for the diluted earnings per share calculation for the three months ended March 31, 2008 and 2007, respectively.

3. Asset Acquisition and Business Combination

     In the first quarter of 2008, the Company entered into a definitive agreement to purchase three jackup drilling rigs and related equipment for $320.0 million. The purchase of two of the jackup drilling rigs and related equipment for $220.0 million was completed in the first quarter with cash on hand. In addition, during the first quarter of 2008 the Company paid a deposit of $10.0 million, which is included in Other Assets, Net on the Consolidate Balance Sheets, to be applied to the purchase of the third jackup rig upon closing. Both the $220.0 million cash paid for the two jackup rigs and the $10.0 million deposit are included in Acquisition of Assets on the Consolidated Statements of Cash Flows.

     On July 11, 2007, the Company acquired TODCO for total consideration of approximately $2,397.8 million, consisting of $925.8 million in cash and 56.6 million shares of common stock. The fair value of the shares issued was determined for accounting purposes using an average price of $25.99, which represented the average closing price of the Company’s stock for a period before and after the date of the merger agreement with TODCO. In addition, the Company incurred additional consideration in the amount of $41.6 million related primarily to transaction related costs, cash payments to non-continuing employees and the conversion of certain employee equity awards. The results of TODCO are included in the Company’s results from the date of acquisition.

     The total consideration was allocated to TODCO’s net tangible and identifiable intangible assets based on their estimated fair values. The excess of the purchase price over the net assets was recorded as goodwill. The preliminary allocation of the purchase price was based on preliminary valuations and estimates, and assumptions are subject to change upon the receipt and management’s review of the final valuations. The final valuation of net assets is expected to be completed no later than one year from the acquisition date.

4. Dispositions

     During the fourth quarter of 2007, the Company sold the nine land rigs and related assets purchased in the TODCO acquisition for gross proceeds of $107.0 million, which approximated the carrying value of these assets. In addition, during 2007, the Company sold several marine support vessels purchased in the TODCO acquisition for gross proceeds of $3.2 million.

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

5. Debt

     Debt is comprised of the following (in thousands):

		March 31, 2008				December 31, 2007
Term Loan Facility, due July 2013		$	893,250			$	895,500
9.5% Senior Notes, due December 2008			10,371				10,432
7.375% Senior Notes, due April 2018			3,513				3,513
6.95% Senior Notes, due April 2008			2,221				2,221
Foreign Line of Credit			—				—
Total Debt			909,355				911,666
Less Short-term Debt and Current Portion of Long-term Debt			21,593				21,653
Total Long-term Debt, Net of Current Portion		$	887,762			$	890,013

Senior secured credit agreement

     In connection with the July 2007 acquisition of TODCO (See Note 3), the Company entered into a new $1,050.0 million credit facility, consisting of a $900.0 million term loan facility and a $150.0 million revolving credit facility. The proceeds from the term loan were used, together with cash on hand to finance the cash portion of the Company’s acquisition of TODCO, to repay amounts under TODCO’s senior secured credit facility outstanding at the closing of the facility and to make certain other payments in connection with the Company’s acquisition of TODCO. In connection with the credit facility, the Company entered into derivative instruments with the purpose of hedging future interest payments (See Note 6).

          On April 28, 2008, the Company and certain of its subsidiaries entered into an agreement with the revolving lenders under its existing credit facility and certain new lenders to increase the maximum amount of the Company’s revolving credit facility from $150.0 million to $250.0 million. The increased availability under the facility is to be used for working capital, capital expenditures and other general corporate purposes.

     No amounts were outstanding and $29.0 million in standby letters of credit had been issued under the revolving credit facility as of March 31, 2008. The remaining availability under this revolving credit facility was $121.0 million at March 31, 2008.

     As of March 31, 2008, $893.3 million was outstanding on the term loan facility and the interest rate was 4.45%. The annualized effective rate of interest was 6.82% for the three months ended March 31, 2008 after giving consideration to derivative activities.

     The credit agreement contains financial covenants that are tested quarterly relating to leverage and fixed charge coverage. 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. The credit agreement contains customary events of default. The Company was in compliance with these covenants at March 31, 2008.

Senior notes and other debt

     In connection with the TODCO acquisition in July 2007, the Company assumed senior notes and an unsecured line of credit with a bank in Venezuela. The senior notes include 6.95% Senior Notes due in April 2008, 7.375% Senior Notes due in April 2018, and 9.5% Senior Notes due in December 2008 (collectively, “Senior Notes”). The fair market value of the Senior Notes at March 31, 2008 was approximately $2.2 million, $3.5 million and $9.9 million, respectively, based on the most recent market valuations. The line of credit is designed to manage local currency liquidity in Venezuela. The maximum amount available to be drawn is 6.0 million Bolivares Fuertes ($2.8 million at the exchange rate at March 31, 2008), and there were no amounts outstanding at March 31, 2008.

6. Derivative Instruments and Hedging

     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 caps to cap the interest rate on variable rate debt.

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

     In July 2007, the Company entered into derivative instruments with the purpose of hedging future interest payments on its term loan facility. 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. 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 payment dates of the collar match those of the term loan.

     The following table provides the scheduled reduction in notional amounts related to the interest rate swap (in thousands):

April 1, 2008-June 30, 2008		$	300,000
July 1, 2008-September 30, 2008			200,000
October 1, 2008-December 31, 2008			100,000
January 1, 2009-March 31, 2009			50,000

     These hedge transactions are being accounted for as cash flow hedges under Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities (an amendment of FASB Statement No. 133), and SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. The fair value of these hedging instruments is included in Other Assets, Net and Other Liabilities and the cumulative unrealized gain/loss, net of tax, is included in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets. 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, 2008 and 2007 related to these hedging instruments.

A summary of amounts relating to derivative instruments is provided below (in thousands):

		March 31,				December 31,
		2008				2007
Fair value included in Other Assets, Net		$	142			$	322
Fair value included in Other Liabilities			23,440				12,809
Cumulative unrealized loss, net of tax of 8,155 and 4,371, respectively included in Accumulated Other Comprehensive Loss			(15,143	)			(8,117	)

		Recognized Gain (Loss) in
		Consolidated Statements of
		Operations for the Three Months
		Ended March 31,
		2008				2007
Realized gains (losses) included in Interest Expense		$	(549	)		$	207

     The Company adopted SFAS No. 157 on January 1, 2008 (See Note 12), which requires enhanced disclosures about assets and liabilities measured at fair value, including our derivative instruments.

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

     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)

     The following table represents our derivative assets and liabilities measured at fair value on a recurring basis as of March 31, 2008 (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, 2008				(Level 1)				(Level 2)				(Level 3)				Technique
Derivative Assets		$	142			$	—			$	142			$	—				A
Derivative Liabilities		$	23,440			$	—			$	23,440			$	—				A

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. In July 2007, the Company’s stockholders approved an increase in the shares available for grant or award under the 2004 Plan by an additional 6.8 million shares to a total of 10.3 million shares. On February 15, 2008, the Company filed a registration statement to register the additional 6.8 million shares issuable under the 2004 plan. At March 31, 2008, approximately 6.4 million shares were available for grant or award under the 2004 Plan.

     During the three months ended March 31, 2008, the Company granted 365,300 stock options with a weighted average exercise price of $25.64 and 339,755 restricted stock awards with a weighted average grant-date fair value per share of $25.59.

     The Company recognized $2.4 million and $1.2 million in stock-based compensation expense during the three months ended March 31, 2008 and 2007, 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, 2008 and 2007 was $0.3 million and $0.7 million, respectively.

     The unrecognized compensation cost related to the Company’s unvested stock options and restricted share grants as of March 31, 2008 was $8.4 million and $13.4 million, respectively, and is expected to be recognized over a weighted-average period of 1.7 years and 2.2 years, respectively.

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

     There were no stock option exercises during the three months ended March 31, 2008.

8. Supplemental Cash Flow Information

     The following summarizes the Company’s non-cash activities for the following periods shown (in thousands):

		Three Months Ended March 31,
		2008				2007
Change in fair value of derivative instruments		$	7,026			$	160

9. Income Tax

     The Company, as successor to TODCO, and TODCO’s former parent Transocean Inc. 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 required the Company to make an acceleration payment to Transocean upon completion of the TODCO acquisition as a result of the deemed utilization of TODCO’s pre-IPO tax benefits. Subsequent to the completion of the TODCO acquisition, the Company paid $116.0 million to Transocean in the second half of 2007 in satisfaction of those obligations. The basis of determination for the change in control payment is subject to a differing interpretation by Transocean. While the Company strongly believes it has complied with the requirements of the tax sharing agreement in computing the amount of the acceleration payment, at this time, the Company cannot estimate whether additional payments will be due related to the acceleration payment.

     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, 2008, assuming a Transocean stock price of $135.20 per share at the time of exercise of the compensatory options (the actual price of Transocean’s common stock at March 31, 2008), is approximately $23.4 million. 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.

     In the first quarter of 2008, the Nigerian Federal Inland Revenue Service (“FIRS”) commenced an audit of the 2006 tax return for one of the Company’s subsidiaries. The audit is currently underway and the Company has not yet received an assessment. Thus, the Company cannot estimate whether the settlement of any assessment would have a material effect on its financial statements.

     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 other deductions. The Company intends to vigorously contest the assessment. While the Company cannot predict or provide assurance as to the ultimate outcome, it does not believe the outcome of this assessment will have a material effect on its financial statements. Depending on the ultimate outcome of the 2004 assessment, the Company anticipates that the Mexican tax authorities could make similar assessments for other open tax years.

     In December 2002, TODCO received an assessment for corporate income taxes from SENIAT, the national Venezuelan tax authority, of 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 2000. 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. 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. The Company has not yet received any proposed adjustments from SENIAT

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

arising from this audit. The Company believes it is owed indemnity from TODCO’s former parent under the tax sharing agreement for any losses it incurs as a result of these legal proceedings.

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) Other. Our Other segment includes Delta Towing and the wind down costs associated with our land rigs sold in December 2007 (See Note 4). The Company eliminates inter-segment revenue and expenses, if any. The following describes the Company’s reporting segments as of March 31, 2008:

     Domestic Offshore – operates 25 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.

     International Offshore – operates ten 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 the following international locations: Qatar, Angola, Cameroon and Trinidad. The Company has one jackup rig in India undergoing contract preparation work, one jackup rig in India undergoing a drilling capability upgrade and one jackup rig in transit to Saudi Arabia that will undergo contract preparation work. This segment operates two jackup rigs and one platform rig in Mexico. In addition, this segment has one jackup rig currently undergoing reactivation in Southeast Asia.

     Inland – operates a fleet of 12 conventional and 15 posted barge rigs that operate inland in marshes, rivers, lakes and shallow bay or coastal waterways along the U.S. Gulf Coast.

     Domestic Liftboats – operates 47 liftboats in the U.S. Gulf of Mexico.

     International Liftboats – operates 18 liftboats offshore West Africa, including five liftboats owned by a third party and one undergoing refurbishment.

     Other – the Company’s Delta Towing business operates a fleet of 33 inland tugs, 17 offshore tugs, 34 crew boats, 46 deck barges, 17 shale barges and four spud barges along and in the U.S. Gulf of Mexico. In December 2007, the Company sold its land rig operations which included one land rig in Trinidad, two land rigs in the United States and six land rigs in Venezuela.

     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, 2008
						Income (Loss)				Depreciation
						from				&
		Revenue				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
Other			11,093				(1,269	)			2,575
			213,386				32,848				43,092
Corporate			—				(12,261	)			534
Total Company		$	213,386			$	20,587			$	43,626

		Three Months Ended March 31, 2007
						Income				Depreciation
						from				&
		Revenue				Operations				Amortization
Domestic Offshore		$	42,831			$	24,765			$	2,561
International Offshore			20,876				11,595				1,368
Inland			—				—				—
Domestic Liftboats			32,703				12,455				6,070
International Liftboats			14,054				4,459				1,704
Other			—				—				—
			110,464				53,274				11,703
Corporate			—				(5,230	)			27
Total Company		$	110,464			$	48,044			$	11,730

		Total Assets
		March 31, 2008				December 31, 2007
Domestic Offshore		$	1,475,674			$	1,504,548
International Offshore			934,654				681,742
Inland			629,908				646,120
Domestic Liftboats			164,473				186,568
International Liftboats			130,346				149,813
Other			208,831				229,979
Corporate			56,130				243,769
Total Company		$	3,600,016			$	3,642,539

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, 2008, management did not believe any accruals were necessary in accordance with SFAS No. 5, Accounting for Contingencies.

     In March 2007, two TODCO stockholder lawsuits were filed in the District Court of Harris County, Texas, both alleging that the members of the TODCO board of directors (which include three of the Company’s current directors) breached their fiduciary duties in connection with TODCO’s merger with a subsidiary of the Company. The first lawsuit, Frank Donio v. Jan Rask, et al. , then pending in the 269^th Judicial District Court of Harris County, Texas, Cause No. 2007-16357, is a purported stockholder class action suit against the TODCO directors and contains claims for breach of fiduciary duty. The second lawsuit, Robert Foster v. Jan Rask, et al. , then pending in the 333^rd Judicial District Court of Harris County, Texas, Cause No. 2007-16397, was a stockholder derivative action purportedly filed on behalf of TODCO against the TODCO directors (which includes three of the Company’s current directors) and the Company, and contained claims for breach of fiduciary duties of loyalty, due care, candor, good faith and/or fair dealing; corporate waste; unlawful self dealing; and claims that the defendants conspired, aided and abetted and/or assisted one another in a common plan to breach these fiduciary duties. Both lawsuits alleged, among other things, that the TODCO directors engaged in self-dealing in approving the merger with the Company by advancing their own personal interests or those of TODCO’s senior management at the expense of the TODCO stockholders, utilized a defective sales process not designed to maximize TODCO stockholder value, and failed to consider any value maximizing alternatives, thus causing TODCO stockholders to receive an unfair price for their shares of TODCO common stock. The second lawsuit also alleged that the Company conspired, aided and abetted or assisted in these violations. In addition, the second suit alleged that TODCO’s directors breached their fiduciary duties by allegedly improperly awarding stock options to certain officers at a time when they allegedly knew the merger was “imminent” and the stock options would vest immediately upon consummation of the merger. The second suit also named the officers who received these stock option awards as defendants and alleged three causes of action against them: (1) a breach of fiduciary duty claim for having received allegedly improperly awarded stock options, (2) an unjust enrichment claim seeking a constructive trust, and (3) rescission of the stock option awards.

     On August 29, 2007, the two lawsuits were consolidated and transferred to the 270^th Judicial District Court of Harris County, Texas. The plaintiffs subsequently filed a consolidated amended shareholder derivative and class action petition seeking, among other things, rescission of the merger, damages not in excess of $174 million for the class action claims and not in excess of $30 million for the derivative claims, rescission of certain stock options, a constructive trust in favor of plaintiffs, and attorneys’ fees and expenses. On March 14, 2008, the court dismissed all of the derivative claims. In light of that ruling, the plaintiffs confirmed to the court that the only defendants remaining in the case were the TODCO directors. On April 24, 2008, the court granted the defendants’ motion seeking dismissal of the remaining class action claim against those directors, resulting in a dismissal of all remaining claims in the consolidated case. The period during which plaintiffs may appeal this decision has not yet expired. With the final dismissal of these claims, there is no outstanding litigation related to the Company’s merger with TODCO.

     In connection with the acquisition of TODCO, the Company also assumed certain other 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 of 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

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

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 such 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.

     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 July 2007, 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 $2.6 billion; however, coverage for U.S. Gulf of Mexico named windstorm damage is subject to an annual aggregate limit on liability of $150.0 million. The policies are subject to 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. In July 2007, 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 $36.2 million was financed through these arrangements and $6.8 million was outstanding at March 31, 2008. The interest rate on these notes is 5.75% and each note matures in June 2008. There was $16.9 million outstanding in insurance note payable at December 31, 2007 at an interest rate of 5.75%.

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

 Surety Bonds and Unsecured Letters of Credit

     In connection with the TODCO acquisition in July 2007 (See Note 3), the Company assumed certain surety bonds. There was $64.0 million outstanding related to surety bonds at March 31, 2008. 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 and Venezuela.

     The Company had $0.3 million in unsecured letters of credit outstanding at March 31, 2008.

 2005 Hurricanes

     The Company acquired several jackup rigs that were damaged by Hurricanes Rita and Katrina and one jackup rig that was damaged in a collision. During the quarter ended March 31, 2008, the Company received $19.4 million in proceeds related primarily to the settlement of claims for damage incurred during Hurricanes Rita and Katrina. At March 31, 2008, $10.9 million was outstanding for insurance claims receivable primarily related to Hercules 205 which was damaged in a collision.

12. Accounting Pronouncements

     In March 2008, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities (“SFAS 161”). SFAS 161 amends SFAS 133 requiring enhanced disclosures about an entity’s derivative and hedging activities thereby improving the transparency of financial reporting. SFAS 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. We are currently evaluating the impact of adopting SFAS 161 on our consolidated financial statements.

     In December 2007, the FASB issued SFAS No. 141R, Business Combinations (“SFAS No. 141R”). SFAS No. 141R replaces SFAS No. 141, Business Combinations, 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. This fair value approach replaces the cost-allocation process required under SFAS No. 141 whereby the cost of an acquisition was allocated to the individual assets acquired and liabilities assumed based on their estimated fair value. 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. Under SFAS No. 141R, the requirements of SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities would have to be met in order to accrue for a restructuring plan in purchase accounting. Pre-acquisition contingencies are to be recognized at fair value, unless it is a non-contractual contingency that is not likely to materialize, in which case, nothing should be recognized in purchase accounting and, instead, that contingency would be subject to the probable and estimable recognition criteria of SFAS No. 5, Accounting for Contingencies. SFAS No. 141R may have a significant impact on the Company’s accounting for business combinations closing on or after January 1, 2009.

     The Company adopted, without material impact to its consolidated financial statements, the provisions of SFAS No.157, Fair Value Measurements (“SFAS No. 157”) related to financial assets and liabilities and to nonfinancial assets and liabilities measured at fair value on a recurring basis on January 1, 2008. 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 FASB Staff Position (FSP) SFAS 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. The Company will adopt 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. The Company does not expect the provisions of SFAS No. 157 related to these items to have a material impact on its consolidated financial statements.

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

     The Company adopted, without material impact to its consolidated financial statements, the provisions of SFAS No.159,The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS No. 159”) on January 1, 2008. SFAS No. 159 permits companies to choose to measure certain financial instruments and certain other items at fair value and requires that unrealized gains and losses on items for which the fair value option has been elected be reported in earnings.

13. Subsequent Events

     On April 28, 2008, the Company and certain of its subsidiaries entered into an agreement with the revolving lenders under its existing credit facility and certain new lenders to increase the maximum amount of the Company’s revolving credit facility from $150.0 million to $250.0 million (See Note 5).

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, 2008 and for the three months ended March 31, 2008 and March 31, 2007, included elsewhere herein, and with our annual report on Form 10-K for the year ended December 31, 2007. 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.

     In July 2007, we furthered our strategic growth initiative by completing the acquisition of TODCO for total consideration of approximately $2,397.8 million, consisting of $925.8 million in cash and 56.6 million shares of common stock. TODCO, a provider of contract drilling and marine services in the U.S. Gulf of Mexico and international markets, owned and operated 24 jackup rigs, 27 barge rigs, three submersible rigs, nine land rigs, one platform rig and a fleet of marine support vessels. The TODCO acquisition positioned us as a leading shallow-water drilling provider as well as expanded our international presence and diversified our fleet. In December 2007, we sold our land rigs for proceeds of $107.0 million.

     In the first quarter of 2008, we purchased two jackup drilling rigs and related equipment for $220.0 million with cash on hand. In addition, during February 2008, we paid a deposit of $10.0 million to be applied to the purchase of a third jackup rig upon closing. The closing of the transaction for the third jackup rig is subject to regulatory approvals and other customary conditions.

     We operate our business as six divisions: (1) Domestic Offshore, (2) International Offshore, (3) Inland, (4) Domestic Liftboats, (5) International Liftboats, and (6) Other. The following describes our operations for each reporting segment:

     Domestic Offshore – operates 25 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.

     International Offshore – operates ten jackup rigs and one platform rig outside of the U.S. Gulf of Mexico. We have one jackup rig working offshore in each of the following international locations: Qatar, Angola, India and Cameroon. We have one jackup rig in India undergoing contract preparation work and one jackup rig in transit to Saudi Arabia where upon arrival, it will undergo contract preparation work. This segment also operates two jackup rigs and one platform rig in Mexico. We have one jackup rig currently undergoing reactivation in Southeast Asia. In addition, we have one jackup rig warm-stacked in Trinidad.

     Inland – operates a fleet of 12 conventional and 15 posted barge rigs that operate inland in marshes, rivers, lakes and shallow bay or coastal waterways along the U.S. Gulf Coast.

     Domestic Liftboats – operates 46 liftboats in the U.S. Gulf of Mexico.

     International Liftboats – operates 19 liftboats offshore West Africa, including five liftboats owned by a third party and one undergoing refurbishment. In addition, one liftboat is currently on its way to the Middle East.

     Other – our Delta Towing business operates a fleet of 33 inland tugs, 17 offshore tugs, 34 crew boats, 46 deck barges, 17 shale barges and four spud barges along and in the U.S. Gulf of Mexico. This segment also includes wind down costs associated with our sale of the land rigs.

     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 and the number and type of units in our fleet. 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 17, 2008 totaled approximately $882.8 million for our executed contracts. Approximately $295.2 million of this backlog is expected to be realized during the remainder of 2008. 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 amount disclosed or expected due to various factors. Downtime due to various operation 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, as well as the ability of our customers to terminate contracts under certain circumstances.

     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 through attrition and redeployment, but a small crew is retained. Warm-stacked rigs generally can be reactivated in one to two 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.

RECENT DEVELOPMENTS

     On April 28, 2008, we entered into an agreement with the revolving lenders under our existing credit facility and certain new lenders to increase the maximum amount of our revolving credit facility from $150.0 million to $250.0 million. The increased availability under the facility is to be used for working capital, capital expenditures and other general corporate purposes.

RESULTS OF OPERATIONS

     On July 11, 2007, we completed the acquisition of TODCO for total consideration of approximately $2,397.8 million, consisting of $925.8 million in cash and 56.6 million shares of common stock. Our first quarter 2008 results include activity from this acquired business. The acquisition significantly impacts the comparability of the 2008 periods with the corresponding 2007 periods. We are unable to provide certain information regarding our current period results excluding the impact of the TODCO acquisition due to the integration of this acquisition into our operations.

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

		Three Months Ended March 31,
		2008				2007
		(Dollars in thousands)
Domestic Offshore:
Number of rigs (as of end of period)			28				6
Revenues		$	62,447			$	42,831
Operating expenses			47,772				13,563
Depreciation and amortization expense			15,335				2,561
General and administrative expenses			1,230				1,942
Operating income (loss)		$	(1,890	)		$	24,765
International Offshore:
Number of rigs (as of end of period)			11				3
Revenues		$	65,343			$	20,876
Operating expenses			22,792				7,383
Depreciation and amortization expense			7,586				1,368
General and administrative expenses			615				530
Operating income		$	34,350			$	11,595
Inland:
Number of barges (as of end of period)			27				—
Revenues		$	40,268			$	—
Operating expenses			31,926				—
Depreciation and amortization expense			9,660				—
General and administrative expenses			622				—
Operating loss		$	(1,940	)		$	—
Domestic Liftboats:
Number of liftboats (as of end of period)			47				47
Revenues		$	15,944			$	32,703
Operating expenses			13,894				13,640
Depreciation and amortization expense			5,952				6,070
General and administrative expenses			649				538
Operating income (loss)		$	(4,551	)		$	12,455
International Liftboats:
Number of liftboats (as of end of period)			18				17
Revenues		$	18,291			$	14,054
Operating expenses			7,220				6,941
Depreciation and amortization expense			1,984				1,704
General and administrative expenses			939				950
Operating income		$	8,148			$	4,459

		Three Months Ended March 31,
		2008				2007
Other:
Revenues		$	11,093			$	—
Operating expenses			9,205				—
Depreciation and amortization expense			2,575				—
General and administrative expenses			582				—
Operating loss		$	(1,269	)		$	—
Total Company:
Revenues		$	213,386			$	110,464
Operating expenses			132,809				41,527
Depreciation and amortization expense			43,626				11,730
General and administrative expenses			16,364				9,163
Operating income			20,587				48,044
Interest expense			(15,960	)			(2,090	)
Other, net			2,207				1,275
Income before income taxes			6,834				47,229
Income tax provision			(2,348	)			(13,838	)
Net income		$	4,486			$	33,391

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

		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

		Three Months Ended March 31, 2007
																		Average
														Average				Operating
		Operating				Available								Revenue				Expense
		Days				Days				Utilization (1)				per Day (2)				per Day (3)
Domestic Offshore			474				540				87.8	%		$	90,363			$	25,117
International Offshore			180				180				100.0	%			115,978				41,016
Inland			—				—				—				—				—
Domestic Liftboats			2,667				4,099				65.1	%			12,262				3,328
International Liftboats			1,162				1,474				78.8	%			12,095				4,709

(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 $2.0 million and $1.8 million related to amortization of deferred mobilization revenue and contract specific capital expenditures reimbursed by the customer for the three months ended March 31, 2008 and 2007, respectively.
(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 $0.8 million and $1.2 million related to amortization of deferred mobilization expenses for the three months ended March 31, 2008 and 2007, respectively.

For the Three Months Ended March 31, 2008 and 2007

  Revenues

     Consolidated. Total revenues for the three-month period ended March 31, 2008 (the “Current Quarter”) were $213.4 million compared with $110.5 million for the three-month period ended March 31, 2007 (the “Comparable Quarter”), an increase of $102.9 million, or 93%. This increase resulted primarily from revenues generated from TODCO acquired in July 2007. Total revenues included $2.9 million in reimbursements from our customers for expenses paid by us in the Current Quarter compared with $3.2 million in the Comparable Quarter.

     Domestic Offshore. Revenues for our Domestic Offshore segment were $62.4 million for the Current Quarter compared with $42.8 million for the Comparable Quarter, an increase of $19.6 million, or 46%. Revenues for the Current Quarter include approximately $43.2 million from TODCO. Excluding the revenue from TODCO, revenue decreased by approximately $23.6 million, of which $17.0 million was due to lower average dayrates and $6.6 million was due to fewer operating days for our fleet. Average utilization was 54.8% in the Current Quarter compared with 87.8% in the Comparable Quarter primarily due to the stacking of rigs in the second half of 2007 and our customers’ lower drilling activity. Average revenue per rig per day was $56,873 in the Current Quarter compared with $90,363 in the Comparable Quarter. Lower revenue per day also reflects our customers’ lower drilling activity. Revenues for our Domestic Offshore segment include $0.4 million and $0.5 million in reimbursements from our customers for expenses paid by us in the Current Quarter and Comparable Quarter, respectively.

     International Offshore. Revenues for our International Offshore segment were $65.3 million for the Current Quarter compared with $20.9 million for the Comparable Quarter, an increase of $44.5 million, or 213%. Revenues for the Current Quarter include approximately $48.4 million from TODCO. Excluding the impact of the acquisition, revenue decreased by $4.0 million, of which $1.9 million was due to fewer operating days in the current period and $2.1 million was due to lower average dayrates. Average utilization was 92.2% in the Current Quarter compared with 100.0% in the Comparable Quarter. Average revenue per rig per day was $99,913 in the Current Quarter compared with $115,978 in the Comparable Quarter. Included in our Revenues for the International Offshore segment is a total of $2.0 million and $1.8 million related to amortization of deferred mobilization revenue and contract specific capital expenditures reimbursed by the customer for the Current Quarter and Comparable Quarter, respectively. In addition, revenues for our International Offshore segment included $0.3 million and $0.2 million in reimbursements from our customers for expenses paid by us in the Current Quarter and Comparable Quarter, respectively.

     Inland. Revenues for our Inland segment were $40.3 million in the Current Quarter, with 938 operating days and average revenue per rig per day of $42,930. Revenues for our Inland segment included $0.2 million in reimbursements from our customers for expenses paid by us in the Current Quarter. Prior to our acquisition of TODCO in July 2007, we did not have an Inland segment.

     Domestic Liftboats. Revenues for our Domestic Liftboats segment were $15.9 million for the Current Quarter compared with $32.7 million in the Comparable Quarter, a decrease of $16.8 million, or 51%. This decrease resulted primarily from lower average dayrates, which contributed $6.1 million of the decrease, and fewer operating days, which contributed $10.7 million of the decrease. Operating days decreased to 1,600 in the Current Quarter from 2,667 in the Comparable Quarter due primarily to lower customer activity in the Gulf of Mexico in the Current Quarter as compared to the Comparable Quarter. Average utilization also declined to 38.2% in the Current Quarter from 65.1% in the Comparable Quarter. Average revenue per vessel per day was $9,965 in the Current Quarter compared with $12,262 in the Comparable Quarter, a decrease of $2,297. Approximately $1,323 of the decrease in average revenue per vessel per day was due to mix and approximately $974 was due to lower dayrates. Revenues for our Domestic Marine Services segment included $0.7 million in reimbursements from our customers for expenses paid by us in the Current Quarter compared with $1.3 million in the Comparable Quarter.

     International Liftboats. Revenues for our International Liftboats segment were $18.3 million for the Current Quarter compared with $14.1 million in the Comparable Quarter, an increase of $4.2 million, or 30%. This increase is due to an increase in operating days from 1,162 days in the Comparable Quarter to 1,217 days in the Current Quarter. Average revenue per liftboat per day was $15,030 in the Current Quarter compared with $12,095 in the Comparable Quarter, with average utilization of 78.7% in the Current Quarter compared with 78.8% in the Comparable Quarter. Revenues for our International Liftboats segment included $1.2 million in reimbursements from our customers for expenses paid by us in both the Current Quarter and Comparable Quarter.

     Other. Revenues for our Other segment were $11.1 million in the Current Quarter and included $0.1 million in reimbursements from our customers for expenses paid by us in the Current Quarter. Prior to our acquisition of TODCO in July 2007, we did not have an Other segment.

Operating Expenses

     Consolidated. Total operating expenses for the Current Quarter were $132.8 million compared with $41.5 million in the Comparable Quarter, an increase of $91.3 million, or 220%. This increase is further described below.

     Domestic Offshore. Operating expenses for our Domestic Offshore segment were $47.8 million in the Current Quarter compared with $13.6 million in the Comparable Quarter, an increase of $34.2 million, or 252%. Operating expenses for the Current Quarter include approximately $31.5 million associated with the TODCO acquisition. Available days increased to 2,002 in the Current Quarter from 540 in the Comparable Quarter. Average operating expenses per rig per day were $23,862 in the Current Quarter compared with $25,117 in the Comparable Quarter. The decrease was driven primarily by lower insurance costs, partially offset by higher repairs and maintenance and other costs.

     International Offshore. Operating expenses for our International Offshore segment were $22.8 million in the Current Quarter compared with $7.4 million in the Comparable Quarter, an increase of $15.4 million, or 209%. Operating expenses for the Current Quarter include approximately $16.3 million associated with the TODCO acquisition. Available days increased to 709 in the Current Quarter from 180 in the Comparable Quarter. Average operating expenses per rig per day were $32,147 in the Current Quarter compared with $41,016 in the Comparable Quarter. The decrease resulted primarily from lower repairs and maintenance costs as well as lower deferred mobilization expenses. Included in operating expense is $0.8 million in amortization of deferred mobilization expense in the Current Quarter compared with $1.2 million in the Comparable Quarter.

     Inland. Operating expenses for our Inland segment were $31.9 million in the Current Quarter, with 1,547 available days and average operating expenses per rig per day of $20,637. Prior to our acquisition of TODCO in July 2007, we did not have an Inland segment.

     Domestic Liftboats. Operating expenses for our Domestic Liftboats segment were $13.9 million in the Current Quarter compared with $13.6 million in the Comparable Quarter, an increase of $0.3 million, or 2%. Available days increased to 4,186 in the Current Quarter from 4,099 in the Comparable Quarter. Average operating expenses per vessel per day were consistent between periods.

     International Liftboats. Operating expenses for our International Liftboats segment were $7.2 million for the Current Quarter compared with $6.9 million in the Comparable Quarter, an increase of $0.3 million, or 4%. Average operating expenses per liftboat per day were $4,667 in the Current Quarter compared with $4,709 in the Comparable Quarter. This decrease was driven primarily by lower training, freight and labor costs, partially offset by higher maintenance and insurance costs.

     Other. Operating expenses for our Other segment were $9.2 million in the Current Quarter. Prior to our acquisition of TODCO in July 2007, we did not have an Other segment.

Depreciation and Amortization

     Depreciation and amortization expense in the Current Quarter was $43.6 million compared with $11.7 million in the Comparable Quarter, an increase of $31.9 million, or 272%. This increase resulted primarily from additional depreciation of approximately $32.0 million related to assets acquired in the TODCO acquisition.

General and Administrative Expenses

     General and administrative expenses in the Current Quarter were $16.4 million compared with $9.2 million in the Comparable Quarter, an increase of $7.2 million, or 79%. The increase is primarily related to incremental general and administrative costs associated with the acquisition of TODCO.

  Interest Expense

     Interest expense increased $13.9 million, or 664%. The increase was primarily due to interest on our borrowings under our 2007 senior secured term loan.

  Other Income

     Other income in the Current Quarter was $2.2 million compared with $1.3 million in the Comparable Quarter, an increase of $0.9 million. This increase related to additional interest income earned in the Current Quarter.

  Income Tax Provision

     Income tax expense was $2.3 million on pre-tax income of $6.8 million during the Current Quarter, compared to $13.8 million on pre-tax income of $47.2 million for the Comparable Quarter. The effective tax rate increased to 34.4% in the Current Quarter from 29.3% in the Comparable Quarter. The increase in the effective tax rate reflects the impact of higher non-creditable foreign taxes from the TODCO acquisition.

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. 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, goodwill 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, 2007.

OUTLOOK

  Offshore

     In general, demand for our drilling rigs is a function of our customers’ capital spending plans, which are largely driven by their cash flow generated from commodity production 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. Both natural gas and oil prices are higher than historical levels and are generally supportive of increased capital spending for exploration and production activities.

     As of March 31, 2008, the spot price for Henry Hub natural gas was $9.83 per MMBtu and the twelve month strip, or the average of the next twelve month’s futures contract, was $10.396 per MMBtu. Declining reservoir sizes and increasing initial decline rates in North America have been supportive of natural gas prices, somewhat offset by increased onshore drilling activity, growing deepwater production and increasing liquefied natural gas deliveries. These factors, together with weather and industrial demand, will likely remain key drivers in the natural gas market for the foreseeable future.

     Oil prices have remained at high levels relative to historical prices for the past several years with the spot price for West Texas intermediate crude ranging from $50.48 to $110.33 per bbl since the beginning of 2006. As of March 31, 2008, the price of WTI was $101.58 with a twelve month strip of $99.856. Stronger oil prices have largely been driven by extremely robust demand growth in China and India, continued economic growth in OECD countries, and the ongoing weakness in the U.S. dollar.

     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 324 in April 2008. 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 79 currently, according to published industry sources. With several of these rigs either in the shipyard or cold stacked, the marketed supply of jackups in the U.S. Gulf of Mexico is currently approximately 66. The Hercules 261 will be departing the U.S. Gulf of Mexico when it finishes its current obligation and we finalize its purchase. In addition, the Hercules 350 is being marketed internationally. We believe the marketed supply will be down in the low 60’s by year end.

     U.S. Gulf of Mexico demand of 59 jackups as of March 31, 2008 was an improvement over the December 31, 2007 demand of 56 jackups. However, this recent level of demand is considerably lower than two years ago when demand was 88 jackups in January 2006. A combination of factors has resulted in this decline from the levels experienced over the previous several years, including declining target reservoir sizes, increasing finding, development and lifting costs and the significant amount of property transfers.

We believe that the further reduction in supply in the U.S. Gulf of Mexico due to rigs mobilizing to international locations could mitigate the impact of recent reduced drilling demand.

     In addition to spurring migration of rigs out of the U.S., strong global demand for jackups over the past few years has encouraged newbuilds. According to ODS-Petrodata, as of April 1, 2008, 82 jackup rigs have been ordered by industry participants, national oil companies and financial investors for delivery through 2011. We anticipate that these rigs will compete directly with our fleet in international regions. As a result of higher dayrates, longer duration contracts and lower insurance costs, which are prevalent internationally, among other factors, we believe the vast majority of the new build jackup rigs will target international regions and not the U.S. Gulf of Mexico. Our ability to expand our international drilling fleet may be limited, however, by the increased supply of newbuild jackup rigs.

     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 historically 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 market for inland barge drilling in the U.S. generally follows the same drivers as drilling in the U.S. Gulf of Mexico with demand following operators’ expectations of prices for natural gas and, to a lesser degree, crude oil. However, 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 over the past year and dayrates have also softened. However, based on recent discoveries and discussion with our customers, we remain optimistic about deeper targets in the inland barge area and believe this may generate growth opportunities as the trend toward deeper drilling in shallow water expands.

  Liftboats

     Demand for liftboats is typically a function of our customer’s 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 demand. 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 US Gulf of Mexico, liftboat demand in the region was stronger than historical levels for approximately two years. Activity levels now appear to have returned to normal. Furthermore, as approximately 14 new liftboats have been delivered over the past two years, utilization rates have softened. As of April 30, 2008, we believe that there were another 11 liftboats under construction or on order in the U.S., with anticipated delivery dates during 2008 and 2009. Once delivered, these liftboats may further impact the demand and utilization of our domestic liftboat fleet.

     Our customers’ growth in international capital spending, 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. We anticipate that demand for liftboats will likely increase in West Africa and other international locations as these markets mature and the focus shifts from exploration to development and new platforms and other infrastructure is installed. We anticipate that there will be longer term contract opportunities in international locations for liftboats currently working in the U.S. Gulf of Mexico and for newly constructed liftboats. While we believe that international demand for liftboats will continue to increase, the political instability in certain regions may negatively impact our customers’ capital spending plans. We are actively marketing a number of our liftboats currently operating in the U.S. Gulf of Mexico for projects in international locations, which have long-term contract opportunities.

  Labor Markets

     We require highly skilled personnel to operate our rigs, barges and liftboats and to support our business. Competition for skilled rig personnel could intensify as 164 new offshore rigs are under construction and 49 are scheduled to enter the global fleet during 2008. If competition for personnel intensifies, our labor costs will likewise increase, although we do not believe at this time that our

operations will be limited. We respond to competition though retention programs, including increases in base compensation and bonuses tied to retention and utilization goals.

     We have also experienced a tightening in the labor market for liftboat and marine personnel. We have instituted retention programs, along with additional programs that may become necessary to retain skilled personnel, to continue for the foreseeable future.

LIQUIDITY AND CAPITAL RESOURCES

  Sources and Uses of Cash

     Sources and uses of cash for the three-month period ended March 31, 2008 are as follows (in millions):

Net Cash Provided by Operating Activities		$	44.7
Net Cash Provided by (Used in) Investing Activities
Acquisition of Rigs			(230.0	)
Sale of Marketable Securities			39.3
Additions to Property and Equipment			(45.8	)
Deferred Drydocking Expenditures			(5.5	)
Proceeds from Sale of Assets, Net			1.9
Insurance Proceeds Received			19.4
Total			(220.7	)
Net Cash Provided by (Used in) Financing Activities
Long-term Debt Payments			(2.3	)
Other			0.3
Total			(2.0	)
Net Decrease in Cash and Cash Equivalents		$	(178.0	)

     During the quarter ended March 31, 2008, we received $19.4 million in proceeds related primarily to the settlement of insurance claims for damage incurred to rigs from Hurricanes Rita and Katrina.

  Sources of Liquidity and Financing Arrangements

     Our sources of liquidity include current cash and cash equivalent balances, marketable securities, cash generated from operations and committed availability under our revolving credit facility. We also maintain a shelf registration statement covering the future issuance of various types of securities, including debt and equity; however, our senior secured credit facility restricts issuance of additional debt.

     From time to time we evaluate the possibility of selling certain of our assets, groups of assets and/or operations. We have engaged a financial advisor to assist us in the possible sale of our Delta Towing business. We have provided interested parties with information about that business and are in the process of soliciting bids. There are no assurances that we will receive bids for the business that will be acceptable to us or that we will otherwise be able to complete a sale of the business.

     Additional capital in either the form of debt or equity may be required in 2008 if we generate less than expected cash due to a deterioration of market conditions or other factors beyond our control, or if other acquisitions necessitate additional liquidity. Our future cash flows may be insufficient to meet all of our debt obligations and commitments, and any insufficiency could negatively impact our business. To the extent we are unable to repay our indebtedness as it becomes due at maturity with cash on hand or from other sources, we will need to refinance our debt, sell assets or repay the debt with the proceeds from further equity offerings. Additional indebtedness or equity financing may not be available to us in the future for the refinancing or repayment of existing indebtedness, and we can provide no assurance as to the timing of any asset sales or the proceeds that could be realized by us from any such asset sale.

  Cash Requirements and Contractual Obligations

  Asset Acquisition

     In February 2008, we entered into a definitive agreement to purchase three jackup drilling rigs and related equipment for approximately $320.0 million. The purchase of two of the jackup drilling rigs for $220.0 million was completed in the first quarter. In addition, in February 2008 we made a deposit of $10.0 million to be applied to the purchase of the third jackup rig, which is expected to close during the second quarter of 2008. The closing of the transaction for the third jackup rig is subject to regulatory approvals and

other customary conditions. We funded the purchase of the first two rigs with cash on hand and plan to fund the acquisition of the third jackup rig with cash on hand and borrowings under our revolving credit facility.

  Debt

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

          In July 2007, we terminated all prior facilities and we entered into a new $1,050.0 million credit facility, consisting of a $900.0 million term loan and a $150.0 million revolving credit facility. All borrowings under the revolving credit facility mature on July 11, 2012, and the revolving credit facility requires interest-only payments on a quarterly basis until the maturity date. No amounts were outstanding and $29.0 million in stand-by letters of credit had been issued under the revolving credit facility as of March 31, 2008. The remaining availability under this revolving credit facility was $121.0 million at March 31, 2008. On April 28, 2008, we entered into an agreement with the revolving lenders under our existing credit facility and certain new lenders to increase the maximum amount of our revolving credit facility from $150.0 million to $250.0 million. The increased availability under the facility is to be used for working capital, capital expenditures and other general corporate purposes.

     As of March 31, 2008, $893.3 million was outstanding on the term loan facility and the interest rate was 4.45%. The annualized effective interest rate was 6.82% for the three months ended March 31, 2008 after giving consideration to derivative activity.

     The credit agreement contains financial covenants that are tested quarterly relating to leverage and fixed charge coverage. 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. The credit agreement contains customary events of default. We were in compliance with these covenants at March 31, 2008.

     In July 2007, we entered into derivative instruments with the purpose of hedging future interest payments on our new term loan facility. 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 a decrease in a derivative asset of $0.2 million and an increase in a derivative liability of $10.6 million during the three months ended March 31, 2008. This resulted in unrealized losses on hedge transactions of $7.0 million, net of tax of $3.8 million for the three months ended March 31, 2008. 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, 2008 related to these hedging instruments. In addition, our interest expense was increased by $0.5 million during the three months ended March 31, 2008 as a result of our interest rate derivative instruments.

     In connection with the TODCO acquisition in July 2007, we assumed senior notes and an unsecured line of credit with a bank in Venezuela. The senior notes include 6.95% Senior Notes due in April 2008, 7.375% Senior Notes due in April 2018 and 9.5% Senior Notes due in December 2008. The fair market value of these notes at March 31, 2008 was approximately $2.2 million, $3.5 million and $9.9 million, respectively, based on the most recent market valuations. The line of credit is designed to manage local currency liquidity in Venezuela. The maximum amount available to be drawn is 6.0 million Bolivares Fuertes ($2.8 million at the exchange rate at March 31, 2008), and there were no amounts outstanding at March 31, 2008.

     In July 2007, 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 $36.2 million was financed through these arrangements, and $6.8 million was outstanding at March 31, 2008. The interest rate on these notes is 5.75% and each note matures in June 2008.

  Capital Expenditures

     We expect to spend a total of $175 million on capital expenditures excluding asset acquisitions during the remainder of 2008. Planned capital expenditures include refurbishment and upgrade of our rigs and liftboats, including amounts allocated to Hercules 185, Hercules 208, Hercules 258, Hercules 260, and the recently acquired Hercules 300 and Hercules 350. In addition, included in our planned capital expenditures are amounts for contract preparation and planned equipment standardization for top-drives and cranes.

     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, surety bonds, letters of credit, future minimum operating lease obligations, purchase commitments and management compensation obligations. During the first quarter of 2008, there were no material changes outside the ordinary course of business in the specified contractual obligations, other than in connection with the acquisition from Transocean.

     For additional information about our contractual obligations as of December 31, 2007, 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, 2007.

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 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, 2008, we had $93.3 million of letters of credit and surety bonds outstanding, consisting of $0.3 million in unsecured outstanding letters of credit, $29.0 million letters of credit outstanding under our revolver and $64.0 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 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;
	•		expectations regarding improvements in offshore drilling activity and dayrates, continuation of current 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, 2007 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 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, 2008, the long-term borrowings that were outstanding subject to fixed interest rate risk consist of the 7.375% Senior Notes due April 2018. Both the carrying amount and fair value of the 7.375% Senior Notes was $3.5 million.

As of March 31, 2008, the interest rate for the $893.3 million outstanding under the term loan was 4.45%. If the interest rate averaged 1% more for 2008 than the rates as of March 31, 2008, annual interest expense would increase by approximately $8.9 million. This sensitivity analysis assumes there are no changes in our financial structure.

We believe our other debt instruments, which are short-term in nature, totaling $12.6 million as of March 31, 2008, approximate fair value.

     Interest Rate Swaps and Derivatives

     We manage our debt portfolio to achieve an overall desired position of fixed and floating rates and may employ hedge transactions such as interest rate swaps and zero cost LIBOR collars as tools to achieve that goal. The major risks from interest rate derivatives include changes in the interest rates affecting the fair value of such instruments, potential increases in interest expense due to market decreases in floating interest rates and the creditworthiness of the counterparties in such transactions. The counterparties to our interest rate swap and zero cost LIBOR collar are creditworthy multinational commercial banks. We believe that the risk of counterparty nonperformance is immaterial. Our interest expense was increased by $0.5 million for the three months ended March 31, 2008, 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%. The table below provides the scheduled reduction in notional amounts related to the interest rate swap (in thousands):

April 1, 2008-June 30, 2008		$	300,000
July 1, 2008-September 30, 2008			200,000
October 1, 2008-December 31, 2008			100,000
January 1, 2009-March 31, 2009			50,000

ITEM 4. CONTROLS AND PROCEDURES

     We carried out an evaluation, under the supervision and with the participation of our management, including Randall D. Stilley, our President and Chief Executive Officer, 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. Stilley and Ms. Rodriguez, acting in their capacities as our principal executive officer and our principal financial officer, concluded that, as of March 31, 2008, 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.

     During the first quarter of 2008, we converted our domestic operational and financial functions to the Oracle enterprise resource planning (“ERP”) software system. The new ERP system affects every aspect of our operations, including procurement, finance and accounting, engineering, human resources and benefits and asset maintenance. We will continue the upgrade of our legacy financial systems to the Oracle ERP system internationally, and expect the upgrade to be completed in the third quarter of 2008. We expect this upgrade will have a positive impact on our overall control environment.

     Other than as discussed above, 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, 2007.

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

     The following table sets forth for the periods indicated certain information with respect to our purchases of our common stock:

Total Number of

Maximum Number of

Total Number

Shares Purchased as

Shares That May Yet Be

of Shares

Average Price

Part of a Publicly

Purchased Under

Period

Purchased (1)

Paid per Share

Announced Plan (2)

Plan (2)

January 1 - 31, 2008

—

$

—

N/A

N/A

February 1 - 29, 2008

1,728

24.44

N/A

N/A

March 1 - 31, 2008

—

—

N/A

N/A

Total

1,728

24.44

N/A

N/A

     

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

ITEM 6. EXHIBITS

10.1		Increase Joinder, dated as of April 28, 2008, among Hercules, as borrower, its subsidiaries party thereto, the incremental lenders and other lenders party thereto, and UBS AG Stamford Branch, as administrative agent for the lenders party thereto (incorporated by reference to Exhibit 10.1 to Hercules’ Current Report on Form 8-K dated April 30, 2008 (File No. 0-51582)).
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/ Randall D. Stilley
				Randall D. Stilley
				President and Chief Executive Officer
				(Principal Executive Officer)
		By:		/s/ Lisa W. Rodriguez
				Lisa W. Rodriguez
				Senior Vice President and Chief Financial Officer
				(Principal Financial and Accounting Officer)

Date: May 1, 2008

EXHIBIT INDEX

10.1		Increase Joinder, dated as of April 28, 2008, among Hercules, as borrower, its subsidiaries party thereto, the incremental lenders and other lenders party thereto, and UBS AG Stamford Branch, as administrative agent for the lenders party thereto (incorporated by reference to Exhibit 10.1 to Hercules’ Current Report on Form 8-K dated April 30, 2008 (File No. 0-51582)).
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