e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended March 31, 2011


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

Commission file number: 0-51582

HERCULES OFFSHORE, INC.

(Exact name of registrant as specified in its charter)


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


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

(713) 350-5100
(Registrant’s telephone number, including area code)

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

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

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

Large accelerated filer o

Accelerated filer þ

Non-accelerated filer o
(Do not check if a smaller reporting company)

Smaller reporting company o

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

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


Common Stock, par value $0.01 per share		Outstanding as of April 27, 2011 137,436,781

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

HERCULES OFFSHORE, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except par value)


	March 31,			December 31,
	2011			2010
	(Unaudited)
ASSETS
Current Assets:
Cash and Cash Equivalents	$	162,966		$	136,666
Restricted Cash		11,129			11,128
Accounts Receivable, Net of Allowance for Doubtful Accounts of $22,228 and $29,798 as of March 31, 2011 and December 31, 2010, Respectively		157,684			143,796
Prepaids		8,033			17,142
Current Deferred Tax Asset		8,488			8,488
Other		8,311			11,794

		356,611			329,014
Property and Equipment, Net		1,603,521			1,634,542
Equity Investment		18,254			—
Other Assets, Net		38,304			31,753

	$	2,016,690		$	1,995,309

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term Debt and Current Portion of Long-term Debt	$	4,924		$	4,924
Insurance Notes Payable		736			5,984
Accounts Payable		60,176			52,279
Accrued Liabilities		62,071			59,861
Interest Payable		24,003			6,974
Taxes Payable		9,559			—
Other Current Liabilities		19,520			16,716

		180,989			146,738
Long-term Debt, Net of Current Portion		854,255			853,166
Other Liabilities		24,117			6,716
Deferred Income Taxes		118,294			135,557
Commitments and Contingencies
Stockholders’ Equity:
Common Stock, $0.01 Par Value; 200,000 Shares Authorized; 116,738 and 116,336 Shares Issued, Respectively; 115,106 and 114,784 Shares Outstanding, Respectively		1,167			1,163
Capital in Excess of Par Value		1,925,115			1,924,659
Treasury Stock, at Cost, 1,632 Shares and 1,552 Shares, Respectively		(50,671	)		(50,333	)
Retained Deficit		(1,036,576	)		(1,022,357	)

		839,035			853,132

	$	2,016,690		$	1,995,309

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

HERCULES OFFSHORE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)


	Three Months Ended March 31,
	2011			2010
Cash Flows from Operating Activities:
Net Loss	$	(14,219	)	$	(15,956	)
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities:
Depreciation and Amortization		42,911			50,254
Stock-Based Compensation Expense		1,158			156
Deferred Income Taxes		(18,027	)		(22,657	)
Benefit for Doubtful Accounts Receivable		(5,021	)		(1,472	)
Amortization of Deferred Financing Fees		874			873
Amortization of Original Issue Discount		1,089			1,002
Equity in Losses of Equity Investment		55			—
Non-Cash (Gain) Loss on Derivatives		(155	)		3,561
Gain on Disposal of Assets		(702	)		(3,013	)
Expense of Credit Agreement Fees		455			—
Excess Tax Benefit from Stock-Based Arrangements		(117	)		(374	)
(Increase) Decrease in Operating Assets -
Accounts Receivable		(8,867	)		(1,062	)
Prepaid Expenses and Other		21,673			10,397
Increase (Decrease) in Operating Liabilities -
Accounts Payable		571			(4,077	)
Insurance Notes Payable		(5,248	)		(4,724	)
Other Current Liabilities		21,221			(7,733	)
Other Liabilities		11,461			(4,843	)

Net Cash Provided by Operating Activities		49,112			332
Cash Flows from Investing Activities:
Additions of Property and Equipment		(10,277	)		(4,546	)
Deferred Drydocking Expenditures		(4,124	)		(4,396	)
Cash Paid for Equity Investment		(10,000	)		—
Proceeds from Sale of Assets, Net		3,421			3,616
Increase in Restricted Cash		(1	)		(3,370	)

Net Cash Used in Investing Activities		(20,981	)		(8,696	)
Cash Flows from Financing Activities:
Long-term Debt Repayments		—			(2,050	)
Excess Tax Benefit from Stock-Based Arrangements		117			374
Payment of Debt Issuance Costs		(2,109	)		—
Other		161			9

Net Cash Used in Financing Activities		(1,831	)		(1,667	)

Net Increase (Decrease) in Cash and Cash Equivalents		26,300			(10,031	)
Cash and Cash Equivalents at Beginning of Period		136,666			140,828

Cash and Cash Equivalents at End of Period	$	162,966		$	130,797

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

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

1. General

Hercules Offshore, Inc., a Delaware corporation, and its majority owned subsidiaries (the “Company”) provide shallow-water drilling and marine services to the oil and natural gas exploration and production industry globally through its Domestic Offshore, International Offshore, Inland, Domestic Liftboats, International Liftboats and Delta Towing segments (See Note 12). At March 31, 2011, the Company owned a fleet of 30 jackup rigs, 17 barge rigs, three submersible rigs, one platform rig, a fleet of marine support vessels operated through Delta Towing, a wholly owned subsidiary, and 60 liftboat vessels and operated an additional five liftboat vessels owned by a third party. The Company’s diverse fleet is capable of providing services such as oil and gas exploration and development drilling, well service, platform inspection, maintenance and decommissioning operations in several key shallow water provinces around the world.

In February 2011, the Company entered into an asset purchase agreement (the “Asset Purchase Agreement”) with Seahawk Drilling, Inc. and certain of its subsidiaries (“Seahawk”), pursuant to which Seahawk agreed to sell the Company 20 jackup rigs and related assets, accounts receivable, cash and certain liabilities. On April 27, 2011, the Company completed the Seahawk asset purchase (See Note 4). Including the assets acquired in the Seahawk transaction, the Company owns a fleet of 50 jackup rigs, 17 barge rigs, three submersible rigs, one platform rig, a fleet of marine support vessels operated through Delta Towing, a wholly owned subsidiary, and 60 liftboat vessels and operated an additional five liftboat vessels owned by a third party.

The consolidated financial statements of the Company are unaudited; however, they include all adjustments of a normal recurring nature which, in the opinion of management, are necessary to present fairly the Company’s Consolidated Balance Sheet at March 31, 2011 and the Company’s Consolidated Statements of Operations, Consolidated Statements of Cash Flows and Consolidated Statements of Comprehensive Loss for the three months ended March 31, 2011 and 2010. 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, 2010 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, 2011 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 revenue and expenses during the reporting period. On an ongoing basis, the Company evaluates its estimates, including those related to bad debts, investments, derivatives, property and equipment, income taxes, insurance, percentage-of-completion, 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.

Investigations

On April 4, 2011, the Company received a subpoena issued by the Securities and Exchange Commission (“SEC”) requesting the delivery of certain documents to the SEC in connection with its investigation into possible violations of the securities laws, including possible violations of the Foreign Corrupt Practices Act (“FCPA”) in certain international jurisdictions where the Company conducts operations. The Company was also notified by the Department of Justice (“DOJ”) on April 5, 2011, that certain of the Company’s activities are under review by the DOJ.

The Company, through the Audit Committee of the Board of Directors, has engaged an outside law firm with significant experience in FCPA-related matters to conduct an internal review, and intends to cooperate with the SEC and DOJ in their investigations. At this time, it is not possible to predict the outcome of the investigations, the expenses the Company will incur associated with these matters, or the impact on the price of the Company’s common stock or other securities as a result of these investigations.

Investment

In January 2011, the Company paid $10 million to purchase 5.0 million shares, an initial investment in approximately eight percent of the total outstanding equity of a new entity incorporated in Luxembourg, Discovery Offshore S.A. (“Discovery Offshore”), which investment was used by Discovery Offshore towards funding the down payments on two new-build ultra high specification

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

harsh environment jackup drilling rigs (collectively the “Rigs” or individually “Rig”) (See Note 3). The Rigs, Keppel FELS “Super A” design, are being constructed by Keppel FELS in its Singapore shipyard and have a maximum water depth rating of 400 feet, two million pound hook load capacity and are capable of drilling up to 35,000 feet deep. The two Rigs are expected to be delivered in the second and fourth quarter of 2013, respectively. Discovery Offshore also holds options to purchase two additional rigs of the same specifications, which must be exercised by the third and fourth quarter of 2011, with delivery dates expected in the second and fourth quarter of 2014, respectively.

The Company also executed a construction management agreement (the “Construction Management Agreement”) and a services agreement (the “Services Agreement”) with Discovery Offshore with respect to each of the Rigs. Under the Construction Management Agreements, the Company will plan, supervise and manage the construction and commissioning of the Rigs in exchange for a fixed fee of $7.0 million per Rig, which the Company received in February 2011. Pursuant to the terms of the Services Agreements, the Company will market, manage, crew and operate the Rigs and any other rigs that Discovery Offshore subsequently acquires or controls, in exchange for a fixed daily fee of $6,000 per Rig plus five percent of Rig-based EBITDA (EBITDA excluding SG&A expense) generated per day per Rig, which commences once the Rigs are completed and operating. Under the Services Agreements, Discovery Offshore will be responsible for operational and capital expenses for the Rigs. The Company is entitled to a minimum fee of $5 million per Rig in the event Discovery Offshore terminates a Services Agreement in the absence of a breach of contract by Hercules Offshore.

In addition to the $10 million investment, the Company received 500,000 additional shares worth $1.0 million to cover its costs incurred and efforts expended in forming Discovery Offshore. The Company was issued warrants to purchase up to 5.0 million additional shares of Discovery Offshore stock at a strike price equivalent to $2.00 which is exercisable in the event that the Discovery Offshore stock price reaches an average equal to or higher than 23 Norwegian Kroner per share, which approximated $4.00 per share as of March 31, 2011, for 30 consecutive trading days. The warrants were issued to additionally compensate the Company for its costs incurred and efforts expended in forming Discovery Offshore. The warrants are being accounted for as a derivative instrument (See Notes 7 and 8). The initial fair value of the warrants and the 500,000 additional shares have been recorded to deferred revenue to be amortized over 30 years, the useful life of the Rigs. The Company has no other financial obligations or commitments with respect to the Rigs or its ownership in Discovery Offshore. Two of the Company’s officers are on the Board of Directors of Discovery Offshore.

Other Agreements

In January 2011, the Company entered into an agreement with China Oilfield Services Limited (“COSL”) whereby it will market and operate a Friede & Goldman JU2000E jackup drilling rig with a maximum water depth of 400 feet. The agreement is limited to a specified opportunity in Angola.

In March, 2011, at the Company’s request, the parties agreed to terminate, without the payment of a termination fee, the management agreement with First Energy Bank B.S.C. (“MENAdrill”) with respect to Hull 110.

Revenue Recognition

Revenue generated from the Company’s contracts is recognized as services are performed, as long as collectability is reasonably assured. 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 ninety days are recognized as services are performed over the term of the related drilling contract. Amounts related to deferred revenue, including revenue deferred related to the Company’s construction management agreements with Discovery Offshore as well as the warrants and 500,000 additional shares received from Discovery Offshore, and deferred expenses are summarized below (in thousands):


	Three Months Ended March 31,
	2011		2010
Revenue deferred	$	24,533	$	600
Expense deferred		1,349		—
Deferred Revenue recognized		5,232		4,927
Deferred Expense recognized		586		1,001

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

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

The balances related to the Company’s Deferred Costs and Deferred Revenue are as follows (in thousands):

As of

Balance Sheet

March 31,

December 31,

Classification

2011

2010

Assets:

Deferred Expense-Current Portion

Other

2,141

1,824

Deferred Expense-Non-Current Portion

Other Assets, Net

3,618

3,172

Liabilities:

Deferred Revenue-Current Portion

Other Current Liabilities

15,002

12,628

Deferred Revenue-Non-Current Portion

Other Liabilities

16,927

—

Percentage-of-Completion

The Company is using the percentage-of-completion method of accounting for its revenue and related costs associated with its construction management agreements with Discovery Offshore, combining the construction management agreements, based on a cost-to-cost method. Any revisions in revenue, cost or the progress towards completion, will be treated as a change in accounting estimate and will be accounted for using the cumulative catch-up method. As of March 31, 2011, $14.0 million has been recorded as a deferred revenue liability; however, no deferred cost asset has been recorded. There was no revenue or cost recognized during the three months ended March, 31, 2011 under the percentage-of-completion method of accounting as there were no activities associated with the performance of contract obligations during the current quarter.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are stated at the historical carrying amount net of write-offs and allowance for doubtful accounts. Management of the Company monitors the accounts receivable from its customers for any collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent factors. Accounts deemed uncollectible are charged to the allowance. The Company had an allowance of $22.2 million and $29.8 million at March 31, 2011 and December 31, 2010, respectively. The change in the Company’s allowance during the three months ended March 31, 2011 related primarily to a payment received from a customer in its International Offshore segment.

Other Assets

Other assets consist of drydocking costs for marine vessels, a derivative asset, other intangible assets, deferred income taxes, deferred operating expenses, financing fees, investments and deposits. Drydocking costs are capitalized at cost and amortized on the straight-line method over a period of 12 months. Drydocking costs, net of accumulated amortization, at March 31, 2011 and December 31, 2010, were $6.4 million and $5.9 million, respectively. Amortization expense for drydocking costs was $3.7 million and $4.2 million for the three months ended March 31, 2011 and 2010, respectively.

Financing fees are deferred and amortized over the life of the applicable debt instrument. However, in the event of an early repayment of debt or certain debt amendments, the related unamortized deferred financing fees are expensed in connection with the repayment or amendment (See Note 6). Unamortized deferred financing fees at March 31, 2011 and December 31, 2010 were $12.2 million and $11.4 million, respectively. Amortization expense for financing fees was $0.9 million for both the three months ended March 31, 2011 and 2010, and is included in Interest Expense on the Consolidated Statements of Operations.

Cash and Cash Equivalents

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.

Restricted Cash

At both March 31, 2011 and December 31, 2010, the Company had restricted cash of $11.1 million to support surety bonds related to the Company’s Mexico and U.S. operations.

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

2. Earnings Per Share

The Company calculates basic earnings per share by dividing net income by the weighted average number of shares outstanding. Diluted earnings per share is computed by dividing net income by the weighted average number of shares outstanding during the period as adjusted for the dilutive effect of the Company’s stock option and restricted stock awards. The effect of stock option and restricted stock awards is not included in the computation for periods in which a net loss occurs, because to do so would be anti-dilutive. Stock equivalents of 6,813,234 and 5,384,189 were anti-dilutive and are excluded from the calculation of the dilutive effect of stock equivalents for the diluted earnings per share calculations for the three months ended March 31, 2011 and 2010, respectively. There were no stock equivalents to exclude from the calculation of the dilutive effect of stock equivalents for the diluted earnings per share calculations for the three months ended March 31, 2011 and 2010 related to the assumed conversion of the 3.375% Convertible Senior Notes under the if-converted method as there was no excess of conversion value over face value in either of these periods.

3. Equity Investment

The Company’s total equity investment in Discovery Offshore was $18.3 million, or 13% as of March 31, 2011, which includes the initial cash investment of $10.0 million, additional equity interest of $1.0 million related to 500,000 Discovery Offshore shares awarded to the Company for reimbursement of costs incurred and efforts expended in forming Discovery Offshore, additional purchases of Discovery Offshore shares on the open market totalling $7.3 million or 3,203,700 shares (amount was not cash settled until April 2011) as well as the Company’s proportionate share of Discovery Offshore’s losses. This investment is being accounted for using the equity method of accounting as the Company has the ability to exert significant influence, but not control, over operating and financial policies. The Company has warrants issued from Discovery Offshore that, if exercised, would be recorded as an increase in the Company’s equity investment in Discovery Offshore (See Notes 1, 7, 8 and 10).

4. Asset Purchase

On April 27, 2011, the Company completed its acquisition of 20 jackup rigs and related assets, accounts receivable, cash and certain liabilities from Seahawk for total consideration of approximately $151.8 million consisting of $25.0 million of cash and 22.3 million Hercules common shares. The fair value of the shares issued was determined using the closing price of the Company’s stock of $5.68 on April 27, 2011.

5. Dispositions

In November 2010, the Company entered into an agreement to sell its retired jackups Hercules 190 and Hercules 254 for a total of $4.0 million for both jackups, which is expected to close in the second quarter of 2011. In March 2011, the Company entered into an agreement to sell its submersible rig Hercules 78 for $1.8 million, which is expected to close in the second quarter of 2011. The financial information for Hercules 190, Hercules 254 and Hercules 78 has been reported as part of the Domestic Offshore segment.

In April 2011, the Company entered into an agreement to sell its jackup Hercules 152 for a purchase price of $5.0 million.

The Company completed the sale of 3 barges in March 2010 for total gross proceeds of $2.2 million, resulting in a gain of $1.8 million.

6. Debt

Debt is comprised of the following (in thousands):

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


	March 31,		December 31,
	2011		2010
Term Loan Facility, due July 2013	$	475,156	$	475,156
10.5% Senior Secured Notes, due October 2017		293,113		292,935
3.375% Convertible Senior Notes, due June 2038		87,399		86,488
7.375% Senior Notes, due April 2018		3,511		3,511

Total Debt		859,179		858,090
Less Short-term Debt and Current Portion of Long-term Debt		4,924		4,924

Total Long-term Debt, Net of Current Portion	$	854,255	$	853,166

Senior secured Credit Agreement

At December 31, 2010, the Company had outstanding a $650.2 million credit facility, consisting of a $475.2 million term loan and a $175.0 million revolving credit facility which is governed by the credit agreement (“Credit Agreement”), as amended.

Prior to the March 2011 Credit Amendment, the interest rates on borrowings under the Credit Facility were 4.00% plus LIBOR for Eurodollar Loans and 3.00% plus the Alternate Base Rate for ABR Loans, based on the principal amount of the term loans outstanding during the period. A minimum LIBOR rate of 2.00% for Eurodollar Loans, or a minimum base rate of 3.00% with respect to ABR Loans, apply to all borrowings under the Credit Facility. The commitment fee on the revolving credit facility was 1.00% and the letter of credit fee with respect to the undrawn amount of each letter of credit issued under the revolving credit facility was 4.00% per annum.

The availability under the $175.0 million revolving credit facility must be used for working capital, capital expenditures and other general corporate purposes and cannot be used to prepay the term loan. The Company is required to maintain a minimum level of liquidity, measured as the amount of unrestricted cash and cash equivalents on hand and availability under the revolving credit facility, of (i) $75.0 million during calendar year 2011 and (ii) $50.0 million thereafter. As of March 31, 2011, as calculated pursuant to the Credit Agreement, the Company’s total liquidity was $290.8 million.

In addition, the Company is required to maintain a minimum fixed charge coverage ratio according to the following schedule:

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


			Fixed Charge
Period			Coverage Ratio
July 1, 2009	—	December 31, 2011	1.00 to 1.00
January 1, 2012	—	March 31, 2012	1.05 to 1.00
April 1, 2012	—	June 30, 2012	1.10 to 1.00
July 1, 2012 and thereafter			1.15 to 1.00

The consolidated fixed charge coverage ratio for any test period is defined as the sum of consolidated EBITDA for the test period plus an amount that may be added for the purpose of calculating the ratio for such test period, not to exceed $130.0 million in total during the term of the credit facility, to consolidated fixed charges for the test period adjusted by an amount not to exceed $110.0 million during the term of the credit facility to be deducted from capital expenditures, all as defined in the Credit Agreement. As of March 31, 2011, the Company’s fixed charge coverage ratio was 1.76 to 1.00.

•

In addition, the Company is required to make mandatory prepayments of debt outstanding under the Credit Agreement with 50% of excess cash flow as defined in the Credit Agreement for the fiscal years ending December 31, 2011 and 2012, and with proceeds from:

	-		unsecured debt issuances, with the exception of refinancing;

	-		secured debt issuances;

	-		casualty events not used to repair damaged property;

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

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

March 2011 Credit Amendment

On March 3, 2011, the Company amended its Credit Agreement (“2011 Credit Amendment”) to, among other things:

	-		Allow for the use of cash to purchase assets from Seahawk, to the extent set forth in the Company’s previously disclosed Asset Purchase Agreement with Seahawk;

	-		Exempt the pro forma treatment of historical results from the Seahawk assets with respect to the calculation of the financial covenants in the Credit Agreement;

	-		Increase the Company’s investment basket to $50 million from $25 million; and

	-		Revise the covenant threshold levels of the Total Leverage Ratio, as defined in the Credit Agreement, to the following schedule:

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


		Amended Total
Test Date	Previous Total Leverage Ratio	Leverage Ratio

March 31, 2011	7.00 to 1.00	No Change
June 30, 2011	6.75 to 1.00	No Change
September 30, 2011	6.00 to 1.00	7.50 to 1.00
December 31, 2011	5.50 to 1.00	7.75 to 1.00
March 31, 2012	5.25 to 1.00	7.50 to 1.00
June 30, 2012	5.00 to 1.00	7.25 to 1.00
September 30, 2012	4.75 to 1.00	6.75 to 1.00
December 31, 2012	4.50 to 1.00	6.25 to 1.00
March 31, 2013	4.25 to 1.00	6.00 to 1.00
June 30, 2013	4.00 to 1.00	5.75 to 1.00

At March 31, 2011, the Company’s total leverage ratio was 4.69 to 1.00.

Further, the interest rates on borrowings under the Credit Facility were increased to 5.50% plus LIBOR for Eurodollar Loans and 4.50% plus the Alternate Base Rate for ABR Loans. The minimum LIBOR of 2.00% for Eurodollar Loans, or a minimum base rate of 3.00% with respect to ABR Loans, remains. In addition, total commitments on the revolving credit facility, which is currently unfunded, were reduced to $140.0 million from $175.0 million.

The Company also agreed to pay consenting lenders an upfront fee of 0.25% on their commitment, or approximately $1.4 million. Including agent bank fees and expenses the Company’s total cost was approximately $2.0 million. The Company recognized a pretax charge of $0.5 million, $0.3 million net of tax, related to the write off of certain unamortized issuance costs and the expense of certain fees in connection with the 2011 Credit Amendment.

Other Terms and Conditions

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

Other covenants contained in the Credit Agreement restrict, among other things, asset dispositions, mergers and acquisitions, dividends, stock repurchases and redemptions, other restricted payments, debt issuances, liens, investments, convertible notes repurchases and affiliate transactions. The Credit Agreement also contains a provision under which an event of default on any other indebtedness exceeding $25.0 million would be considered an event of default under the Company’s Credit Agreement.

The Credit Agreement requires that the Company meet certain financial ratios and tests, which it met as of March 31, 2011. The Company’s failure to comply with such covenants would result in an event of default under the Credit Agreement. Additionally, in order to maintain compliance with the Company’s financial covenants, borrowings under the Company’s revolving credit facility may be limited to an amount less than the full amount of remaining availability after outstanding letters of credit. An event of default could prevent the Company from borrowing under the revolving credit facility, which would in turn have a material adverse effect on the Company’s available liquidity. Furthermore, an event of default could result in the Company having to immediately repay all amounts outstanding under

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

the credit facility, the 10.5% Senior Secured Notes and the 3.375% Convertible Senior Notes and in the foreclosure of liens on its assets.

Other than the required prepayments as outlined previously, the principal amount of the term loan amortizes in equal quarterly installments of approximately $1.2 million, with the balance due on July 11, 2013. All borrowings under the revolving credit facility mature on July 11, 2012. Interest payments on both the revolving and term loan facility are due at least on a quarterly basis and in certain instances, more frequently.

As of March 31, 2011, no amounts were outstanding and $12.2 million in standby letters of credit had been issued under the revolving credit facility, therefore the remaining availability under this revolving credit facility was $127.8 million. As of March 31, 2011, $475.2 million was outstanding on the term loan facility and the interest rate was 7.5%. The annualized effective rate of interest was 6.89% for the three months ended March 31, 2011 after giving consideration to revolver fees.

10.5% senior secured notes due 2017

The notional amount of the 10.5% Senior Secured Notes, its unamortized discount and its net carrying amount was $300.0 million, $6.9 million and $293.1 million, respectively, as of March 31, 2011 and $300.0 million, $7.1 million and $292.9 million, respectively, as of December 31, 2010. The unamortized discount is being amortized to interest expense over the life of the 10.5% Senior Secured Notes which ends in October 2017. During the three months ended March 31, 2011, the Company recognized $8.1 million, $5.2 million, net of tax, in interest expense, or $0.05 per diluted share, at an effective rate of 11%, of which $7.9 million related to the coupon rate of 10.5% and $0.2 million related to discount amortization. During the three months ended March 31, 2010, the Company recognized $8.0 million, $5.2 million, net of tax, in interest expense, or $0.05 per diluted share, at an effective rate of 11%, of which $7.9 million related to the coupon rate of 10.5% and $0.1 million related to discount amortization.

The notes are guaranteed by all of the Company’s existing and future restricted subsidiaries that incur or guarantee indebtedness under a credit facility, including the Company’s existing credit facility. The notes are secured by liens on all collateral that secures the Company’s obligations under its secured credit facility, subject to limited exceptions. The liens securing the notes share on an equal and ratable first priority basis with liens securing the Company’s credit facility. Under the intercreditor agreement, the collateral agent for the lenders under the Company’s secured credit facility is generally entitled to sole control of all decisions and actions.

All the liens securing the notes may be released if the Company’s secured indebtedness, other than these notes, does not exceed the lesser of $375.0 million and 15.0% of the Company’s consolidated tangible assets. The Company refers to such a release as a “collateral suspension.” If a collateral suspension is in effect, the notes and the guarantees will be unsecured, and will effectively rank junior to the Company’s secured indebtedness to the extent of the value of the collateral securing such indebtedness. If, after any such release of liens on collateral, the aggregate principal amount of the Company’s secured indebtedness, other than these notes, exceeds the greater of $375.0 million and 15.0% of its consolidated tangible assets, as defined in the indenture, then the collateral obligations of the Company and guarantors will be reinstated and must be complied with within 30 days of such event.

The indenture governing the notes contains covenants that, among other things, limit the Company’s ability and the ability of its restricted subsidiaries to:

	•		incur additional indebtedness or issue certain preferred stock;

	•		pay dividends or make other distributions;

	•		make other restricted payments or investments;

	•		sell assets;

	•		create liens;

	•		enter into agreements that restrict dividends and other payments by restricted subsidiaries;

	•		engage in transactions with its affiliates; and

	•		consolidate, merge or transfer all or substantially all of its assets.

The indenture governing the notes also contains a provision under which an event of default by the Company or by any restricted subsidiary on any other indebtedness exceeding $25.0 million would be considered an event of default under the indenture if such default: a) is caused by failure to pay the principal at final maturity, or b) results in the acceleration of such indebtedness prior to maturity.

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

3.375% convertible senior notes due 2038

The carrying amount of the equity component of the 3.375% Convertible Senior Notes was $30.1 million at both March 31, 2011 and December 31, 2010. The principal amount of the liability component of the 3.375% Convertible Senior Notes, its unamortized discount and its net carrying amount was $95.9 million, $8.5 million and $87.4 million, respectively, as of March 31, 2011 and $95.9 million, $9.4 million and $86.5 million, respectively, as of December 31, 2010. The unamortized discount is being amortized to interest expense over the expected life of the 3.375% Convertible Senior Notes which ends June 1, 2013. During the three months ended March 31, 2011, the Company recognized $1.7 million, $1.1 million, net of tax, in interest expense, or $0.01 per diluted share, at an effective rate of 7.93%, of which $0.8 million related to the coupon rate of 3.375% and $0.9 million related to discount amortization. During the three months ended March 31, 2010, the Company recognized $1.7 million, $1.1 million, net of tax, in interest expense, or $0.01 per diluted share, at an effective rate of 7.93%, of which $0.9 million related to the coupon rate of 3.375% and $0.8 million related to discount amortization.

The notes will be convertible under certain circumstances into shares of the Company’s common stock (“Common Stock”) at an initial conversion rate of 19.9695 shares of Common Stock per $1,000 principal amount of notes, which is equal to an initial conversion price of approximately $50.08 per share. Upon conversion of a note, a holder will receive, at the Company’s election, shares of Common Stock, cash or a combination of cash and shares of Common Stock. At March 31, 2011, the number of conversion shares potentially issuable in relation to the 3.375% Convertible Senior Notes was 1.9 million.

The indenture governing the 3.375% Convertible Senior Notes contains a provision under which an event of default by the Company or by any subsidiary on any other indebtedness exceeding $25.0 million would be considered an event of default under the indenture if such default: a) is caused by failure to pay the principal at final maturity, or b) results in the acceleration of such indebtedness prior to maturity.

The Company determined that upon maturity or redemption it has the intent and ability to settle the principal amount of its 3.375% Convertible Senior Notes in cash, and any additional conversion consideration spread (the excess of conversion value over face value) in shares of the Company’s Common Stock.

Other debt

In connection with the TODCO acquisition in July 2007, one of the Company’s domestic subsidiaries assumed approximately $3.5 million of 7.375% Senior Notes due in April 2018. There are no financial or operating covenants associated with these notes.

7. Derivative Instruments and Hedging

The Company is required to recognize all of its derivative instruments as either assets or liabilities in the statement of financial position at fair value. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and further, on the type of hedging relationship. For those derivative instruments that are designated and qualify as hedging instruments, a company must designate the hedging instrument, based upon the exposure being hedged, as a fair value hedge, cash flow hedge, or a hedge of a net investment in a foreign operation.

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

The Company periodically uses derivative instruments to manage its exposure to interest rate risk, including interest rate swap agreements to effectively fix the interest rate on variable rate debt and interest rate collars to limit the interest rate range on variable rate debt. These hedge transactions have historically been accounted for as cash flow hedges.

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

The Company currently has no interest rate derivatives outstanding. On October 1, 2010, the Company’s zero cost LIBOR collar, entered into in July 2007, was settled per the agreement with a cash payment of $3.4 million. This zero cost LIBOR collar was on $300.0 million of term loan principal with a final settlement date of October 1, 2010 with a ceiling of 5.75% and a floor of 4.99%. The counterparty paid the Company in any quarter that actual LIBOR reset above 5.75% and the Company paid the counterparty in any quarter that actual LIBOR reset below 4.99%. The terms and settlement dates of the collar matched those of the term loan through July 27, 2009, the date of the 2009 Credit Amendment.

As a result of the inclusion of a LIBOR floor in the Credit Agreement, the Company determined, as of July 27, 2009 and on an ongoing basis, that the interest rate collar would not be highly effective in achieving offsetting changes in cash flows attributable to the hedged interest rate risk during the period that the hedge was designated. As such, the Company discontinued cash flow hedge accounting for the interest rate collar as of July 27, 2009. Because cash flow hedge accounting was not applied to this instrument, changes in fair value related to the interest rate collar subsequent to July 27, 2009 were recorded in earnings. As a result of discontinuing the cash flow hedging relationship, the Company recognized a decrease in fair value of $0.4 million related to the hedge ineffectiveness of its interest rate collar as Interest Expense in its Consolidated Statements of Operations for the three months ended March 31, 2010.

The Company was issued warrants to purchase up to 5.0 million additional shares of Discovery Offshore stock at a strike price equivalent to $2.00 which is exercisable in the event that the Discovery Offshore stock price reaches an average equal to or higher than 23 Norwegian Kroner per share, which approximated $4.00 per share as of March 31, 2011, for 30 consecutive trading days (See Note 1). The warrants are being accounted for as a derivative instrument as the underlying security is readily convertible to cash. Subsequent changes in the fair value of the warrants is recognized to other income (expense). If the warrants become exercisable and the Company exercises those warrants, the settlement would be recorded as an increase in the Company’s equity investment in Discovery Offshore. The fair value of the Discovery Offshore warrants was determined using a Monte Carlo simulation (See Note 8).

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


March 31, 2011
Balance Sheet	Fair
Classification	Value
Derivatives:
Warrants:

Other Assets, Net	$	5,215

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

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


	Three Months Ended March 31,
	2011		2010				2011		2010				2011		2010
Derivatives	I.				II.		III.					IV.	V.
Interest rate contracts(a)	$	—	$	—	Interest Expense		$	—	$	(3,198	)	Interest Expense	$	—	$	(363	)
Warrants	$	—	$	—		N/A	$	—	$	—		Revenue	$	31	$	—
Warrants	$	—	$	—		N/A	$	—	$	—		Other Income	$	155	$	—


(a)		These interest rate contracts were designated as cash flow hedges through July 27, 2009.


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

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

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

IV.		Classification of Gain (Loss) Recognized in Income (Loss) on Derivative

V.		Amount of Gain (Loss) Recognized in Income (Loss) on Derivative

8. Fair Value Measurements

FASB ASC Topic 820-10, Fair Value Measurements and Disclosures (“ASC Topic 820-10”) defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles and expands disclosures about fair value measurements; however, it 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.

Fair value measurements are generally based upon observable and unobservable inputs. Observable inputs reflect market data obtained from independent sources, while unobservable inputs reflect the Company’s 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. ASC Topic 820-10 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.

As of January 1, 2010, the Company adopted the FASB Accounting Standards Update (“ASU”) No. 2010-06, Improving Disclosures about Fair Value Measurements (“ASU 2010-06”) which requires additional disclosures about the various classes of assets and liabilities measured at fair value, the valuation techniques and inputs used, the activity in Level 3 fair value measurements and the transfers between Levels 1, 2, and 3. The requirement for disclosures about purchases, sales, issuances and settlements in the roll forward of activity in Level 3 fair value measurements are effective for interim and annual reporting periods beginning after December 15, 2010 and were adopted by the Company on January 1, 2011 (See Note 14).

As of March 31, 2011 the fair value of the Company’s warrants was in an asset position in the amount of $5.2 million. The fair value of the warrants was determined using a Monte Carlo simulation based on the following assumptions:

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


	March 31,
	2011
Strike Price (USD)	$	2.00
Target Price (USD)	$	4.12
Stock Value (USD)	$	2.30
Expected Volatility (%)		50.0	%
Risk-free Interest Rate (%)		2.13	%
Expected Life of Warrants (years)		5.0
Number of Warrants		5,000,000

The Company used the historical volatility of companies similar to that of Discovery Offshore to estimate volatility. The risk-free interest rate assumption was based on observed interest rates consistent with the approximate life of the warrants. The stock price represents the closing stock price of Discovery Offshore stock at March 31, 2011, converted to U.S. Dollars. The strike price, target price, expected life and number of warrants are all contractual based on the terms of the warrant agreement.

The following table represents the Company’s derivative asset measured at fair value on a recurring basis as of March 31, 2011 (in thousands):

Quoted Prices in

Total

Active Markets for

Fair Value

Identical Asset or

Significant Other

Significant

Measurement

Liability

Observable Inputs

Unobservable Inputs

March 31, 2011

(Level 1)

(Level 2)

(Level 3)

Warrants

5,215

—

5,215

—

There were no derivative assets or liabilities outstanding at December 31, 2010.

The following table represents the Company’s assets measured at fair value on a non-recurring basis for which an impairment measurement was made as of December 31, 2010 (in thousands):

Total

Quoted Prices in

Significant

Fair Value

Active Markets for

Other

Significant

Measurement

Identical Asset or

Observable

Unobservable

December 31,

Liability

Inputs

Total

2010

(Level 1)

(Level 2)

(Level 3)

Gain (Loss)

Property and Equipment, Net

27,848

—

27,848

(125,136

)

The Company incurred $125.1 million ($81.3 million, net of tax) in impairment of property and equipment charges related to certain of its assets. The property, plant and equipment was valued based on the discounted cash flows associated with the assets which included management’s estimate of sales proceeds less costs to sell.

The carrying value and fair value of the Company’s equity investment in Discovery Offshore was $18.3 million and $20.0 million at March 31, 2011, respectively. The fair value was calculated using the closing price of Discovery Offshore shares converted to U.S. dollars using the exchange rate at March 31, 2011.

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

Fair Value of Financial Instruments

The carrying amounts of the Company’s financial instruments, which include cash and cash equivalents, restricted cash, accounts receivable, accounts payable and accrued liabilities, approximate fair values because of the short-term nature of the instruments.

The fair value of the Company’s 3.375% Convertible Senior Notes, 10.5% Senior Secured Notes and term loan facility is estimated based on quoted prices in active markets. The fair value of the Company’s 7.375% Senior Notes is estimated based on discounted cash flows using inputs from quoted prices in active markets for similar debt instruments. The following table provides the carrying value and fair value of the Company’s long-term debt instruments:


	March 31, 2011				December 31, 2010
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(in millions)
Term Loan Facility, due July 2013	$	475.2	$	469.1	$	475.2	$	443.7
10.5% Senior Secured Notes, due October 2017		293.1		307.7		292.9		245.1
3.375% Convertible Senior Notes, due June 2038		87.4		90.9		86.5		69.1
7.375% Senior Notes, due April 2018		3.5		3.0		3.5		2.2

9. Long-Term Incentive Awards

Stock-based Compensation

The Company’s 2004 Long-Term Incentive Plan (the “2004 Plan”) provides for the granting of stock options, restricted stock, performance stock awards and other stock-based awards to selected employees and non-employee directors of the Company. At March 31, 2011, approximately 0.9 million shares were available for grant or award under the 2004 Plan.

During the three months ended March 31, 2011, the Company granted 988,549 time-based restricted stock awards with a weighted average grant-date fair value per share of $4.89. There were no stock options granted during the three months ended March 31, 2011. The Company recognized $1.2 million in stock-based compensation expense during the three months ended March 31, 2011. The Company recognized $0.2 million in stock-based compensation expense during the three months ended March 31, 2010 which includes a reduction of $1.8 million due to a change in the Company’s estimated forfeiture rate.

On March 6, 2011, the Compensation Committee of the Company’s Board of Directors approved equity grants for certain of its executive officers which consisted of a time-based vesting restricted stock award and a performance-based restricted stock award. The grants vest one-third per year on each of the first three anniversaries of the grant date; however, the vesting of the performance grant is contingent upon meeting the established consolidated safety and EBITDA metrics at a weighting of 50% each, with vesting prorated between threshold, target and maximum levels. Threshold, target and maximum performance objectives have been established for each metric, with the officer vesting 33% more shares at the maximum level, 33% less shares at the threshold level, with vesting pro rated between levels, and no shares will be issued with respect to a particular metric if the threshold performance objective is not met with respect to such metric. The target number of performance-based restricted stock issuable under this award if conditions for vesting are met is 507,509 shares. The fair value of these awards was based on the closing price of the Company’s stock on the date of grant.

The unrecognized compensation cost related to the Company’s unvested stock options and restricted stock grants, including performance-based restricted stock grants as of March 31, 2011 was $2.1 million and $7.8 million, respectively, and is expected to be recognized over a weighted-average period of 1.2 years and 2.4 years, respectively.

Liability Retention Awards

In December 2010, the Compensation Committee of the Company’s Board of Directors approved retention and incentive arrangements for the Company’s Chief Executive Officer, consisting of three separate awards.

Vesting under each award is conditioned upon continuous employment with the Company from the date of grant until the earlier of a specified vesting date or a change in control of the Company. Subject to the satisfaction of all vesting requirements, awards are payable in cash based on the product of the number of shares of Common Stock specified in the award, the percentage of that number of shares that vest under the award and the average price of the Common Stock for the 90 days prior to the date of vesting (“Average Share Price”).

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

The grant date of each of the three awards is January 1, 2011. Vesting of any award and the amount payable under any vested award do not affect vesting or the amount payable under any of the other awards. Subject to vesting, all awards are payable in cash within thirty days of vesting. No shares of common stock are issuable under any of the awards. These awards are accounted for under stock-compensation principles of accounting as liability instruments. The fair value of these awards is remeasured based on the awards’ estimated fair value at the end of each reporting period and will be recorded to expense over the vesting period. At March 31, 2011, the Company’s liability related to these awards was $0.3 million and is included in Other Liabilities on the Consolidated Balance Sheets. Additionally, compensation expense of $0.3 million was recognized for the three months ended March 31, 2011.

The first award is a Special Retention Agreement (the “Agreement”), which provides for a cash payment based on 500,000 shares of the Company’s common stock, subject to vesting. Upon satisfaction of vesting requirements, 100% of the amount under the Agreement becomes vested on December 31, 2013 and the payout will equal the product of 500,000 and the lesser of the Average Share Price and $10.00. If all of the requirements necessary for vesting of this award are not met, no amounts become vested and no amount is payable. The fair value of this award is based on the average price of the Common Stock for the 90 days prior to the end of the quarter or date of vesting.

The second and third awards are performance awards under the 2004 Plan (“Performance Awards”). Each Performance Award provides for a cash payment, subject to vesting, based on 250,000 shares of the Company’s common stock. Upon satisfaction of vesting requirements, 100% of the first Performance Award will vest on December 31, 2013, and 100% of the second Performance Award will vest on March 31, 2014. Under each Performance Award, vesting is subject to the further requirement that the Average Share Price is at least $5.00. Subject to the satisfaction of the vesting requirements, the payout of each Performance Award shall be equal to the product of (1) 250,000, (2) the Average Share Price or $10.00, whichever is less, divided by $10.00, and (3) the lesser of the Average Share Price or $10.00. If the requirements necessary for vesting of a Performance Award are met, the amount payable in cash under each of the Performance Awards shall be not less than $625,000 and not more than $2,500,000. The fair value of these awards was determined at March 31, 2011 using a Monte Carlo simulation based on the following assumptions:


	March 31,
	2011

Dividend Yield		—
Expected Price Volatility		50	%
Risk-Free Interest Rate		1.3	%
Stock Price	$	6.61
Fair Value	$	3.32

The Company used the historical volatility of its common stock to estimate volatility. The dividend yield assumption was based on historical and anticipated dividend payouts. The risk-free interest rate assumption was based on observed interest rates consistent with the approximate vesting period. The stock price represents the closing price of the Company’s common stock at March 31, 2011.

10. Supplemental Cash Flow Information

The Company had non-cash investing activities related to its equity investment in Discovery Offshore as 500,000 shares of Discovery Offshore valued at $1.0 million were received by the Company as reimbursement for costs incurred and efforts expended in forming Discovery offshore. In addition, the Company purchased 3,203,700 shares of Discovery Offshore for $7.3 million which were not cash settled until April 2011.


	Three Months Ended March 31,
	2011			2010
	(In thousands)
Cash paid (received), net during the period for:
Interest	$	41		$	60
Income taxes		(4,199	)		11,321

11. Income Tax

The Company, directly or through its subsidiaries, files income tax returns in the United States, and multiple state and foreign jurisdictions. The Company’s tax returns for 2005 through 2009 remain open for examination by the taxing authorities in the respective jurisdictions where those returns were filed. Although, the Company believes that its estimates are reasonable, the final outcome in the

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

event that the Company is subjected to an audit could be different from that which is reflected in its historical income tax provision and accruals. Such differences could have a material effect on the Company’s income tax provision and net income in the period in which such determination is made. In addition, certain tax returns filed by TODCO and its subsidiaries are open for years prior to 2004, however TODCO tax obligations from periods prior to its initial public offering in 2004 are indemnified by Transocean under the tax sharing agreement, except for the Trinidad and Tobago jurisdiction. The Company’s Trinidadian tax returns are open for examination for the years 2005 through 2009.

In December 2002, TODCO received an assessment from SENIAT, the national Venezuelan tax authority, relating to calendar years 1998 through 2001. After a series of partial payments and appeals, in July 2009, the Company settled the remaining tax and interest portion of the assessment. Residual penalties of $0.8 million (based on the official exchange rate at March 31, 2011) remain in dispute. The Company, as successor to TODCO, is fully indemnified by TODCO’s former parent, Transocean Ltd. for this issue. The Company does not expect the ultimate resolution of this assessment and settlement to have a material impact on its consolidated financial statements. In January 2008, SENIAT commenced an audit for the 2003 calendar year, which was completed in the fourth quarter of 2008. The Company has not yet received any proposed adjustments from SENIAT for that year.

In March 2007, a subsidiary of the Company received an assessment from the Mexican tax authorities related to its operations for the 2004 tax year. This assessment contested the Company’s right to certain deductions and also claimed it did not remit withholding tax due on certain of these deductions. In accordance with local statutory requirements, the Company provided a surety bond for an amount equal to approximately $13 million, which was released in July 2010, to contest these assessments. In 2008, the Mexican tax authorities commenced an audit for the 2005 tax year. During 2010, the Company effectively reached a compromise settlement of all issues for 2004-2007. The Company paid $11.6 million and reversed (i) previously provided reserves and (ii) an associated tax benefit in the year ended December 31, 2010 which totaled $5.8 million, of which the initial impact for the three months ended March 31, 2010 was $6.2 million.

As of March 31, 2011, the Company was in a net income tax payable position of $9.6 million which is included in Taxes Payable on the Consolidated Balance Sheets and as of December 31, 2010, the Company was in a net income tax receivable position of $5.6 million which is included in Other on the Consolidated Balance Sheets.

12. Segments

The Company reports its business activities in six business segments: (1) Domestic Offshore, (2) International Offshore, (3) Inland, (4) Domestic Liftboats, (5) International Liftboats and (6) Delta Towing. The Company eliminates inter-segment revenue and expenses, if any.

The following describes the Company’s reporting segments as of March 31, 2011:

Domestic Offshore — includes 22 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. Ten of the jackup rigs are either working on short-term contracts or available for contracts, one is in the shipyard and eleven are cold-stacked. All three submersibles are cold-stacked.

International Offshore — includes eight jackup rigs and one platform rig outside of the U.S. Gulf of Mexico. The Company has two jackup rigs working offshore in each of India and Saudi Arabia, one jackup rig contracted offshore in Malaysia, one jackup rig contracted in Angola and one platform rig under contract in Mexico. The Company has one jackup rig warm-stacked and one jackup rig cold-stacked in Bahrain. In addition, to owning and operating its own rigs, the Company has an agreement with COSL to market and operate a jackup rig in Angola. Further, the Company has the Construction Management Agreement and the Services Agreement with Discovery Offshore with respect to each of the Rigs. (See Note 1). There was no revenue or expense associated with the COSL agreement, nor the Construction Management Agreement and Services Agreement with Discovery Offshore during the three months ended March 31, 2011.

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

Domestic Liftboats — includes 41 liftboats in the U.S. Gulf of Mexico. Thirty-eight are operating or available and three are cold-stacked.

International Liftboats — includes 24 liftboats. Twenty-one are operating or available for contracts offshore West Africa, including five liftboats owned by a third party, one is cold-stacked offshore West Africa and two are operating or available for contracts in the Middle East region.

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

Delta Towing — the Company’s Delta Towing business operates a fleet of 29 inland tugs, 10 offshore tugs, 34 crew boats, 46 deck barges, 16 shale barges and five spud barges along and in the U.S. Gulf of Mexico and from time to time along the Southeastern coast and in Mexico. Of these vessels, 24 crew boats, 11 inland tugs, three offshore tugs, one deck barge and one spud barge are cold-stacked, and the remaining are working, being repaired or available for contracts.

The Company’s jackup rigs, submersible rigs and platform rigs are used primarily for exploration and development drilling in shallow waters. The Company’s liftboats are self-propelled, self-elevating vessels with a large open deck space, which provides a versatile, mobile and stable platform to support a broad range of offshore maintenance and construction services throughout the life of an oil or natural gas well.

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


	Three Months Ended March 31, 2011
			Income (Loss)			Depreciation &
	Revenue		from Operations			Amortization
Domestic Offshore	$	33,799	$	(25,130	)	$	15,082
International Offshore		77,119		32,674			13,300
Inland		5,502		(6,379	)		4,621
Domestic Liftboats		10,631		(3,369	)		3,641
International Liftboats		32,327		11,601			4,498
Delta Towing		6,868		(438	)		1,118

		166,246		8,959			42,260
Corporate		—		(11,019	)		651

Total Company	$	166,246	$	(2,060	)	$	42,911


	Three Months Ended March 31, 2010
			Income (Loss)			Depreciation &
	Revenue		from Operations			Amortization
Domestic Offshore	$	28,962	$	(30,126	)	$	16,539
International Offshore		73,442		22,486			14,931
Inland		4,751		(5,307	)		7,506
Domestic Liftboats		11,443		(2,566	)		4,200
International Liftboats		25,962		5,303			4,691
Delta Towing		6,289		(941	)		1,590

		150,849		(11,151	)		49,457
Corporate		—		(9,193	)		797

Total Company	$	150,849	$	(20,344	)	$	50,254


	Total Assets
	March 31,		December 31,
	2011		2010
Domestic Offshore	$	785,683	$	772,950
International Offshore		743,054		712,988
Inland		127,933		136,229
Domestic Liftboats		80,823		86,013
International Liftboats		168,079		167,561
Delta Towing		53,312		56,631
Corporate		57,806		62,937

Total Company	$	2,016,690	$	1,995,309

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

13. Commitments and Contingencies

Legal Proceedings

The Company is involved in various claims and lawsuits in the normal course of business. As of March 31, 2011, management did not believe any accruals were necessary in accordance with FASB Codification Topic 450-20, Contingencies — Loss Contingencies.

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

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

Robert E. Aaron et al. vs. Phillips 66 Company et al. Circuit Court, Second Judicial District, Jones County, Mississippi. This is the case name used to refer to several cases that have been filed in the Circuit Courts of the State of Mississippi involving 768 persons that allege personal injury or whose heirs claim their deaths arose out of asbestos exposure in the course of their employment by the defendants between 1965 and 2002. The complaints name as defendants, among others, certain of TODCO’s subsidiaries and certain subsidiaries of TODCO’s former parent to whom TODCO may owe indemnity, and other unaffiliated defendant companies, including companies that allegedly manufactured drilling related products containing asbestos that are the subject of the complaints. The number of unaffiliated defendant companies involved in each complaint ranges from approximately 20 to 70. The complaints allege that the defendant drilling contractors used asbestos-containing products in offshore drilling operations, land based drilling operations and in drilling structures, drilling rigs, vessels and other equipment and assert claims based on, among other things, negligence and strict liability, and claims authorized under the Jones Act. The plaintiffs seek, among other things, awards of unspecified compensatory and punitive damages. All of these cases were assigned to a special master who has approved a form of questionnaire to be completed by plaintiffs so that claims made would be properly served against specific defendants. 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 has not determined which entity would be responsible for such claims under the Master Separation Agreement between TODCO and its former parent. More than three years has passed since the court ordered that amended complaints be filed by each individual plaintiff, and the original complaints. No additional plaintiffs have attempted to name TODCO as a defendant and such actions may now be time-barred. The Company intends to defend vigorously and 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 statements.

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

Insurance

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

subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect the Company against liability from all potential consequences. In addition, there is no assurance of renewal or the ability to obtain coverage acceptable to the Company.

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

As of March 31, 2011, the Company’s primary marine package provides for hull and machinery coverage for substantially all of the Company’s rigs and liftboats up to a scheduled value of each asset. The total maximum amount of coverage for these assets is $2.1 billion. The marine package includes protection and indemnity and maritime employer’s liability coverage for marine crew personal injury and death and certain operational liabilities, with primary coverage (or self-insured retention for maritime employer’s liability coverage) of $5.0 million per occurrence with excess liability coverage up to $200.0 million. The marine package policy also includes coverage for personal injury and death of third-parties with primary and excess coverage of $25 million per occurrence with additional excess liability coverage up to $200 million, subject to a $250,000 per-occurrence deductible. The marine package also provides coverage for cargo and charterer’s legal liability. The marine package includes limitations for coverage for losses caused in U.S. Gulf of Mexico named windstorms, including an annual aggregate limit of liability of $100.0 million for property damage and removal of wreck liability coverage. The Company also procured an additional $75.0 million excess policy for removal of wreck and certain third-party liabilities incurred in U.S. Gulf of Mexico named windstorms. Deductibles for events that are not caused by a U.S. Gulf of Mexico named windstorm are 12.5% of the insured drilling rig values per occurrence, subject to a minimum of $1.0 million, and $1.0 million per occurrence for liftboats. The deductible for drilling rigs and liftboats in a U.S. Gulf of Mexico named windstorm event is $25.0 million. Vessel pollution is covered under a Water Quality Insurance Syndicate policy (“WQIS Policy”) providing limits as required by applicable law, including the Oil Pollution Act of 1990. The WQIS Policy covers pollution emanating from the Company’s vessels and drilling rigs, with primary limits of $5 million (inclusive of a $3.0 million per-occurrence deductible) and excess liability coverage up to $200 million.

Control-of-well events generally include an unintended flow from the well that cannot be contained by equipment on site (e.g., a blow-out preventer), by increasing the weight of the drilling fluid or that does not naturally close itself off through what is typically described as bridging over. The Company carries a contractor’s extra expense policy with $50 million primary covering liability for well control costs, expenses incurred to redrill wild or lost wells and pollution, with excess liability coverage up to $200 million for pollution liability that is covered in the primary policy. The policies are subject to exclusions, limitations, deductibles, self-insured retention and other conditions. In addition to the marine package, the Company has separate policies providing coverage for onshore foreign and domestic general liability, employer’s liability, auto liability and non-owned aircraft liability, with customary deductibles and coverage as well as a separate underlying marine package for its Delta Towing business.

The Company’s drilling contracts provide for varying levels of indemnification from its customers and in most cases, may require the Company to indemnify its customers for certain liabilities. Under the Company’s drilling contracts, liability with respect to personnel and property is customarily assigned on a “knock-for-knock” basis, which means that the Company and its customers assume liability for the Company’s respective personnel and property, regardless of how the loss or damage to the personnel and property may be caused. The Company’s customers typically assume responsibility for and agree to indemnify the Company from any loss or liability resulting from pollution or contamination, including clean-up and removal and third-party damages arising from operations under the contract and originating below the surface of the water, including as a result of blow-outs or cratering of the well (“Blowout Liability”). The customer’s assumption for Blowout Liability may, in certain circumstances, be limited or could be determined to be unenforceable in the event of the gross negligence, willful misconduct or other egregious conduct of the Company. The Company generally indemnifies the customer for the consequences of spills of industrial waste or other liquids originating solely above the surface of the water and emanating from its rigs or vessels.

In 2010, 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 $25.9 million was financed through these arrangements, of which $0.7 million and $6.0 million was outstanding as of March 31, 2011 and December 31, 2010, respectively. The interest rate on the $24.1 million note was 3.79% and it was fully paid as of March 31, 2011. The interest rate on the $1.8 million note is 3.54% and the note is scheduled to mature in July 2011.

In April 2011, the Company completed its annual renewal and revised its insurance coverage to include the assets from the Seahawk asset purchase (See Note 15).

Surety Bonds, Bank Guarantees and Unsecured Letters of Credit

The Company had $11.2 million outstanding related to surety bonds at March 31, 2011. The surety bonds guarantee the Company’s performance as it relates to its drilling contracts 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 in Mexico and the U.S.

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

The Company had $1.0 million in unsecured bank guarantees and a $0.1 million unsecured letter of credit outstanding at March 31, 2011.

Sales Tax Audits

Certain of the Company’s legal entities obtained in the TODCO acquisition are under audit by various taxing authorities for several prior-year periods. These audits are ongoing and the Company is working to resolve all relevant issues, however, the Company has accrued approximately $5.9 million as of March 31, 2011 while the Company provides additional information and responds to auditor requests.

14. Accounting Pronouncements

In December 2010, the FASB issued ASU No. 2010-29, Disclosure of Supplementary Pro Forma Information for Business Combinations (“ASU 2010-29”), which amends and clarifies the acquisition date that should be used for reporting the pro forma financial disclosures in Topic 805 when comparative financial statements are presented. It also requires a description of the nature and amount of material, nonrecurring pro forma adjustments that are directly attributable to the business combination. ASU 2010-29 is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010 with early adoption permitted. The Company has adopted this standard with no material impact on its consolidated financial statements as it only amends required disclosures. The Company will comply with the provisions of this update for its Seahawk asset purchase which closed April 27, 2011 (See Notes 4 and 15).

In January 2010, the FASB issued ASU 2010-06 which requires additional disclosures about the various classes of assets and liabilities measured at fair value, the valuation techniques and inputs used, the activity in Level 3 fair value measurements and the transfers between Levels 1, 2, and 3. The disclosures are effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements, which are effective for interim and annual reporting periods beginning after December 15, 2010. The Company adopted the required portions of ASU 2010-06 as of January 1, 2010 with no material impact to its consolidated financial statements and adopted the remaining portions on January 1, 2011 with no material impact on its consolidated financial statements (See Note 8).

15. Subsequent Events

Investigations

Shareholder Derivative Suit

On April 27, 2011, a shareholder derivative action was filed in the District Court of Harris County, Texas, allegedly on behalf of and for the benefit of the Company, naming the Company as a nominal defendant and certain of our officers and directors as defendants alleging, among other claims, breach of fiduciary duty, abuse of control, waste of corporate assets, and unjust enrichment. The petition alleges that the individual defendants allowed the Company to violate the U.S. Foreign Corrupt Practices Act (“FCPA”) and failed to maintain internal controls and accounting systems for compliance with the FCPA. Plaintiffs seek damages, restitution and injunctive and/or equitable relief purportedly on behalf of the Company, certain corporate actions, and an award of their costs and attorney’s fees.

Asset Purchase

On April 27, 2011, the Company completed the Seahawk asset purchase (See Note 4).

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

Insurance Renewal

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

In April 2011, the Company completed the annual renewal of all of its key insurance policies. The Company’s primary marine package provides for hull and machinery coverage for substantially all of the Company’s rigs and liftboats up to a scheduled value of each asset. The total maximum amount of coverage for these assets is $1.6 billion, including the newly acquired Seahawk units. The marine package includes protection and indemnity and maritime employer’s liability coverage for marine crew personal injury and death and certain operational liabilities, with primary coverage (or self-insured retention for maritime employer’s liability coverage) of $5.0 million per occurrence with excess liability coverage up to $200.0 million. The marine package policy also includes coverage for personal injury and death of third-parties with primary and excess coverage of $25 million per occurrence with additional excess liability coverage up to $200 million, subject to a $250,000 per-occurrence deductible. The marine package also provides coverage for cargo and charterer’s legal liability. The marine package includes limitations for coverage for losses caused in U.S. Gulf of Mexico named windstorms, including an annual aggregate limit of liability of $75.0 million for property damage and removal of wreck liability coverage. The Company also procured an additional $75.0 million excess policy for removal of wreck and certain third-party liabilities incurred in U.S. Gulf of Mexico named windstorms. Deductibles for events that are not caused by a U.S. Gulf of Mexico named windstorm are 12.5% of the insured drilling rig values per occurrence, subject to a minimum of $1.0 million, and $1.0 million per occurrence for liftboats. The deductible for drilling rigs and liftboats in a U.S. Gulf of Mexico named windstorm event is $25.0 million. Vessel pollution is covered under a Water Quality Insurance Syndicate policy (“WQIS Policy”) providing limits as required by applicable law, including the Oil Pollution Act of 1990. The WQIS Policy covers pollution emanating from the Company’s vessels and drilling rigs, with primary limits of $5 million (inclusive of a $3.0 million per-occurrence deductible) and excess liability coverage up to $200 million.

Control-of-well events generally include an unintended flow from the well that cannot be contained by equipment on site (e.g., a blow-out preventer), by increasing the weight of the drilling fluid or that does not naturally close itself off through what is typically described as bridging over. The Company carries a contractor’s extra expense policy with $25.0 million primary covering liability for well control costs, expenses incurred to redrill wild or lost wells and pollution, with excess liability coverage up to $200 million for pollution liability that is covered in the primary policy. The policies are subject to exclusions, limitations, deductibles, self-insured retention and other conditions. In addition to the marine package, the Company has separate policies providing coverage for onshore foreign and domestic general liability, employer’s liability, auto liability and non-owned aircraft liability, with customary deductibles and coverage as well as a separate underlying marine package for its Delta Towing business.

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, 2011 and for the three months ended March 31, 2011 and 2010, included elsewhere herein, and with our Annual Report on Form 10-K for the year ended December 31, 2010. 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 on Form 10-K for the year ended December 31, 2010 for a discussion of certain risks facing our company.

OVERVIEW

We are a leading provider of shallow-water drilling and marine services to the oil and natural gas exploration and production industry globally. We provide these services to national oil and gas companies, major integrated energy companies and independent oil and natural gas operators. In February 2011, we entered into an asset purchase agreement (the “Asset Purchase Agreement”) with Seahawk Drilling, Inc. and certain of its subsidiaries (“Seahawk”), pursuant to which Seahawk agreed to sell us 20 jackup rigs and related assets, accounts receivable, cash and certain liabilities. On April 27, 2011, we completed the Seahawk asset purchase (See Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operation — Recent Developments). Including the assets acquired in the Seahawk transaction, we own a fleet of 50 jackup rigs, 17 barge rigs, three submersible rigs, one platform rig, a fleet of marine support vessels operated through Delta Towing, a wholly owned subsidiary, and 60 liftboat vessels and operate an additional five liftboat vessels owned by a third party. Our diverse fleet is capable of providing services such as oil and gas exploration and development drilling, well service, platform inspection, maintenance and decommissioning operations in several key shallow water provinces around the world.

Investment

In January 2011, we paid $10 million to purchase 5.0 million shares, an initial investment in approximately eight percent of the total outstanding equity of a new entity incorporated in Luxembourg, Discovery Offshore S.A. (“Discovery Offshore”), which investment was used by Discovery Offshore towards funding the down payments on two new-build ultra high specification harsh environment jackup drilling rigs (collectively the “Rigs” or individually “Rig”). The Rigs, Keppel FELS “Super A” design, are being constructed by Keppel FELS in its Singapore shipyard and have a maximum water depth rating of 400 feet, two million pound hook load capacity, and are capable of drilling up to 35,000 feet deep. The two Rigs are expected to be delivered in the second and fourth quarter of 2013, respectively. Discovery Offshore also holds options to purchase two additional rigs of the same specifications, which must be exercised by the third and fourth quarter of 2011, with delivery dates expected in the second and fourth quarter of 2014, respectively.

We also executed a construction management agreement (the “Construction Management Agreement”) and a services agreement (the “Services Agreement”) with Discovery Offshore with respect to each of the Rigs. Under the Construction Management Agreements, we will plan, supervise and manage the construction and commissioning of the Rigs in exchange for a fixed fee of $7.0 million per Rig, which we received in February 2011. Pursuant to the terms of the Services Agreements, we will market, manage, crew and operate the Rigs and any other rigs that Discovery Offshore subsequently acquires or controls, in exchange for a fixed daily fee of $6,000 per Rig plus five percent of Rig-based EBITDA (EBITDA excluding SG&A expense) generated per day per Rig, which commences once the Rigs are completed and operating. Under the Services Agreements, Discovery Offshore will be responsible for operational and capital expenses for the Rigs. We are entitled to a minimum fee of $5 million per Rig in the event Discovery Offshore terminates a Services Agreement in the absence of a breach of contract by Hercules Offshore.

In addition to the $10 million investment, we received 500,000 additional shares worth $1.0 million to cover our costs incurred and efforts expended in forming Discovery Offshore. We were issued warrants to purchase up to 5.0 million additional shares of Discovery Offshore stock at a strike price equivalent to $2.00 which is exercisable in the event that the Discovery Offshore stock price reaches an average equal to or higher than 23 Norwegian Kroner per share, which approximated $4.00 per share as of March 31, 2011, for 30 consecutive trading days. The warrants were issued to additionally compensate us for our costs incurred and efforts expended in forming Discovery Offshore. The warrants are being accounted for as a derivative instrument. The initial fair value of the warrants and the 500,000 additional shares have been recorded to deferred revenue to be amortized over 30 years, the useful life of the Rigs. We have no other financial obligations

or commitments with respect to the Rigs or our ownership in Discovery Offshore. Two of our officers are on the Board of Directors of Discovery Offshore.

We report our business activities in six business segments, which, as of April 27, 2011, included the following:

Domestic Offshore — includes 42 jackup rigs and three submersible rigs in the U.S. Gulf of Mexico that can drill in maximum water depths ranging from 80 to 350 feet. Fifteen of the jackup rigs are either working on short-term contracts or available for contracts, three are in the shipyard and 24 are cold-stacked. All three submersibles are cold-stacked.

International Offshore — includes eight jackup rigs and one platform rig outside of the U.S. Gulf of Mexico. We have two jackup rigs working offshore in each of India and Saudi Arabia, one jackup rig contracted offshore in Malaysia, one jackup rig contracted in Angola and one platform rig under contract in Mexico. In addition, we have one jackup rig warm-stacked and one jackup rig cold-stacked in Bahrain.

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

Domestic Liftboats — includes 41 liftboats in the U.S. Gulf of Mexico. Thirty-six are operating or available and five are cold-stacked.

Delta Towing — our Delta Towing business operates a fleet of 29 inland tugs, 10 offshore tugs, 34 crew boats, 46 deck barges, 16 shale barges and five spud barges along and in the U.S. Gulf of Mexico and from time to time along the Southeastern coast and in Mexico. Of these vessels, 24 crew boats, 11 inland tugs, three offshore tugs, one deck barge and one spud barge are cold-stacked, and the remaining are working, being repaired or available for contracts.

In November 2010, we entered into an agreement to sell our retired jackups Hercules 190 and Hercules 254 for a total of $4.0 million for both jackups, which is expected to close in the second quarter of 2011. In March 2011, we entered into an agreement to sell our submersible rig Hercules 78 for $1.8 million, which is expected to close in the second quarter of 2011. The financial information for Hercules 190, Hercules 254 and Hercules 78 has been reported as part of the Domestic Offshore segment.

In April 2011, we entered into an agreement to sell our jackup Hercules 152 for a purchase price of $5.0 million.

In January 2011, we entered into an agreement with China Oilfield Services Limited (“COSL”) whereby we will market and operate a Friede & Goldman JU2000E jackup drilling rig with a maximum water depth of 400 feet. The agreement is limited to a specified opportunity in Angola.

In March, 2011, at our request, the parties agreed to terminate, without the payment of a termination fee, the management agreement with First Energy Bank B.S.C. (“MENAdrill”) with respect to Hull 110.

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 with a large open deck space which provides a versatile, mobile and stable platform to support a broad range of offshore maintenance and construction 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 revenue is affected primarily by dayrates, fleet utilization, the number and type of units in our fleet and mobilization fees received from our customers. Utilization and dayrates, in turn, are influenced principally by the demand for rig and liftboat services from the exploration and production sectors of the oil and natural gas industry. Our contracts in the U.S. Gulf of Mexico tend to be short-term in nature and are heavily influenced by changes in the supply of units relative to the fluctuating expenditures for both drilling and production activity. Our international drilling contracts and some of our liftboat contracts in West Africa are longer term in nature.

Our backlog at April 27, 2011 totaled approximately $211.6 million for our executed contracts, including those related to assets purchased from Seahawk. Approximately $165.7 million of this backlog is expected to be realized during the remainder of 2011. 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 revenue for mobilization, demobilization, contract preparation and customer reimbursables. The amount of actual revenue earned and the actual periods during which revenue is earned will be different than the backlog disclosed or expected due to various factors. Downtime due to various operational factors, including unscheduled repairs, maintenance, weather and other factors (some of which are beyond our control), may result in lower dayrates than the full contractual operating dayrate. In some of the contracts, our customer has the right to terminate the contract without penalty and in certain instances, with little or no notice.

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

The most significant costs for our Domestic Liftboats and International Liftboats segments are the wages paid to crews and the amortization of regulatory drydocking costs. Unlike our Domestic Offshore, International Offshore and Inland segments, a significant portion of the expenses incurred with operating each liftboat are paid for or reimbursed by the customer under contractual terms and prices. This includes catering, fuel, oil, rental equipment, crane overtime and other items. We record reimbursements from customers as revenue 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

Investigations

On April 4, 2011, we received a subpoena issued by the Securities and Exchange Commission (“SEC”) requesting the delivery of certain documents to the SEC in connection with its investigation into possible violations of the securities laws, including possible violations of the Foreign Corrupt Practices Act (“FCPA”) in certain international jurisdictions where we conduct operations. We were also notified by the Department of Justice (“DOJ”) on April 5, 2011, that certain of our activities are under review by the DOJ.

We, through the Audit Committee of the Board of Directors, have engaged an outside law firm with significant experience in FCPA-related matters to conduct an internal review, and intend to cooperate with the SEC and DOJ in their investigations. At this time, it is not possible to predict the outcome of the investigations, the expenses we will incur associated with these matters, or the impact on the price of our common stock or other securities as a result of these investigations.

Asset Purchase

On April 27, 2011, we completed our acquisition of 20 jackup rigs and related assets, accounts receivable, cash and certain liabilities from Seahawk for total consideration of approximately $151.8 million consisting of $25.0 million of cash and 22.3 million Hercules common shares. The fair value of the shares issued was determined using the closing price of our stock of $5.68 on April 27, 2011.

Insurance Renewal

We are self-insured for the deductible portion of our insurance coverage. We believe adequate accruals have been made on known and estimated exposures up to the deductible portion of our insurance coverage. We believe that claims and liabilities in excess of the amounts accrued are adequately insured. However, our insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect us against liability from all potential consequences. In addition, there is no assurance of renewal or the ability to obtain coverage acceptable to us.

We maintain insurance coverage that includes coverage for physical damage, third party liability, workers’ compensation and employer’s liability, general liability, vessel pollution and other coverages.

In April 2011, we completed the annual renewal of all of our key insurance policies. Our primary marine package provides for hull and machinery coverage for substantially all of our rigs and liftboats up to a scheduled value of each asset. The total maximum amount of coverage for these assets is $1.6 billion, including the newly acquired Seahawk units. The marine package includes protection and indemnity and maritime employer’s liability coverage for marine crew personal injury and death and certain operational liabilities, with primary coverage (or self-insured retention for maritime employer’s liability coverage) of $5.0 million per occurrence with excess liability coverage up to $200.0 million. The marine package policy also includes coverage for personal injury and death of third-parties with primary and excess coverage of $25 million per occurrence with additional excess liability coverage up to $200 million, subject to a $250,000 per-occurrence deductible. The marine package also provides coverage for cargo and charterer’s legal liability. The marine package includes limitations for coverage for losses caused in U.S. Gulf of Mexico named windstorms, including an annual aggregate limit of liability of $75.0 million for property damage and removal of wreck liability coverage. We also procured an additional $75.0 million excess policy for removal of wreck and certain third-party liabilities incurred in U.S. Gulf of Mexico named windstorms. Deductibles for events that are not caused by a U.S. Gulf of Mexico named windstorm are 12.5% of the insured drilling rig values per occurrence, subject to a minimum of $1.0 million, and $1.0 million per occurrence for liftboats. The deductible for drilling rigs and liftboats in a U.S. Gulf of Mexico named windstorm event is $25.0 million. Vessel pollution is covered under a Water Quality Insurance Syndicate policy (“WQIS Policy”) providing limits as required by applicable law, including the Oil Pollution Act of 1990. The WQIS Policy covers pollution emanating from our vessels and drilling rigs, with primary limits of $5 million (inclusive of a $3.0 million per-occurrence deductible) and excess liability coverage up to $200 million.

described as bridging over. We carry a contractor’s extra expense policy with $25.0 million primary covering liability for well control costs, expenses incurred to redrill wild or lost wells and pollution, with excess liability coverage up to $200 million for pollution liability that is covered in the primary policy. The policies are subject to exclusions, limitations, deductibles, self-insured retention and other conditions. In addition to the marine package, we have separate policies providing coverage for onshore foreign and domestic general liability, employer’s liability, auto liability and non-owned aircraft liability, with customary deductibles and coverage as well as a separate underlying marine package for our Delta Towing business.

Our drilling contracts provide for varying levels of indemnification from our customers and in most cases, may require us to indemnify our customers for certain liabilities. Under our drilling contracts, liability with respect to personnel and property is customarily assigned on a “knock-for-knock” basis, which means that we and our customers assume liability for our respective personnel and property, regardless of how the loss or damage to the personnel and property may be caused. Our customers typically assume responsibility for and agree to indemnify us from any loss or liability resulting from pollution or contamination, including clean-up and removal and third-party damages arising from operations under the contract and originating below the surface of the water, including as a result of blow-outs or cratering of the well (“Blowout Liability”). The customer’s assumption for Blowout Liability may, in certain circumstances, be limited or could be determined to be unenforceable in the event of the gross negligence, willful misconduct or other egregious conduct of us. We generally indemnify the customer for the consequences of spills of industrial waste or other liquids originating solely above the surface of the water and emanating from our rigs or vessels.

RESULTS OF OPERATIONS

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


	Three Months Ended
	March 31
	2011			2010
	(Dollars in thousands)
Domestic Offshore:
Number of rigs (as of end of period)		25			25
Revenue	$	33,799		$	28,962
Operating expenses		41,002			39,152
Depreciation and amortization expense		15,082			16,539
General and administrative expenses		2,845			3,397

Operating loss	$	(25,130	)	$	(30,126	)

International Offshore:
Number of rigs (as of end of period)		9			9
Revenue	$	77,119		$	73,442
Operating expenses		33,828			34,719
Depreciation and amortization expense		13,300			14,931
General and administrative expenses		(2,683	)		1,306

Operating income	$	32,674		$	22,486

Inland:
Number of barges (as of end of period)		17			17
Revenue	$	5,502		$	4,751
Operating expenses		7,030			5,717
Depreciation and amortization expense		4,621			7,506
General and administrative expenses		230			(3,165	)

Operating loss	$	(6,379	)	$	(5,307	)

Domestic Liftboats:
Number of liftboats (as of end of period)		41			41
Revenue	$	10,631		$	11,443
Operating expenses		9,864			9,314
Depreciation and amortization expense		3,641			4,200
General and administrative expenses		495			495

Operating loss	$	(3,369	)	$	(2,566	)

International Liftboats:
Number of liftboats (as of end of period)		24			24
Revenue	$	32,327		$	25,962
Operating expenses		14,657			14,462
Depreciation and amortization expense		4,498			4,691
General and administrative expenses		1,571			1,506

Operating income	$	11,601		$	5,303


	Three Months Ended
	March 31,
	2011			2010
	(Dollars in thousands)
Delta Towing:
Revenue	$	6,868		$	6,289
Operating expenses		5,865			5,272
Depreciation and amortization expense		1,118			1,590
General and administrative expenses		323			368

Operating loss	$	(438	)	$	(941	)

Total Company:
Revenue	$	166,246		$	150,849
Operating expenses		112,246			108,636
Depreciation and amortization		42,911			50,254
General and administrative		13,149			12,303

Operating loss		(2,060	)		(20,344	)
Interest expense		(19,034	)		(21,739	)
Expense of credit agreement fees		(455	)		—
Equity in losses of equity investment		(55	)		—
Other, net		318			(14	)

Loss before income taxes		(21,286	)		(42,097	)
Income tax benefit		7,067			26,141

Net loss	$	(14,219	)	$	(15,956	)

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


	Three Months Ended March 31, 2011
										Average
								Average		Operating
	Operating		Available					Revenue		Expense
	Days		Days		Utilization (1)			per Day (2)		per Day (3)
Domestic Offshore		788		990		79.6	%	$	42,892	$	41,416
International Offshore		582		720		80.8	%		132,507		46,983
Inland		205		270		75.9	%		26,839		26,037
Domestic Liftboats		1,330		3,420		38.9	%		7,993		2,884
International Liftboats		1,395		2,070		67.4	%		23,173		7,081


	Three Months Ended March 31, 2010
										Average
								Average		Operating
	Operating		Available					Revenue		Expense
	Days		Days		Utilization (1)			per Day (2)		per Day (3)
Domestic Offshore		823		990		83.1	%	$	35,191	$	39,547
International Offshore		527		869		60.6	%		139,359		39,953
Inland		240		270		88.9	%		19,796		21,174
Domestic Liftboats		1,727		3,420		50.5	%		6,626		2,723
International Liftboats		1,174		2,160		54.4	%		22,114		6,695


(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.

(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.

For the Three Months Ended March 31, 2011 and 2010

Revenue

Consolidated. Total revenue for the three-month period ended March 31, 2011 (the “Current Quarter”) was $166.2 million compared with $150.8 million for the three-month period ended March 31, 2010 (the “Comparable Quarter”), an increase of $15.4 million, or 10%. This increase is further described below.

Domestic Offshore. Revenue for our Domestic Offshore segment was $33.8 million for the Current Quarter compared with $29.0 million for the Comparable Quarter, an increase of $4.8 million, or 17%. This increase resulted primarily from an increase in average dayrates, which contributed to an approximate $6 million increase in revenue. Partially offsetting this increase is a decline in operating days to 788 days during the Current Quarter from 823 days during the Comparable Quarter which contributed to an approximate $2 million decrease during the Current Quarter as compared to the Comparable Quarter.

International Offshore. Revenue for our International Offshore segment was $77.1 million for the Current Quarter compared with $73.4 million for the Comparable Quarter, an increase of $3.7 million, or 5% primarily related to Hercules 185 operating under a new contract in the Current Quarter compared to not meeting revenue recognition criteria in the Comparable Quarter.

Inland. Revenue for our Inland segment was $5.5 million for the Current Quarter compared with $4.8 million for the Comparable Quarter, an increase of $0.8 million, or 16%. This increase was driven by a 36% increase in average dayrates which contributed to an approximate $2 million increase to revenue in the Current Quarter as compared to the Comparable Quarter. Partially offsetting this increase, operating days decreased to 205 in the Current Quarter as Compared to 240 in the Comparable Quarter which contributed to an approximate $1 million decrease in revenue.

Domestic Liftboats. Revenue from our Domestic Liftboats segment was $10.6 million for the Current Quarter compared with $11.4 million in the Comparable Quarter, a decrease of $0.8 million, or 7%. This decrease resulted primarily from a 23% decline in operating days, which contributed to an approximate $3 million decrease in revenue. This decrease was partially offset by an increase in average revenue per liftboat per day to $7,993 in the Current Quarter compared with $6,626 in the Comparable Quarter, which contributed to an approximate $2 million increase in revenue.

International Liftboats. Revenue for our International Liftboats segment was $32.3 million for the Current Quarter compared with $26.0 million in the Comparable Quarter, an increase of $6.4 million, or 25%. This increase resulted primarily from an increase in operating days during the Current Quarter to 1,395 days from 1,174 days in the Comparable Quarter, which contributed to an approximate $5 million increase in revenue.

Delta Towing. Revenue for our Delta Towing segment was $6.9 million for the Current Quarter compared with $6.3 million in the Comparable Quarter, an increase of $0.6 million, or 9%. This increase resulted primarily from an increase in operating days during the Current Quarter as compared to the Comparable Quarter, which contributed an approximate $2 million increase. The increase was partially offset by a decrease in average vessel dayrates during the Current Quarter as compared to the Comparable Quarter, which contributed to an approximate $1 million decrease.

Operating Expenses

Consolidated. Total operating expenses for the Current Quarter were $112.2 million compared with $108.6 million in the Comparable Quarter, an increase of $3.6 million, or 3%. This increase is further described below.

Domestic Offshore. Operating expenses for our Domestic Offshore segment were $41.0 million in the Current Quarter compared with $39.2 million in the Comparable Quarter, an increase of $1.9 million, or 5%. The increase was driven by an increase in workers’ compensation expenses of $4.6 million offset by a decrease in equipment rentals of $2.0 million in the Current Quarter as compared to the Comparable Quarter. Average operating expenses per rig per day were $41,416 in the Current Quarter compared with $39,547 in the Comparable Quarter.

International Offshore. Operating expenses for our International Offshore segment were $33.8 million in the Current Quarter compared with $34.7 million in the Comparable Quarter, a decrease of $0.9 million, or 3%. Hercules 205 was transferred to the Domestic Offshore segment during the first quarter of 2010 which contributed to a $3.2 million decrease, Platform 3 was preparing for a contract a portion of the Comparable Quarter which contributed to a $1.1 million decrease in the Current Quarter and Hercules 156 was cold stacked in December 2010 which contributed to a $0.6 million decrease. These decreases were partially offset by i) Hercules 185 operating under a new contract in the Current Quarter compared to being on stand-by in the Comparable Quarter which contributed to a $1.3 million increase, ii) costs to prepare Hercules 170 for contract during the Current Quarter contributed to a $1.7 million increase and iii) an increase in workers’ compensation expenses of $1.3 million overall during the Current Quarter. Average operating expenses per rig per day were $46,983 in the Current Quarter compared with $39,953 in the Comparable Quarter.

Inland. Operating expenses for our Inland segment were $7.0 million in the Current Quarter compared with $5.7 million in the Comparable Quarter, an increase of $1.3 million, or 23%. This increase is primarily due to a $1.8 million gain in the Comparable Quarter for the sale of three barges partially offset by a $0.4 million decrease in property taxes in the Current Quarter as compared to the Comparable Quarter due to decreases in assessed values. Average operating expenses per rig per day were $26,037 in the Current Quarter compared with $21,174 in the Comparable Quarter.

Domestic Liftboats. Operating expenses for our Domestic Liftboats segment were $9.9 million in the Current Quarter compared with $9.3 million in the Comparable Quarter, an increase of $0.6 million, or 6%. This increase is primarily due to an increase in labor and burden of $0.4 million and an accrual for an insurance deductible of $0.3 million in the Current Quarter as well as the Comparable Quarter including a favorable adjustment to property taxes of $0.2 million. These increases are partially offset by a $0.3 million reduction in repairs and maintenance expenses in the Current Quarter as compared to the Comparable Quarter. Available days were flat in the Current Quarter as compared to the Comparable Quarter. Average operating expenses per vessel per day were slightly higher at $2,884 in the Current Quarter compared with $2,723 in the Comparable Quarter.

International Liftboats. Operating expenses for our International Liftboats segment were $14.7 million for the Current Quarter compared with $14.5 million in the Comparable Quarter, an increase of $0.2 million, or 1%. Available days decreased slightly to 2,070 in the Current Quarter from 2,160 in the Comparable Quarter.

Delta Towing. Operating expenses for our Delta Towing segment were $5.9 million for the Current Quarter compared with $5.3 million in the Comparable Quarter, an increase of $0.6 million, or 11%. The increase is primarily due to an increase in repairs and maintenance expenses in the Current Quarter.

Depreciation and Amortization

Depreciation and amortization expense in the Current Quarter was $42.9 million compared with $50.3 million in the Comparable Quarter, a decrease of $7.3 million, or 15%. This decrease resulted primarily from reduced depreciation in the Current Quarter of approximately $8 million due to asset sales, fully depreciated assets as well as asset impairments recorded in the fourth quarter of 2010, partially offset by an approximate $1 million increase in depreciation in the Current Quarter due to capital additions.

General and Administrative Expenses

General and administrative expenses in the Current Quarter were $13.1 million compared with $12.3 million in the Comparable Quarter, an increase of $0.8 million, or 7%. The increase is related to i) an approximate $1 million increase in the Current Quarter in labor and burden costs partially due to the impact of a revision of our estimated forfeiture rate for stock-based compensation during the Comparable Quarter of $1.8

million, partially offset by a decrease in the Current Quarter as compared to the Comparable Quarter for bonus and base salary of $0.8 million, ii) an approximate $0.2 million increase in software and licensing fees in the Current Quarter as compared to the Comparable Quarter and iii) an approximate $3 million increase in legal and professional service fees in the Current Quarter of which approximately $2 million related to the Seahawk asset purchase. These increases are largely offset by a $3.5 million reduction in bad debt expense in the Current Quarter as compared to the Comparable Quarter.

Interest Expense

Interest expense in the Current Quarter was $19.0 million compared with $21.7 million in the Comparable Quarter, a decrease of $2.7 million, or 12%. This decrease was related primarily to the impact of our interest rate collar outstanding in the Comparable Quarter.

Expense of Credit Agreement Fees

During the Current Quarter, we amended our credit agreement (the “Credit Agreement”) In doing so, we recorded the write-off of certain deferred debt issuance costs and expensed certain fees directly related to these activities totaling $0.5 million.

Income Tax Benefit

Our income tax benefit was $7.1 million on a pre-tax loss of $21.3 million, for an effective rate of 33.2%, during the Current Quarter, compared to a benefit of $26.1 million on a pre-tax loss of $42.1 million, for an effective rate of 62.1%, for the Comparable Quarter. The effective tax rate in the Current Quarter decreased as compared to the Comparable Quarter due to mix of earnings (losses) from different jurisdictions as well as the prior year benefit of $6.2 million related to the effective compromise settlement with the Mexican tax authorities on certain tax liabilities.

Non-GAAP Financial Measures

Regulation G, General Rules Regarding Disclosure of Non-GAAP Financial Measures and other SEC regulations define and prescribe the conditions for use of certain Non-Generally Accepted Accounting Principles (“Non-GAAP”) financial measures. We use various Non-GAAP financial measures such as adjusted operating income (loss), adjusted net income (loss), adjusted diluted earnings (loss) per share, EBITDA and Adjusted EBITDA. EBITDA is defined as net income plus interest expense, income taxes, depreciation and amortization. We believe that in addition to GAAP based financial information, Non-GAAP amounts are meaningful disclosures for the following reasons: (i) each are components of the measures used by our board of directors and management team to evaluate and analyze our operating performance and historical trends, (ii) each are components of the measures used by our management team to make day-to-day operating decisions, (iii) the Credit Agreement contains covenants that require us to maintain a total leverage ratio and a consolidated fixed charge coverage ratio, which contain Non-GAAP adjustments as components, (iv) each are components of the measures used by our management to facilitate internal comparisons to competitors’ results and the shallow-water drilling and marine services industry in general, (v) results excluding certain costs and expenses provide useful information for the understanding of the ongoing operations without the impact of significant special items, and (vi) the payment of certain bonuses to members of our management is contingent upon, among other things, the satisfaction by the Company of financial targets, which may contain Non-GAAP measures as components. We acknowledge that there are limitations when using Non-GAAP measures. The measures below are not recognized terms under GAAP and do not purport to be an alternative to net income as a measure of operating performance or to cash flows from operating activities as a measure of liquidity. EBITDA and Adjusted EBITDA are not intended to be a measure of free cash flow for management’s discretionary use, as it does not consider certain cash requirements such as tax payments and debt service requirements. In addition, the EBITDA and Adjusted EBITDA amounts presented in the following table should not be used for covenant compliance purposes as these amounts could differ materially from the amounts ultimately calculated under our Credit Agreement. Because all companies do not use identical calculations, the amounts below may not be comparable to other similarly titled measures of other companies.

The following table presents a reconciliation of the GAAP financial measure to the corresponding adjusted financial measure (in thousands):


	For the Three Months
	Ended March 31,
	2011			2010
Net Loss	$	(14,219	)	$	(15,956	)
Interest expense		19,034			21,739
Income tax benefit		(7,067	)		(26,141	)
Depreciation and amortization		42,911			50,254

EBITDA		40,659			29,896

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 base our 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.

We periodically update the estimates used in the preparation of the financial statements based on our latest assessment of the current and projected business and general economic environment. During recent periods, there has been substantial volatility and a decline in gas prices. This decline may adversely impact the business of our customers, and in turn our business. This could result in changes to estimates used in preparing our financial statements, including the assessment of certain of our assets for impairment.

We believe that our more critical accounting policies include those related to property and equipment, equity investments, derivatives, revenue recognition, percentage-of-completion, income tax, allowance for doubtful accounts, deferred charges, stock-based compensation and cash and cash equivalents. 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, 2010 and Item 1 of Part I of this Quarterly Report on Form 10-Q.

OUTLOOK

Offshore

Demand for our oilfield services is driven by our Exploration and Production (“E&P”) customers’ capital spending, which can experience significant fluctuations depending on current commodity prices and their expectations of future price levels among other factors. Demand in the shallow water U.S. Gulf of Mexico is particularly driven by natural gas prices, while international demand is typically driven by prices for crude oil.

Drilling activity levels in the shallow water U.S. Gulf of Mexico are typically dependent on natural gas prices, and to a lesser extent crude oil prices, as well as our customers’ ability to obtain necessary drilling permits to operate in the region. As of April 27, 2011, the spot price for Henry Hub natural gas was $4.35 per MMbtu, with the twelve month strip, or average of the next twelve months’ futures contracts, at $4.71 per MMbtu. We expect natural gas to continue to account for the majority of hydrocarbon production in the shallow water U.S. Gulf of Mexico and the performance of our Domestic Offshore segment will remain dependent on natural gas prices. Additionally, in the wake of the Macondo well blowout incident, new regulations for offshore drilling were imposed by BOEMRE, which have resulted in our customers experiencing significant delays in obtaining necessary permits to operate in the U.S. Gulf of Mexico. While we believe that the current state of the permit approval process appears to have improved since the advent of these new regulations, it is likely that our customers will continue to experience some degree of delay in obtaining drilling permits throughout 2011.

The supply of marketed jackup rigs in the U.S. Gulf of Mexico has declined significantly since the financial crisis starting in 2008 and again with imposition of new regulations during 2010, as drilling contractors such as ourselves and some of our competitors have elected to cold stack, or no longer actively market, a number of rigs in the region, while other competitors have mobilized rigs out of the U.S. Gulf of Mexico. As a result, the number of actively marketed jackup rigs in the U.S. Gulf of Mexico has declined from 63 rigs in late 2008 to 49 rigs as of April 27, 2011. Of the 49 marketed rigs, we own 18 of these rigs, which includes 7 rigs acquired from Seahawk. Although we are encouraged by the reduction in the marketed supply of jackup rigs in the region, which has helped to partially offset the reduction in demand for drilling rigs, we remain cautious about the outlook for improved demand and dayrates in Domestic Offshore given the permit delays and market expectations for a prolonged period of relatively low natural gas prices. Any new regulatory or legislative changes that would affect shallow water drilling activity in the U.S. Gulf of Mexico could have a material impact on Domestic Offshore’s financial results. Based on the current improving backdrop of drilling activity in the U.S. Gulf of Mexico, as well as robust onshore drilling activity in the U.S., there has been a tightening of skilled labor across the oilfield service industry and a commensurate rise in general labor costs. These factors, coupled with our reduction of wages during the financial crisis, have begun to put wage pressures on our Domestic Offshore segment and labor costs will increase as a result. Further, maintaining a skilled workforce may become harder, particularly if drilling activity in the U.S. and globally continues to rise and compete for the pool of experienced offshore labor.

Demand for our rigs in our International Offshore segment is primarily dependent on crude oil prices. Strong crude oil prices during 2010 and market expectations of continued strength through 2011, as well as what appears to be an increase in the number of international tenders for drilling rigs, leads us to believe that international capital spending and demand for drilling rigs overseas will increase in 2011. Our expectation for greater international rig demand is tempered by the current number of idle jackup rigs and the anticipated growth in supply. As of April 27, 2011, there were 356 jackup rigs marketed in international regions, of which 46 rigs were uncontracted. Further, there were 64 new jackup rigs either under construction or on order (excludes 10 rigs that have been indefinitely suspended) for delivery through 2014, of which 48 were without contracts. All of the jackup rigs under construction have higher specifications than the rigs in our existing fleet. We expect that increased market demand will be sufficient to absorb the increased supply of drilling rigs with higher specifications. We have entered into agreements with Discovery Offshore to manage the construction, marketing and operations of two ultra high specification harsh environment jackup drilling rigs scheduled to be delivered in the second quarter and fourth quarter of 2013, respectively.

Five of our international rigs will complete three year contracts during 2011 and current market rates for comparable rigs in the various international regions where we operate are substantially below our existing contracted rates. There is no guarantee we will be able to secure new contracts for these rigs. If we are successful in securing new contracts, we expect the new dayrates will be substantially below current contract rates. Further, as our international customers typically have longer term investment programs, and tend to enter into multi-year contracts for our services, new international contracts could expose our International Offshore segment to much lower rates over the next several years.

Activity for inland barge drilling in the U.S. generally follows similar drivers as drilling in the U.S. Gulf of Mexico Shelf, with activity following operators’ expectations of prices for natural gas and crude oil. The predominance of smaller independent operators active in inland waters adds to the volatility of this region. Inland barge drilling activity has slowed dramatically since 2008, as a number of key operators have curtailed or ceased activity in the inland market for various reasons, including lack of funding, lack of drilling success and reallocation of capital to other onshore basins. Inland activity levels appear to have stabilized in 2010, but remain depressed relative to historical levels. As of April 25, 2011, there were 24 marketed barge rigs, of which 20 were contracted. We expect industry activity levels in 2011 to remain relatively flat with such levels, barring a significant increase in natural gas prices and/or property exchanges to new operators that may spur drilling activity in this region.

Liftboats

Demand for liftboats is typically a function of our customers’ demand for platform inspection and maintenance, well maintenance, offshore construction, well plugging and abandonment, and other related activities. Although activity levels for liftboats are not as closely correlated to commodity prices as our drilling segments, commodity prices are still a key driver of liftboat demand. In addition, liftboat demand in the U.S. Gulf of Mexico typically experiences seasonal fluctuations, due in large part to the operating limitations of liftboats in rough waters, which tend to occur during the winter months.

Domestic Liftboat segment demand was positively impacted by clean up efforts related to the Macondo well blowout incident throughout mid-2010, with a peak of 12 out of our 38 marketed liftboats dedicated to this activity. Such demand effectively concluded by the end of the third quarter of 2010, and we do not expect this source of revenue to recur. On September 15, 2010, the Department of Interior issued the Notice to Lessees Number 2010-G05, which provides federal guidelines for the plugging and abandonment of wells and decommissioning of offshore platforms in the U.S. Gulf of Mexico. These new federal regulations require E&P operators to perform such services, and we expect liftboat demand in support of these services will increase over an extended period of time, in particular demand for the larger class liftboats. However, the magnitude of demand growth for plugging, abandonment and decommissioning services, and the related increase in demand for liftboats, is uncertain. Further, barring an

exogenous industry event, it is also uncertain whether such an increase in liftboat demand stemming from these new regulations will be adequate to fully offset the absence of clean up related business that we benefited from in 2010.

Our International Liftboat segment is driven by our customers’ demand for production, platform maintenance and support activities in West Africa and the Middle East. While international rates for liftboats typically exceed those in the U.S., operating costs are also higher, and we expect this dynamic to continue through the foreseeable future. In recent years, international liftboat utilization has lagged the U.S. We believe that this is due in part to competitive pressures and curtailment of capital spending by various customers in wake of the 2008 financial crisis. During late 2010 and continuing into 2011, we have seen some signs of improvement in liftboat demand from various international customers. Over the long term, we believe that international liftboat demand will benefit from: (i) the aging offshore infrastructure and maturing offshore basins; (ii) desire by our international customers to economically produce from these mature basins and service their infrastructure; and (iii) the cost advantages of liftboats to perform these services relative to alternatives. Tempering this demand outlook is our expectation of increased competition in our international markets.

LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses of Cash

Sources and uses of cash for the three-month period ended March 31, 2011 are as follows (in millions):


Net Cash Provided by Operating Activities	$	49.1
Net Cash Provided by (Used in) Investing Activities:
Additions of Property and Equipment		(10.3	)
Deferred Drydocking Expenditures		(4.1	)
Cash Paid for Equity Investment		(10.0	)
Proceeds from Sale of Assets, Net		3.4

Total		(21.0	)
Net Cash Provided by (Used in) Financing Activities:
Payment of Debt Issuance Costs		(2.1	)
Excess Tax Benefits from Stock-Based Arrangements		0.1
Other		0.2

Total		(1.8	)

Net Increase in Cash and Cash Equivalents	$	26.3

Asset Purchase

Equity Investment and Derivative Asset

Our total equity investment in Discovery Offshore was $18.3 million, or 13% as of March 31, 2011, which includes the initial cash investment of $10.0 million, additional equity interest of $1.0 million related to 500,000 Discovery Offshore shares awarded to us for reimbursement of costs incurred and efforts expended in forming Discovery Offshore, additional purchases of Discovery Offshore shares on the open market totalling $7.3 million or 3,203,700 shares (amount was not cash settled until April 2011) as well as our proportionate share of Discovery Offshore’s losses. This investment is being accounted for using the equity method of accounting as we have the ability to exert significant influence, but not control, over operating and financial policies. We have warrants issued from Discovery Offshore that are being accounted for as a derivative asset equal to $5.2 million as of March 31, 2011 that, if exercised, would be recorded as an increase our equity investment in Discovery Offshore. The initial fair value of the warrants of $5.0 million as well as the $1.0 million related to the 500,000 additional shares have been recorded as deferred revenue to be amortized over 30 years, the useful life of the two Discovery Offshore rigs, of which thirty-one thousand dollars was recognized as of March 31, 2011. Subsequent changes in the fair value of the warrants is recognized to other income (expense). We recognized $0.2 million to other income related to the change in the fair value of the warrants during the three months ended March 31, 2011.

Percentage-of-Completion

We are using the percentage-of-completion method of accounting for our revenue and related costs associated with our construction management agreements with Discovery Offshore, combining the construction management agreements, based on a cost-

to-cost method. Any revisions in revenue, cost or the progress towards completion, will be treated as a change in accounting estimate and will be accounted for using the cumulative catch-up method. As of March 31, 2011, $14.0 million has been recorded as a deferred revenue liability; however, no deferred cost asset has been recorded. There was no revenue or cost recognized during the three months ended March, 31, 2011 under the percentage-of-completion method of accounting as there were no activities associated with the performance of contract obligations during the current quarter.

Sources of Liquidity and Financing Arrangements

Our liquidity is comprised of cash on hand, cash from operations and availability under our revolving credit facility. We also maintain a shelf registration statement covering the future issuance from time to time of various types of securities, including debt and equity securities. If we issue any debt securities off the shelf or otherwise incur debt, we would generally be required to allocate the proceeds of such debt to repay or refinance existing debt. We currently believe we will have adequate liquidity to meet the minimum liquidity requirement under our Credit Agreement that governs our $475.2 million term loan and $140.0 million revolving credit facility and to fund our operations. However, to the extent we do not generate sufficient cash from operations we may need to raise additional funds through debt, equity offerings or the sale of assets. Furthermore, we may need to raise additional funds through debt or equity offerings or asset sales to meet certain covenants under the Credit Agreement, to refinance existing debt or for general corporate purposes. In July 2012, our $140.0 million revolving credit facility matures. To the extent we are unsuccessful in extending the maturity or entering into a new revolving credit facility, our liquidity would be negatively impacted. In June 2013, we may be required to settle our 3.375% Convertible Senior Notes. As of March 31, 2011, the notional amount of these notes outstanding was $95.9 million. Additionally, our term loan matures in July 2013 and currently requires a balloon payment of $464.1 million at maturity. We intend to meet these obligations through one or more of the following: cash flow from operations, asset sales, debt refinancing and future debt or equity offerings.

Our Credit Agreement imposes various affirmative and negative covenants, including requirements to meet certain financial ratios and tests, which we currently meet. Our failure to comply with such covenants would result in an event of default under the Credit Agreement. Additionally, in order to maintain compliance with our financial covenants, borrowings under our revolving credit facility may be limited to an amount less than the full amount of remaining availability after outstanding letters of credit. An event of default could prevent us from borrowing under the revolving credit facility, which would in turn have a material adverse effect on our available liquidity. Furthermore, an event of default could result in us having to immediately repay all amounts outstanding under the term loan facility, the revolving credit facility, our 10.5% Senior Secured Notes and our 3.375% Convertible Senior Notes and in the foreclosure of liens on our assets.

Cash Requirements and Contractual Obligations

Debt

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

At December 31, 2010, we had outstanding a $650.2 million credit facility consisting of a $475.2 million term loan and a $175.0 million revolving credit facility which is governed by the credit agreement (“Credit Agreement”), as amended.

The availability under the $175.0 million revolving credit facility must be used for working capital, capital expenditures and other general corporate purposes and cannot be used to prepay the term loan. We are required to maintain a minimum level of liquidity, measured as the amount of unrestricted cash and cash equivalents on hand and availability under the revolving credit facility, of (i) $75.0 million during calendar year 2011 and (ii) $50.0 million thereafter. As of March 31, 2011, as calculated pursuant to our Credit Agreement, our total liquidity was $290.8 million.

In addition, we are required to maintain a minimum fixed charge coverage ratio according to the following schedule:


			Fixed Charge
Period			Coverage Ratio
July 1, 2009	—	December 31, 2011	1.00 to 1.00
January 1, 2012	—	March 31, 2012	1.05 to 1.00
April 1, 2012	—	June 30, 2012	1.10 to 1.00
July 1, 2012 and thereafter			1.15 to 1.00

•

In addition, we are required to make mandatory prepayments of debt outstanding under the Credit Agreement with 50% of excess cash flow as defined in the Credit Agreement for the fiscal years ending December 31, 2011 and 2012, and with proceeds from:

	-		unsecured debt issuances, with the exception of refinancing;

	-		secured debt issuances;

	-		casualty events not used to repair damaged property;

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

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

March 2011 Credit Amendment

On March 3, 2011, we amended our Credit Agreement (“2011 Credit Amendment”) to, among other things:

Allow for the use of cash to purchase assets from Seahawk, to the extent set forth in our previously disclosed Asset Purchase Agreement with Seahawk;

	-		Exempt the pro forma treatment of historical results from the Seahawk assets with respect to the calculation of the financial covenants in the Credit Agreement;

	-		Increase our investment basket to $50 million from $25 million; and

	-		Revise the covenant threshold levels of the Total Leverage Ratio, as defined in the Credit Agreement, to the following schedule:


		Amended Total
Test Date	Previous Total Leverage Ratio	Leverage Ratio

March 31, 2011	7.00 to 1.00	No Change
June 30, 2011	6.75 to 1.00	No Change
September 30, 2011	6.00 to 1.00	7.50 to 1.00
December 31, 2011	5.50 to 1.00	7.75 to 1.00
March 31, 2012	5.25 to 1.00	7.50 to 1.00
June 30, 2012	5.00 to 1.00	7.25 to 1.00
September 30, 2012	4.75 to 1.00	6.75 to 1.00
December 31, 2012	4.50 to 1.00	6.25 to 1.00
March 31, 2013	4.25 to 1.00	6.00 to 1.00
June 30, 2013	4.00 to 1.00	5.75 to 1.00

At March 31, 2011, our total leverage ratio was 4.69 to 1.00.

We also agreed to pay consenting lenders an upfront fee of 0.25% on their commitment, or approximately $1.4 million. Including agent bank fees and expenses our total cost was approximately $2.0 million. We recognized a pretax charge of $0.5 million, $0.3 million net of tax, related to the write off of certain unamortized issuance costs and the expense of certain fees in connection with the 2011 Credit Amendment.

As of March 31, 2011, the credit facility consisted of a $475.2 million term loan which matures on July 11, 2013 and a $140.0 million revolving credit facility that matures on July 11, 2012, under which the remaining availability was $127.8 million as $12.2 million in standby letters of credit had been issued under it. Other than the required prepayments as outlined previously, the principal amount of the term loan amortizes in equal quarterly installments of approximately $1.2 million, with the balance due on July 11, 2013. Interest payments on both the revolving and term loan facility are due at least on a quarterly basis and in certain instances, more frequently. As of March 31, 2011, $475.2 million was outstanding on

the term loan facility and the interest rate was 7.5%. The annualized effective interest rate was 6.89% for the three months ended March 31, 2011 after giving consideration to revolver fees.

In July 2007, we entered into a zero cost LIBOR collar on $300.0 million of term loan principal with a final settlement date of October 1, 2010 (which was settled on October 1, 2010 per the agreement with a cash payment of $3.4 million) with a ceiling of 5.75% and a floor of 4.99%. The counterparty paid us in any quarter that actual LIBOR reset above 5.75% and we paid the counterparty in any quarter that actual LIBOR resets below 4.99%. The terms and settlement dates of the collar matched those of the term loan through July 27, 2009, the date of the 2009 Credit Amendment.

As a result of the inclusion of a LIBOR floor in the Credit Agreement, we determined, as of July 27, 2009 and on an ongoing basis, that the interest rate collar (which settled on October 1, 2010) would not be highly effective in achieving offsetting changes in cash flows attributable to the hedged interest rate risk during the period that the hedge was designated. As such, we discontinued cash flow hedge accounting for the interest rate collar as of July 27, 2009. Because cash flow hedge accounting was not applied to this instrument, changes in fair value related to the interest rate collar subsequent to July 27, 2009 were recorded in earnings. As a result of discontinuing the cash flow hedging relationship, we recognized a decrease in fair value of $0.4 million related to the hedge ineffectiveness of our interest rate collar as Interest Expense in our Consolidated Statements of Operations for the three months ended March 31, 2010. We had a net unrealized gain on hedge transactions of $2.1 million, net of tax of $1.1 million for the three months ended March 31, 2010. Overall, our interest expense was increased by $3.6 million during the three months ended March 31, 2010, as a result of our interest rate derivative instruments. 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, 2011 as the interest rate collar’s final settlement occurred on October 1, 2010.

On October 20, 2009, we completed an offering of $300.0 million of senior secured notes at a coupon rate of 10.5% (“10.5% Senior Secured Notes”) with a maturity in October 2017. The interest on the 10.5% Senior Secured Notes is payable in cash semi-annually in arrears on April 15 and October 15 of each year, to holders of record at the close of business on April 1 or October 1. Interest on the notes will be computed on the basis of a 360-day year of twelve 30-day months. The notes were sold at 97.383% of their face amount to yield 11.0% and were recorded at their discounted amount, with the discount to be amortized over the life of the notes. As of March 31, 2011, $300.0 million notional amount of the 10.5% Senior Secured Notes was outstanding.

The notes are guaranteed by all of our existing and future restricted subsidiaries that incur or guarantee indebtedness under a credit facility, including our existing credit facility. The notes are secured by liens on all collateral that secures our obligations under our secured credit facility, subject to limited exceptions. The liens securing the notes share on an equal and ratable first priority basis with liens securing our credit facility. Under the intercreditor agreement, the collateral agent for the lenders under our secured credit facility is generally entitled to sole control of all decisions and actions.

All the liens securing the notes may be released if our secured indebtedness, other than these notes, does not exceed the lesser of $375.0 million and 15.0% of our consolidated tangible assets. We refer to such a release as a “collateral suspension.” If a collateral suspension is in effect, the notes and the guarantees will be unsecured, and will effectively rank junior to our secured indebtedness to the extent of the value of the collateral securing such indebtedness. If, after any such release of liens on collateral, the aggregate principal amount of our secured indebtedness, other than these notes, exceeds the greater of $375.0 million and 15.0% of our consolidated tangible assets, as defined in the indenture, then the collateral obligations of the Company and guarantors will be reinstated and must be complied with within 30 days of such event.

The indenture governing the notes contains covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to:

	•		incur additional indebtedness or issue certain preferred stock;

	•		pay dividends or make other distributions;

	•		make other restricted payments or investments;

	•		sell assets;

	•		create liens;

	•		enter into agreements that restrict dividends and other payments by restricted subsidiaries;

	•		engage in transactions with our affiliates; and

	•		consolidate, merge or transfer all or substantially all of our assets.

The indenture governing the notes also contains a provision under which an event of default by us or by any restricted subsidiary on any other indebtedness exceeding $25.0 million would be considered an event of default under the indenture if such default: a) is caused by failure to pay the principal at final maturity, or b) results in the acceleration of such indebtedness prior to maturity.

On June 3, 2008, we completed an offering of $250.0 million convertible senior notes at a coupon rate of 3.375% (“3.375% Convertible Senior Notes”) with a maturity in June 2038. As of March 31, 2011, $95.9 million notional amount of the $250.0 million 3.375% Convertible Senior Notes was outstanding. The net carrying amount of the 3.375% Convertible Senior Notes was $87.4 million at March 31, 2011.

The interest on the 3.375% Convertible Senior Notes is payable in cash semi-annually in arrears, on June 1 and December 1 of each year until June 1, 2013, after which the principal will accrete at an annual yield to maturity of 3.375% per year. We will also pay contingent interest during any six-month interest period commencing June 1, 2013, for which the trading price of these notes for a specified period of time equals or exceeds 120% of their accreted principal amount. The notes will be convertible under certain circumstances into shares of our common stock (“Common Stock”) at an initial conversion rate of 19.9695 shares of Common Stock per $1,000 principal amount of notes, which is equal to an initial conversion price of approximately $50.08 per share. Upon conversion of a note, a holder will receive, at our election, shares of Common Stock, cash or a combination of cash and shares of Common Stock. At March 31, 2011, the number of conversion shares potentially issuable in relation to our 3.375% Convertible Senior Notes was 1.9 million. We may redeem the notes at our option beginning June 6, 2013, and holders of the notes will have the right to require us to repurchase the notes on June 1, 2013 and certain dates thereafter or on the occurrence of a fundamental change.

The indenture governing the 3.375% Convertible Senior Notes contains a provision under which an event of default by us or by any subsidiary on any other indebtedness exceeding $25.0 million would be considered an event of default under the indenture if such default: a) is caused by failure to pay the principal at final maturity, or b) results in the acceleration of such indebtedness prior to maturity.

We determined that upon maturity or redemption, we have the intent and ability to settle the principal amount of our 3.375% Convertible Senior Notes in cash, and any additional conversion consideration spread (the excess of conversion value over face value) in shares of our Common Stock.

The fair value of our 3.375% Convertible Senior Notes, 10.5% Senior Secured Notes and term loan facility is estimated based on quoted prices in active markets. The fair value of our 7.375% Senior Notes is estimated based on discounted cash flows using inputs from quoted prices in active markets for similar debt instruments. The following table provides the carrying value and fair value of our long-term debt instruments:


	March 31, 2011				Decenber 31, 2010
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(in millions)
Term Loan Facility, due July 2013	$	475.2	$	469.1	$	475.2	$	443.7
10.5% Senior Secured Notes, due October 2017		293.1		307.7		292.9		245.1
3.375% Convertible Senior Notes, due June 2038		87.4		90.9		86.5		69.1
7.375% Senior Notes, due April 2018		3.5		3.0		3.5		2.2

As of March 31, 2011, our primary marine package provides for hull and machinery coverage for substantially all of our rigs and liftboats up to a scheduled value of each asset. The total maximum amount of coverage for these assets is $2.1 billion. The marine package includes protection and indemnity and maritime employer’s liability coverage for marine crew personal injury and death and certain operational liabilities, with primary coverage (or self-insured retention for maritime employer’s liability coverage) of $5.0 million per occurrence with excess liability coverage up to $200.0 million. The marine package policy also includes coverage for personal injury and death of third-parties with primary and excess coverage of $25 million per occurrence with additional excess liability coverage up to $200 million, subject to a $250,000 per-occurrence deductible. The marine package also provides coverage for cargo and charterer’s legal liability. The marine package includes limitations for coverage for losses caused in U.S. Gulf of Mexico named windstorms, including an annual aggregate limit of liability of $100.0 million for property damage and removal of wreck liability coverage. We also procured an additional $75.0 million excess policy for removal of wreck and certain third-party liabilities incurred in U.S. Gulf of Mexico named windstorms. Deductibles for events that are not caused by a U.S. Gulf of Mexico named windstorm are 12.5% of the insured drilling rig values per occurrence, subject to a minimum of $1.0 million, and $1.0 million per occurrence for liftboats. The deductible for drilling rigs and liftboats in a U.S. Gulf of Mexico named windstorm event is $25.0 million. Vessel pollution is covered under a Water Quality Insurance Syndicate policy (“WQIS Policy”) providing limits as required by applicable law, including the Oil Pollution Act of 1990. The WQIS Policy covers pollution emanating from our vessels and drilling rigs, with primary limits of $5 million (inclusive of a $3.0 million per-occurrence deductible) and excess liability coverage up to $200 million.

Control-of-well events generally include an unintended flow from the well that cannot be contained by equipment on site (e.g., a blow-out preventer), by increasing the weight of the drilling fluid or that does not naturally close itself off through what is typically described as bridging over. We carry a contractor’s extra expense policy with $50 million primary covering liability for well control costs, expenses incurred to redrill wild or lost wells and pollution, with excess liability coverage up to $200 million for pollution liability that is covered in the primary policy. The policies are subject to exclusions, limitations, deductibles, self-insured retention and other conditions. In addition to the marine package, we have separate policies providing coverage for onshore foreign and domestic general liability, employer’s liability, auto liability and non-owned aircraft liability, with customary deductibles and coverage as well as a separate underlying marine package for our Delta Towing business.

In 2010, 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 $25.9 million was financed through these arrangements, of which $0.7 million and $6.0 million was outstanding at March 31, 2011 and December 31, 2010, respectively. The interest rate on the $24.1 million note was 3.79% and it was fully paid as of March 31, 2011. The interest rate on the $1.8 million note is 3.54% and the note is scheduled to mature in July 2011.

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

In April 2011, we completed our annual renewal and revised our insurance coverage to include the assets from the Seahawk asset purchase (See Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operation — Recent Developments).

Capital Expenditures

We expect to spend approximately $55 million on capital expenditures and drydocking during the remainder of 2011, which includes our preliminary estimate of expenditures related to the recently acquired Seahawk jackup rigs. Planned capital expenditures are generally maintenance and regulatory in nature and do not include refurbishment or upgrades to our rigs, liftboats, and other marine vessels. Should we elect to reactivate cold stacked rigs or upgrade and refurbish selected rigs or liftboats, our capital expenditures may increase. Reactivations, upgrades and refurbishments are subject to our discretion and will depend on our view of market conditions and our cash flows.

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

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

From time to time, we may review possible acquisitions of rigs, liftboats or businesses, joint ventures, mergers or other business combinations, and we may have outstanding from time to time bids to acquire certain assets from other companies. We may not, however, be successful in our acquisition efforts. We are generally restricted by our Credit Agreement from making acquisitions for cash consideration, except to the extent the acquisition is funded by an issuance of our stock or cash proceeds from the issuance of stock (with the exception of the Seahawk asset purchase), or unless we are in compliance with more restrictive financial covenants than what we are normally required to meet in each respective period as defined in the 2011 Credit Amendment. If we acquire additional assets, we would expect that the ongoing capital expenditures for our company as a whole would increase in order to maintain our equipment in a competitive condition.

Our ability to fund capital expenditures would be adversely affected if conditions deteriorate in our business.

Off-Balance Sheet Arrangements

Guarantees

Our obligations under the credit facility and 10.5% Senior Secured Notes are secured by liens on a majority of our vessels and substantially all of our other personal property. Substantially all of our domestic subsidiaries, and several of our international subsidiaries, guarantee the obligations under the credit facility and 10.5% Senior Secured Notes and have granted similar liens on the majority of their vessels and substantially all of their other personal property.

Bank Guarantees, Letters of Credit, and Surety Bonds

We execute bank guarantees, 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, 2011, we had $24.4 million of bank guarantees, letters of credit and surety bonds

outstanding, consisting of $1.0 million in unsecured bank guarantees, a $0.1 million unsecured outstanding letter of credit, $12.2 million in standby letters of credit outstanding under our revolver and $11.2 million outstanding in surety bonds that guarantee our performance as it relates to our drilling contracts and other obligations in Mexico and the U.S. If the beneficiaries called the bank guarantees, letters of credit and surety bonds, the called amount would become an on-balance sheet liability, and we would be required to settle the liability with cash on hand or through borrowings under our available line of credit. As of March 31, 2011, we have restricted cash of $11.1 million to support surety bonds related to our Mexico and U.S. operations.

Contractual Obligations

Our contractual obligations and commitments principally include obligations associated with our outstanding indebtedness, certain income tax liabilities, surety bonds, letters of credit, future minimum operating lease obligations, purchase commitments and management compensation obligations. During the first three months of 2011, there were no material changes outside the ordinary course of business in the specified contractual obligations.

For additional information about our contractual obligations as of December 31, 2010, 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, 2010.

Accounting Pronouncements

See Note 14 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 levels of indebtedness, covenant compliance and access to capital under current market conditions;

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

	•		our ability to renew or extend our long-term international contracts, or enter into new contracts, at current dayrates when such contracts expire;

	•		demand for our rigs and our liftboats;

	•		activity levels of our customers and their expectations of future energy prices and ability to obtain drilling permits;

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

	•		levels of reserves for accounts receivable;

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

	•		expected completion times for our refurbishment and upgrade projects;

	•		our plans to increase international operations;

	•		expected useful lives of our rigs and liftboats;

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

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

	•		liabilities and restrictions under coastwise and other laws of the United States and regulations protecting the environment;

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

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

We have based these statements on our assumptions and analyses in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. Forward-looking statements by their nature involve substantial risks and uncertainties that could significantly affect expected results, and actual future results could differ materially from those described in such statements. Although it is not possible to identify all factors, we continue to face many risks and uncertainties. Among the factors that could cause actual future results to differ materially are the risks and uncertainties described under “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2010, and Item 1A of Part II of this quarterly report and the following:

	•		the ability of our customers in the U.S. Gulf of Mexico to obtain drilling permits;

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

	•		levels of oil and gas exploration and production spending;

	•		demand for and supply of offshore drilling 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, North Africa, West Africa and other oil and natural gas producing regions or acts of terrorism or piracy;

	•		the impact of governmental laws and regulations, including new laws and regulations in the U.S. Gulf of Mexico arising out of the Macondo well blowout incident;

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

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

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

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

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

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

	•		the effect of litigation, investigations and contingencies; and

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

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Interest Rate Exposure

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

As of March 31, 2011, the long-term borrowings that were outstanding subject to fixed interest rate risk consisted of the 7.375% Senior Notes due April 2018, the 3.375% Convertible Senior Notes due June 2038 and the 10.5% Senior Secured Notes due October 2017 with a carrying amount of $3.5 million, $87.4 million and $293.1 million, respectively.

As of March 31, 2011, the interest rate for the $475.2 million outstanding under the term loan was 7.5%. If the interest rate averaged 1% more for 2011 than the rates as of March 31, 2011, annual interest expense would increase by approximately $4.8 million. This sensitivity analysis assumes there are no changes in our financial structure and excludes the impact of our interest rate derivatives, if any.


	March 31, 2011				December 31, 2010
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(in millions)
Term Loan Facility, due July 2013	$	475.2	$	469.1	$	475.2	$	443.7
10.5% Senior Secured Notes, due October 2017		293.1		307.7		292.9		245.1
3.375% Convertible Senior Notes, due June 2038		87.4		90.9		86.5		69.1
7.375% Senior Notes, due April 2018		3.5		3.0		3.5		2.2

Fair Value of Warrants and Derivative Asset

At March 31, 2011, the fair value of derivative instruments was $5.2 million. We estimate the fair value of these instruments using a Monte Carlo simulation which takes into account a variety of factors including the strike price, the target price, the stock value, the expected volatility, the risk-free interest rate, the expected life of warrants, and the number of warrants. We are required to revalue this asset each quarter. We believe that the assumption that has the greatest impact on the determination of fair value is the closing price of Discovery Offshore’s stock. The following table illustrates the potential effect on the fair value of the derivative asset from changes in the assumptions made:


	Increase/(Decrease)
	(In thousands)
25% increase in stock price	$	2,385
50% increase in stock price		4,960
10% increase in assumed volatility		860
25% decrease in stock price		(2,130	)
50% decrease in stock price		(3,860	)
10% decrease in assumed volatility		(970	)

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our chief executive officer and our chief financial officer, evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Our chief executive officer and chief financial officer evaluated whether our disclosure controls and procedures as of the end of the period covered by this report were designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is (1) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and

(2) accumulated and communicated to our management, including our chief executive officer and our chief financial officer, as appropriate to allow timely decisions regarding required disclosure. Based on their evaluation, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures were effective to achieve the foregoing objectives as of the end of the period covered by this report.

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 13 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.

Shareholder Derivative Suit

ITEM 1A. RISK FACTORS

Except for the additional and updated disclosures set forth below, for additional information about our risk factors, see Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2010.

Any violation of the Foreign Corrupt Practices Act or similar laws and regulations could result in significant expenses, divert management attention, and otherwise have a negative impact on us.

We are subject to the Foreign Corrupt Practices Act (the “FCPA”), which generally prohibits U.S. companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or retaining business, and the anti-bribery laws of other jurisdictions. On April 4, 2011, we received a subpoena from the SEC requesting that we produce documents relating to our compliance with the FCPA. We have also been advised by the Department of Justice that it is conducting a similar investigation. Under the direction of the audit committee, we are conducting an internal investigation regarding these matters. Any determination that we have violated the FCPA or laws of any other jurisdiction could have a material adverse effect on our financial condition.

Our international operations may subject us to political and regulatory risks and uncertainties.

In connection with our international contracts, the transportation of rigs, services and technology across international borders subjects us to extensive trade laws and regulations. Our import and export activities are governed by unique customs laws and regulations in each of the countries where we operate. In each jurisdiction, laws and regulations concerning importation, recordkeeping and reporting, import and export control and financial or economic sanctions are complex and constantly changing. Our business and financial condition may be materially affected by enactment, amendment, enforcement or changing interpretations of these laws and regulations. Rigs and other shipments can be delayed and denied import or export for a variety of reasons, some of which are outside our control and some of which may result in failure to comply with existing laws and regulations and contractual requirements. Shipping delays or denials could cause operational downtime or increased costs, duties, taxes and fees. Any failure to comply with applicable legal and regulatory obligations also could result in criminal and civil penalties and sanctions, such as fines, imprisonment, debarment from government contracts, seizure of goods and loss of import and export privileges.

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

Shares Purchased

of Shares That

Total Number

as Part of a

May Yet Be

of Shares

Average Price

Publicly

Purchased Under

Period

Purchased (1)

Paid per Share

Announced Plan (2)

Plan (2)

January 1-31, 2011

—

N/A

February 1-28, 2011

79,368

4.24

N/A

March 1-31, 2011

212

5.79

N/A

Total

79,580

4.25

N/A


(1)		Represents the surrender of shares of our 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.


	Page No.
PART I. FINANCIAL INFORMATION

Item 1. Financial Statements:
Consolidated Balance Sheets as of March 31, 2011 and December 31, 2010		3
Consolidated Statements of Operations for the three months ended March 31, 2011 and 2010		4
Consolidated Statements of Cash Flows for the three months ended March 31, 2011 and 2010		5
Consolidated Statements of Comprehensive Loss for the three months ended March 31, 2011 and 2010		6
Notes to Unaudited Consolidated Financial Statements		7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		27
Item 3. Quantitative and Qualitative Disclosures about Market Risk		49
Item 4. Controls and Procedures		49

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		50
Item 1A. Risk Factors		50
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		50
Item 6. Exhibits		51

Signatures		52
EX-10.1
EX-31.1
EX-31.2
EX-32.1


10.1*		Form of Restricted Stock Agreement (Performance Grant).

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.


	HERCULES OFFSHORE, INC.
	By:	/s/ John T. Rynd
		John T. Rynd
		Chief Executive Officer and President (Principal Executive Officer)


	By:	/s/ Stephen M. Butz
		Stephen M. Butz
		Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)


	By:	/s/ Troy L. Carson
		Troy L. Carson
		Chief Accounting Officer (Principal Accounting Officer)