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Hercules Offshore 10-Q 2011

Documents found in this filing:

  1. 10-Q
  2. Ex-31.1
  3. Ex-31.2
  4. Ex-32.1
  5. Ex-32.1
e10vq
Table of Contents

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q
 
     
þ   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2011
or
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number: 0-51582
 
HERCULES OFFSHORE, INC.
(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 þ No o
     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See 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 October 24, 2011
137,893,030
 
 

 


 

HERCULES OFFSHORE, INC.
INDEX
         
    Page No.  
       
 
       
    3  
    4  
    5  
    6  
    7  
    28  
    51  
    52  
 
       
       
 
       
    52  
    52  
    53  
    54  
 
       
    55  
 EX-31.1
 EX-31.2
 EX-32.1
 EX-101 INSTANCE DOCUMENT
 EX-101 SCHEMA DOCUMENT
 EX-101 CALCULATION LINKBASE DOCUMENT
 EX-101 LABELS LINKBASE DOCUMENT
 EX-101 PRESENTATION LINKBASE DOCUMENT

2


Table of Contents

PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
HERCULES OFFSHORE, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except par value)
                 
    September 30,     December 31,  
    2011     2010  
    (Unaudited)          
ASSETS
               
Current Assets:
               
Cash and Cash Equivalents
  $ 127,274     $ 136,666  
Restricted Cash
    13,604       11,128  
Accounts Receivable, Net of Allowance for Doubtful Accounts of $12,867 and $29,798 as of September 30, 2011 and December 31, 2010, Respectively
    163,780       143,796  
Prepaids
    23,651       17,142  
Current Deferred Tax Asset
    10,572       8,488  
Other
    16,906       11,794  
 
           
 
    355,787       329,014  
Property and Equipment, Net of Accumulated Depreciation of $605,997 and $516,565 as of September 30, 2011 and December 31, 2010, Respectively
    1,631,661       1,634,542  
Equity Investment
    34,910        
Other Assets, Net
    31,667       31,753  
 
           
 
  $ 2,054,025     $ 1,995,309  
 
           
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current Liabilities:
               
Short-term Debt and Current Portion of Long-term Debt
  $ 4,768     $ 4,924  
Insurance Notes Payable
    12,987       5,984  
Accounts Payable
    53,707       52,279  
Accrued Liabilities
    57,973       59,861  
Interest Payable
    18,585       6,974  
Taxes Payable
    6,231        
Other Current Liabilities
    20,942       16,716  
 
           
 
    175,193       146,738  
Long-term Debt, Net of Current Portion
    838,012       853,166  
Other Liabilities
    21,869       6,716  
Deferred Income Taxes
    90,301       135,557  
Commitments and Contingencies
               
Stockholders’ Equity:
               
Common Stock, $0.01 Par Value; 200,000 Shares Authorized; 139,789 and 116,336 Shares Issued, Respectively; 137,892 and 114,784 Shares Outstanding, Respectively
    1,398       1,163  
Capital in Excess of Par Value
    2,056,428       1,924,659  
Treasury Stock, at Cost, 1,897 Shares and 1,552 Shares, Respectively
    (52,178 )     (50,333 )
Retained Deficit
    (1,076,998 )     (1,022,357 )
 
           
 
    928,650       853,132  
 
           
 
  $ 2,054,025     $ 1,995,309  
 
           
The accompanying notes are an integral part of these financial statements.

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
(Unaudited)
                                 
    Three Months Ended September 30,     Nine Months Ended September 30,  
    2011     2010     2011     2010  
            (As Adjusted)             (As Adjusted)  
Revenue
  $ 162,991     $ 157,609     $ 492,570     $ 460,067  
Costs and Expenses:
                               
Operating Expenses
    111,372       102,310       332,081       307,626  
Depreciation and Amortization
    43,895       44,982       128,699       140,382  
General and Administrative
    10,757       14,158       40,403       40,595  
 
                       
 
    166,024       161,450       501,183       488,603  
 
                       
Operating Loss
    (3,033 )     (3,841 )     (8,613 )     (28,536 )
Other Income (Expense):
                               
Interest Expense
    (20,389 )     (20,752 )     (59,035 )     (62,437 )
Expense of Credit Agreement Fees
                (455 )      
Equity in Losses of Equity Investment
    (34 )           (225 )      
Other, Net
    (1,561 )     (22 )     (2,583 )     3,144  
 
                       
Loss Before Income Taxes
    (25,017 )     (24,615 )     (70,911 )     (87,829 )
Income Tax Benefit
    7,973       8,478       25,921       38,267  
 
                       
Loss from Continuing Operations
    (17,044 )     (16,137 )     (44,990 )     (49,562 )
Income (Loss) from Discontinued Operations, Net of Taxes
    52       1,076       (9,651 )     (439 )
 
                       
Net Loss
  $ (16,992 )   $ (15,061 )   $ (54,641 )   $ (50,001 )
 
                       
Basic Loss Per Share:
                               
Loss from Continuing Operations
  $ (0.12 )   $ (0.14 )   $ (0.35 )   $ (0.43 )
Income (Loss) from Discontinued Operations
          0.01       (0.08 )     (0.01 )
 
                       
Net Loss
  $ (0.12 )   $ (0.13 )   $ (0.43 )   $ (0.44 )
 
                       
Diluted Loss Per Share:
                               
Loss from Continuing Operations
  $ (0.12 )   $ (0.14 )   $ (0.35 )   $ (0.43 )
Income (Loss) from Discontinued Operations
          0.01       (0.08 )     (0.01 )
 
                       
Net Loss
  $ (0.12 )   $ (0.13 )   $ (0.43 )   $ (0.44 )
 
                       
Weighted Average Shares Outstanding:
                               
Basic
    137,887       114,774       128,000       114,742  
Diluted
    137,887       114,774       128,000       114,742  
The accompanying notes are an integral part of these financial statements.

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
                 
    Nine Months Ended September 30,  
    2011     2010  
Cash Flows from Operating Activities:
               
Net Loss
  $ (54,641 )   $ (50,001 )
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities:
               
Depreciation and Amortization
    130,355       144,758  
Stock-Based Compensation Expense
    3,898       2,799  
Deferred Income Taxes
    (47,458 )     (38,639 )
Provision (Benefit) for Doubtful Accounts Receivable
    (12,240 )     80  
Amortization of Deferred Financing Fees
    2,877       2,493  
Amortization of Original Issue Discount
    3,305       3,041  
Non-Cash Loss on Derivatives
    3,065       1,987  
(Gain) Loss on Disposal of Assets and Businesses, Net
    5,495       (10,180 )
Other
    (197 )     (381 )
(Increase) Decrease in Operating Assets -
               
Accounts Receivable
    7,622       (10,841 )
Prepaid Expenses and Other
    21,744       16,563  
Increase (Decrease) in Operating Liabilities -
               
Accounts Payable
    (9,013 )     (2,811 )
Insurance Notes Payable
    (18,778 )     (15,036 )
Other Current Liabilities
    13,260       (10,011 )
Other Liabilities
    9,073       (14,141 )
 
           
Net Cash Provided by Operating Activities
    58,367       19,680  
Cash Flows from Investing Activities:
               
Acquisition of Seahawk Assets
    (25,000 )      
Additions of Property and Equipment
    (33,508 )     (16,353 )
Deferred Drydocking Expenditures
    (12,859 )     (10,972 )
Cash Paid for Equity Investment
    (34,155 )      
Proceeds from Sale of Assets and Businesses, Net
    58,440       15,764  
Increase in Restricted Cash
    (2,476 )     (9,466 )
 
           
Net Cash Used in Investing Activities
    (49,558 )     (21,027 )
Cash Flows from Financing Activities:
               
Long-term Debt Repayments
    (18,615 )     (5,233 )
Payment of Debt Issuance Costs
    (2,109 )      
Other
    2,523       396  
 
           
Net Cash Used in Financing Activities
    (18,201 )     (4,837 )
 
           
Net Decrease in Cash and Cash Equivalents
    (9,392 )     (6,184 )
Cash and Cash Equivalents at Beginning of Period
    136,666       140,828  
 
           
Cash and Cash Equivalents at End of Period
  $ 127,274     $ 134,644  
 
           
The accompanying notes are an integral part of these financial statements.

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(In thousands)
(Unaudited)
                                 
    Three Months Ended September 30,     Nine Months Ended September 30,  
    2011     2010     2011     2010  
Net Loss
  $ (16,992 )   $ (15,061 )   $ (54,641 )   $ (50,001 )
Other Comprehensive Income, Net of Taxes:
                               
Changes Related to Hedge Transactions
          1,762             5,773  
 
                       
Comprehensive Loss
  $ (16,992 )   $ (13,299 )   $ (54,641 )   $ (44,228 )
 
                               
 
                       
The accompanying notes are an integral part of these financial statements.

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Table of Contents

HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 and International Liftboats segments (See Note 12). At September 30, 2011, the Company owned a fleet of 49 jackup rigs, 17 barge rigs, two submersible rigs, one platform rig, 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 May 2011, the Company completed the sale of substantially all of Delta Towing’s assets and certain liabilities (See Note 5). Accordingly, the Company has recast certain prior period financial information to reflect the results of operations of the Delta Towing assets as discontinued operations for all periods presented.
     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, accounts payable and certain contractual rights (“Seahawk Transaction”). On April 27, 2011, the Company completed the Seahawk Transaction (See Note 4).
     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 September 30, 2011, Consolidated Statements of Operations and Consolidated Statements of Comprehensive Loss for the three and nine months ended September 30, 2011 and 2010, and Consolidated Statements of Cash Flows for the nine months ended September 30, 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, as amended on Form 8-K filed July 8, 2011. The results of operations for the three and nine months ended September 30, 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 continue 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.

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED
Recent Events
     On September 18, 2011, the Company was conducting a required annual spud can inspection on the Hercules 185 in protected waters offshore Angola. While conducting the inspection, it was determined that the spud can on the starboard leg had detached from the leg. While preparing the rig for heavy-lift transport to a shipyard in Pascagoula, Mississippi to conduct the spud can repairs, additional leg damage was identified. The additional damage must be repaired before the rig can be transported to the shipyard in Mississippi. The Company is currently in the process of repairing the additional leg damage and preparing the rig for the transport to Pascagoula, Mississippi. Until a full inspection of the rig is completed, it is impossible to determine the full extent of the damage, the scope and cost of the repairs necessary to return the rig to service and the anticipated time needed to complete the required repairs. However, the Company currently estimates that the rig will be out of service for approximately six months. During this period, the rig will be at zero dayrate pursuant to its contract with Cabinda Gulf Oil Company (“Cabinda Gulf”). The Company has discussed the expected downtime of the rig with Cabinda Gulf and Cabinda Gulf has indicated that it intends to accept the rig after the completion of the repairs and to continue the contract, although Cabinda Gulf may have the right to terminate the contract and be paid $1.0 million by the Company for liquidated damages. The Company expects to be insured for damage to the rig up to the insured value of $35.0 million, subject to a $3.5 million deductible and other customary limitations and exclusions. The Company has incurred approximately $2.0 million during the three months ended September 30, 2011 related to rig repairs, inspections and other costs, of which all or a portion of these costs will be applied to the deductible associated with this claim. In addition, the rig had a net book value of $52.3 million as of September 30, 2011.
     On September 30, 2011, the Starfish, a 140 class liftboat (the “Vessel”), was underway in the Gulf of Mexico in Ship Shoal Block 116 when it was hit by a series of waterspouts and capsized. The Vessel has been anchored and secured by a salvage company retained by the Company. The Company anticipates salvaging the Vessel when weather conditions are favorable. The Company’s underwriters have determined that the Vessel is considered to be a constructive total loss and, therefore, the Company will receive the full insured value of the Vessel, $2.5 million. The Company carries removal of wreck insurance adequately covering the salvage operation, subject to a $250,000 deductible. Additionally, the Company carries pollution insurance, subject to a $3 million deductible and other customary limitations. The Vessel had a net book value of $0.7 million.
Permanent Importation
     On May 16, 2011, the Company initiated the permanent importation of Rig 3, its platform rig under contract in Mexico, and related equipment and spares into Mexico, at a net cost of approximately $8 million. The net cost consists of a cash payment of approximately $13 million, including approximately $5 million of value added tax, which the Company expects to fully recover as provided by Mexican law.
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. Additionally, the initial fair value of the warrants and 500,000 shares issued from Discovery Offshore have been recorded to deferred revenue to be amortized over 30 years, the estimated useful life of the two new-build Discovery Offshore rigs (See Note 3). 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 September 30,     Nine Months Ended September 30,  
    2011     2010     2011     2010  
Revenue deferred
  $ 8,042     $     $ 34,067     $ 600  
Expense deferred
    5,729             9,227        
Deferred Revenue recognized
    6,712       4,892       17,487       15,114  
Deferred Expense recognized
    1,297       276       2,516       2,037  
     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.

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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     As of  
    Balance Sheet   September 30,     December 31,  
    Classification   2011     2010  
Assets:
                   
Deferred Expense-Current Portion
  Other   $ 8,342     $ 1,824  
Deferred Expense-Non-Current Portion
  Other Assets, Net     3,365       3,172  
Liabilities:
                   
Deferred Revenue-Current Portion
  Other Current Liabilities     14,637       12,628  
Deferred Revenue-Non-Current Portion
  Other Liabilities     14,571        
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. During the nine months ended September 30, 2011, $14.0 million has been recorded as deferred revenue and $12.5 million was outstanding at September 30, 2011. The Company recognized $0.8 million and $1.5 million as revenue during the three and nine months ended September 30, 2011, respectively, under the percentage-of-completion method of accounting. Additionally, $0.7 million and $1.3 million in cost was recognized during the three and nine months ended September 30, 2011, respectively, under the percentage-of-completion method of accounting related to activities associated with the performance of contract obligations.
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 $12.9 million and $29.8 million at September 30, 2011 and December 31, 2010, respectively. The change in the Company’s allowance during the nine months ended September 30, 2011 related primarily to payments received from a customer in its International Offshore segment.
Other Assets
     Other assets consist of drydocking costs for marine vessels, a derivative asset, 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 September 30, 2011 and December 31, 2010, were $6.4 million and $5.9 million, respectively. Amortization expense for drydocking costs was $4.2 million and $12.1 million for the three and nine months ended September 30, 2011 and $3.0 million and $10.6 million for the three and nine months ended September 30, 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 September 30, 2011 and December 31, 2010 were $10.1 million and $11.4 million, respectively. Amortization expense for financing fees was $1.0 million and $2.9 million for the three and nine months ended September 30, 2011, respectively and $0.8 million and $2.5 million for the three and nine months ended September 30, 2010, respectively, 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.

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED
Restricted Cash
     The Company’s restricted cash balance supports surety bonds related to the Company’s Mexico and U.S. operations.
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 5.7 million and 6.5 million were anti-dilutive and are excluded from the calculation of the dilutive effect of stock equivalents for the diluted earnings per share calculations for the three and nine months ended September 30, 2011, respectively. Stock equivalents of 6.6 million and 6.2 million were anti-dilutive and are excluded from the calculation of the dilutive effect of stock equivalents for the diluted earnings per share calculations for the three and nine months ended September 30, 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 either the three and nine months ended September 30, 2011 and 2010, respectively, 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 any of these periods.
3. Equity Investment
     In January 2011, the Company made an initial investment of $10 million to purchase 5.0 million shares of a new entity incorporated in Luxembourg, Discovery Offshore S.A. (“Discovery Offshore”). Discovery Offshore has ordered two new-build ultra high specification harsh environment jackup drilling rigs (collectively the “Rigs” or individually “Rig”) and they hold options to purchase two additional rigs of the same specifications. Although these options were set to expire in late October 2011, Discovery Offshore is currently in discussions with the shipyard to extend the exercise date on these two options. 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. 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.
     The Company’s total equity investment in Discovery Offshore was $34.9 million, or 28%, as of September 30, 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 totaling $24.2 million, or 12.9 million shares for the nine months ended September 30, 2011, which includes $12.3 million, or 7.5 million shares for the three months ended September 30, 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 was issued warrants to purchase up to 5.0 million additional shares of Discovery Offshore, additional compensation for its costs incurred and efforts expended in forming Discovery Offshore, that, if exercised, would be recorded as an increase in the Company’s equity investment in Discovery Offshore (See Notes 1, 7 and 8).
4. Business Combination
     On April 27, 2011, the Company completed its acquisition of 20 jackup rigs and related assets, accounts receivable, accounts payable and certain contractual rights from Seahawk for total consideration of approximately $150.3 million consisting of $25.0 million of cash and 22.1 million shares of Hercules common stock, net of a working capital adjustment. Seahawk operated a jackup rig business that provided contract drilling services to the oil and natural gas exploration and production industry in the Gulf of Mexico.

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED
     The Seahawk Transaction expanded the Company’s jackup fleet and further strengthened the Company’s position as a leading shallow-water drilling provider. The fair value of the shares issued was determined using the closing price of the Company’s common stock of $5.68 on April 27, 2011. The results of Seahawk are included in the Company’s results from the date of acquisition.
     The Company accounted for this transaction as a business combination and accordingly the total consideration was allocated to Seahawk’s net tangible assets based on their estimated fair values. The Company is in the process of finalizing valuations of the property and equipment. Therefore, the valuations of property and equipment are preliminary and are subject to change upon the receipt and management’s review of the final valuations. In addition, certain of the Company’s tax positions are also being reviewed and the valuation of the Company’s deferred taxes are preliminary and are subject to change (See Note 11). The Company has recorded the accounts receivable at estimated fair value which does not include an allowance for doubtful accounts. Upon final valuation of net assets, the excess, if any, of the purchase price over the net assets will be recorded as goodwill, and conversely, if the purchase price is less than the fair value of the net assets, a gain from a bargain purchase will be recorded.
     The preliminary allocation of the consideration is as follows:
         
    April 27, 2011  
    (In thousands)  
    (Unaudited)  
Accounts Receivable
  $ 15,366  
Property and Equipment, Net
    145,404  
 
     
Total Assets
    160,770  
Accounts Payable
    (10,441 )
 
     
Total Preliminary Purchase Price
  $ 150,329  
 
     
     The following presents the consolidated financial information for the Company on a pro forma basis assuming the Seahawk Transaction had occurred as of the beginning of the periods presented. The historical financial information has been adjusted to give effect to pro forma items that are directly attributable to the acquisition, factually supportable and with respect to income, are expected to have a continuing impact on consolidated results. These items include adjustments to record the incremental depreciation expense related to the increase in fair value of the acquired assets, the elimination of amounts related to the operations of Seahawk that were not purchased in the transaction as well as the elimination of directly related transaction costs.
     The unaudited financial information set forth below has been compiled from historical financial statements and other information, but is not necessarily indicative of the results that actually would have been achieved had the transaction occurred on the dates indicated or that may be achieved in the future:
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2011     2010     2011     2010  
            (In millions, except per share amounts)  
Revenue
  $ 163.0     $ 176.2     $ 526.0     $ 519.0  
Net Loss
    (16.6 )     (35.2 )     (52.8 )     (80.4 )
Basic loss per share
    (0.12 )     (0.26 )     (0.38 )     (0.59 )
Diluted loss per share
    (0.12 )     (0.26 )     (0.38 )     (0.59 )

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED
     The amount of revenue and net income related to the net assets acquired from Seahawk included in the Company’s Consolidated Statements of Operations for the three and nine months ended September 30, 2011 is as follows (in millions):
                 
    Three months     April 27, 2011  
    ended     through  
    September     September  
    30, 2011     30, 2011  
Revenue
  $ 24.8     $ 42.0  
Net income
    1.1       2.7  
     The Company incurred transaction costs in the amount of $0.5 million and $3.6 million for the three and nine months ended September 30, 2011 related to the Seahawk Transaction of which $0.5 million and $3.4 million in the same periods, respectively, are included in General and Administrative on the Consolidated Statements of Operations. The remaining $0.2 million in transaction costs are included in Operating Expenses on the Consolidated Statements of Operations for the nine months ended September 30, 2011.
5. Dispositions and Discontinued Operations
Dispositions
     From time to time the Company enters into agreements to sell assets. The following table provides information related to the sale of several of the Company’s assets during the nine months ended September 30, 2011 and 2010 (in thousands):
                       
Rig   Segment   Period of Sale   Proceeds   Gain/(Loss)  
2011:
                     
Hercules 78
  Domestic Offshore   May 2011   $ 1,700   $ 20  
Various(a)
  Delta Towing   May 2011     30,000     (13,359 )
Hercules 152
  Domestic Offshore   July 2011     5,000     271  
Hercules 190
  Domestic Offshore   September 2011     2,000     1,440  
Hercules 254
  Domestic Offshore   September 2011     2,054     369  
 
                 
 
          $ 40,754   $ (11,259 )
 
                 
2010:
                     
Various(b)
  Inland   March 2010   $ 2,200   $ 1,753  
Various(b)
  Inland   April 2010     800     410  
Hercules 191
  Domestic Offshore   April 2010     5,000     3,067  
Hercules 255
  Domestic Offshore   September 2010     5,000     3,180  
 
                 
 
          $ 13,000   $ 8,410  
 
                 
 
(a)   The Company completed the sale of substantially all of Delta Towing’s assets.
 
(b)   The Company entered into an agreement to sell six of its retired barges for $3.0 million. The sale of 3 barges closed in each of March and April 2010.
Discontinued Operations
     In May 2011, the Company completed the sale of substantially all of Delta Towing’s assets and certain liabilities for aggregate consideration of $30 million in cash (the “Delta Towing Sale”) and recognized a loss on the sale of approximately $13 million. The Company retained the working capital of its Delta Towing business which was approximately $6 million at the date of sale. The results of operations of the Delta Towing segment are reflected in the Consolidated Statements of Operations for the three and nine months ended September 30, 2011 and 2010 as discontinued operations.
     Interest charges have been allocated to the discontinued operations of the Delta Towing segment in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 205-20, Discontinued Operations. The interest

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED
was allocated based on a pro rata calculation of the net Delta Towing assets sold to the Company’s consolidated net assets. Interest allocated to discontinued operations was $0.8 million for the nine months ended September 30, 2011, and $0.6 million and $1.9 million for the three and nine months ended September 30, 2010, respectively.
     Operating results of the Delta Towing segment were as follows (in thousands):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2011     2010     2011     2010  
Revenue
  $     $ 10,875     $ 9,822     $ 25,161  
 
                       
 
                               
Income (Loss) Before Income Taxes
  $ 84     $ 1,800     $ (15,703 )   $ (733 )
Income Tax (Provision) Benefit
    (32 )     (724 )     6,052       294  
 
                       
Income (Loss) from Discontinued Operations, Net of Taxes
  $ 52     $ 1,076     $ (9,651 )   $ (439 )
 
                       
     The carrying value of the assets included in the Delta Towing Sale are as follows:
                 
    May 13,     December 31,  
    2011     2010  
    (In thousands)  
Property and Equipment, Net and Related Assets
  $ 43,359     $ 44,249  
     The nine months ended September 30, 2011 includes a loss of $13.4 million, or $8.2 million net of taxes, in connection with the Delta Towing Sale.
6. Debt
     Debt is comprised of the following (in thousands):
                 
    September 30,     December 31,  
    2011     2010  
Term Loan Facility, due July 2013
  $ 456,541     $ 475,156  
 10.5% Senior Secured Notes, due October 2017
    293,483       292,935  
 3.375% Convertible Senior Notes, due June 2038
    89,245       86,488  
 7.375% Senior Notes, due April 2018
    3,511       3,511  
 
           
Total Debt
    842,780       858,090  
Less Short-term Debt and Current Portion of Long-term Debt
    4,768       4,924  
 
           
Total Long-term Debt, Net of Current Portion
  $ 838,012     $ 853,166  
 
           
     The unamortized discount of the 10.5% Senior Secured Notes and 7.375% Senior Notes is being amortized to interest expense over the life of the respective debt instrument. The unamortized discount of the 3.375% Convertible Senior Notes is being amortized to interest expense over their expected life which ends June 1, 2013.
                                                 
            September 30, 2011                     December 31, 2010        
    Notional     Unamortized     Carrying     Notional     Unamortized     Carrying  
Liability Component   Amount     Discount     Value     Amount     Discount     Value  
            (in millions)                     (in millions)          
10.5% Senior Secured Notes, due October 2017
  $ 300.0     $ (6.5 )   $ 293.5     $ 300.0     $ (7.1 )   $ 292.9  
3.375% Convertible Senior Notes, due June 2038*
    95.9       (6.7 )     89.2       95.9       (9.4 )     86.5  
7.375% Senior Notes, due April 2018
    3.5             3.5       3.5             3.5  
 
*   The carrying amount of the equity component was $30.1 million at both September 30, 2011 and December 31, 2010.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED
                                                                 
    Three Months Ended September 30,  
            2011                             2010              
    Coupon     Discount     Total     Effective     Coupon     Discount     Total     Effective  
    Interest     Amortization     Interest     Rate     Interest     Amortization     Interest     Rate  
    (in millions)             (in millions)          
 10.5% Senior Secured Notes, due October 2017
  $ 7.9     $ 0.2     $ 8.1       11.00 %   $ 7.8     $ 0.2     $ 8.0       11.00 %
 3.375% Convertible Senior Notes, due June 2038
    0.9       0.9       1.8       7.93       0.8       0.9       1.7       7.93  
 7.375% Senior Notes, due April 2018
    0.1             0.1       7.38       0.1             0.1       7.38  
                                                                 
    Nine Months Ended September 30,  
            2011                             2010              
    Coupon     Discount     Total     Effective     Coupon     Discount     Total     Effective  
    Interest     Amortization     Interest     Rate     Interest     Amortization     Interest     Rate  
    (in millions)             (in millions)          
 10.5% Senior Secured Notes, due October 2017
  $ 23.6     $ 0.6     $ 24.2       11.00 %   $ 23.5     $ 0.5     $ 24.0       11.00 %
 3.375% Convertible Senior Notes, due June 2038
    2.5       2.7       5.2       7.93       2.4       2.6       5.0       7.93  
 7.375% Senior Notes, due April 2018
    0.2             0.2       7.38       0.2             0.2       7.38  
Senior Secured Credit Agreement
     The Company has a $596.5 million credit facility, consisting of a $456.5 million term loan facility and a $140.0 million revolving credit facility. The availability under the $140.0 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 interest rates on borrowings under the Credit Facility are 5.50% plus LIBOR for Eurodollar Loans and 4.50% plus the Alternate Base Rate for ABR Loans. The minimum LIBOR is 2.00% for Eurodollar Loans, or a minimum base rate of 3.00% with respect to ABR Loans. Under the credit agreement, as amended, which governs the credit facility (the “Credit Agreement”), the Company must among other things:
  Maintain a total leverage ratio for any test period calculated as the ratio of consolidated indebtedness on the test date to consolidated EBITDA for the trailing twelve months, all as defined in the Credit Agreement according to the following schedule:
         
    Maximum Total  
Test Date   Leverage Ratio  
 
September 30, 2011
    7.50 to 1.00  
December 31, 2011
    7.75 to 1.00  
March 31, 2012
    7.50 to 1.00  
June 30, 2012
    7.25 to 1.00  
September 30, 2012
    6.75 to 1.00  
December 31, 2012
    6.25 to 1.00  
March 31, 2013
    6.00 to 1.00  
June 30, 2013
    5.75 to 1.00  
 
          At September 30, 2011, the Company’s total leverage ratio was 5.03 to 1.00.
  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 September 30, 2011, as calculated pursuant to the Credit Agreement, the Company’s total liquidity was $265.5 million.

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED
  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
    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 September 30, 2011, the Company’s fixed charge coverage ratio was 1.35 to 1.00.
  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.
     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 September 30, 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 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. In addition to its scheduled payments, during the second quarter of 2011, the Company used a portion of the net proceeds from the sale of the Delta Towing assets to retire $15.0 million of the outstanding balance on the Company’s term loan facility.
     As of September 30, 2011, no amounts were outstanding and $1.8 million in standby letters of credit had been issued under the revolving credit facility, therefore the remaining availability under this revolving credit facility was $138.2 million. As of September 30, 2011, $456.5 million was outstanding on the term loan facility and the interest rate was 7.5%. The annualized effective rate of interest was 7.60% for the nine months ended September 30, 2011 after giving consideration to revolver fees.

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED
     In connection with the amendment of the Credit Agreement in March 2011 (“2011 Credit Amendment”), the Company 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.
10.5% Senior Secured Notes due 2017
     The 10.5% Senior Secured 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.
3.375% Convertible Senior Notes due 2038
     The 3.375% Convertible Senior 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 September 30, 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED
     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
     The Company was issued warrants to purchase up to 5.0 million additional shares of Discovery Offshore stock at a strike price of 11.5 Norwegian Kroner (“NOK”) per share 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 September 30, 2011, for 30 consecutive trading days. 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 are recognized to other income (expense). 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):
         
September 30, 2011  
Balance Sheet   Fair  
Classification   Value  
Derivatives:
       
Warrants
  $ 1,980  
 
     
Other Assets, Net
  $ 1,980  
 
     

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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 September 30,
        2011   2010       2011   2010
Derivatives   I.   II.   III.   IV.
Interest rate contracts
  Interest Expense   $              —   $ (2,711 )   Interest Expense   $     $ (5 )
Warrants
  N/A                   —         Other Income (Expense)     (1,845 )      
                         
    Nine Months Ended September 30,
        2011   2010       2011   2010
Derivatives   I.   II.   III.   IV.
Interest rate contracts
  Interest Expense   $           —         $(8,881)   Interest Expense   $              —   $(264)
Warrants
  N/A                —                —   Other Income (Expense)   (3,065)            —
 
I.   Classification of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Income (Loss) (Effective Portion)
 
II.   Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Income (Loss) (Effective Portion)
 
III.   Classification of Gain (Loss) Recognized in Income (Loss) on Derivative
 
IV.   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.

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED
     As of September 30, 2011 the fair value of the warrants issued by Discovery Offshore was $2.0 million. The fair value of the warrants was determined using a Monte Carlo simulation based on the following assumptions:
         
    September 30,  
    2011  
Strike Price (NOK)
    11.50  
Target Price (NOK)
    23.00  
Stock Value (NOK)
    8.75  
Expected Volatility (%)
    50.0 %
Risk-Free Interest Rate (%)
    0.96 %
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 September 30, 2011. 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 September 30, 2011 (in thousands):
                                 
            Quoted Prices in              
    Total     Active Markets for              
    Fair Value     Identical Asset or     Significant Other     Significant  
    Measurement     Liability     Observable Inputs     Unobservable Inputs  
    September 30, 2011     (Level 1)     (Level 2)     (Level 3)  
 
Warrants
  $ 1,980     $     $ 1,980     $  
     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     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 of which $2.4 million ($1.5 million, net of tax) related to the discontinued operations of its Delta Towing segment. The property 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 $34.9 million and $27.4 million at September 30, 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 September 30, 2011.

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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:
                                 
    September 30, 2011     December 31, 2010  
    Carrying     Fair     Carrying     Fair  
    Value     Value     Value     Value  
            (in millions)          
Term Loan Facility, due July 2013
  $ 456.5     $ 436.8     $ 475.2     $ 443.7  
10.5% Senior Secured Notes, due October 2017
    293.5       287.8       292.9       245.1  
3.375% Convertible Senior Notes, due June 2038
    89.2       81.5       86.5       69.1  
7.375% Senior Notes, due April 2018
    3.5       2.9       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 September 30, 2011, approximately 6.9 million shares were available for grant or award under the 2004 Plan, as amended in May 2011.
     During the nine months ended September 30, 2011, the Company granted 1.1 million time-based restricted stock awards with a weighted average grant-date fair value per share of $5.01. There were no stock options granted during the nine months ended September 30, 2011. The Company recognized $1.2 million and $3.9 million in stock-based compensation expense during the three and nine months ended September 30, 2011, respectively. The Company recognized $1.0 million and $2.8 million in stock-based compensation expense during the three and nine months ended September 30, 2010, respectively, which includes a reduction of $0.8 million and $2.8 million due to a change in the Company’s estimated forfeiture rate, respectively.
     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 479,183 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 September 30, 2011, was $1.2 million and $5.8 million, respectively, and is expected to be recognized over a weighted-average period of 0.8 years and 2.0 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED
     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”).
     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 September 30, 2011, the Company’s liability related to these awards was $0.6 million and is included in Other Liabilities on the Consolidated Balance Sheets. Additionally, compensation expense of $0.6 million was recognized for the nine months ended September 30, 2011. The three months ended September 30, 2011 included a reduction to compensation expense of $0.1 million based on the fair value measurement at September 30, 2011. The unrecognized compensation cost related to these awards as of September 30, 2011 was $1.8 million and is expected to be recognized over a weighted-average period of 2.3 years.
     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 September 30, 2011 using a Monte Carlo simulation based on the following weighted-average assumptions:
         
    September 30,  
    2011  
Dividend Yield
     
Expected Price Volatility
    50 %
Risk-Free Interest Rate
    0.3 %
Stock Price
  $ 2.91  
Fair Value
  $ 0.74  
     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 September 30, 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.

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED
     The following summarizes investing activities relating to the Seahawk Transaction integrated into the Company’s operations for the period shown (in thousands):
         
    Nine Months  
    Ended  
    September 30, 2011  
Fair Value of Assets
  $ 160,770  
Common Stock Issuance
    (125,329 )
Total Liabilities
    (10,441 )
 
     
Cash Consideration
  $ 25,000  
 
     
                 
    Nine Months Ended September 30,  
    2011     2010  
    (In thousands)  
Cash paid (received), net during the period for:
               
Interest
  $ 41,972     $ 40,210  
Income taxes
    3,338       19,364  
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 2010 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 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 2010.
     In January 2008, SENIAT, the national Venezuelan tax authority, 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 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.
     Effective April 27, 2011 the Company completed the Seahawk Transaction. The Company’s financial statements have been prepared assuming that this transaction should be characterized as a purchase of assets for income tax purposes. Seahawk is currently in a Chapter 11 proceeding in United States Bankruptcy Court. The resolution of the bankruptcy and future actions taken in the reorganization of Seahawk’s operations may require that the transaction is instead treated by the Company as a reorganization pursuant to IRC §368(a)(1)(G). Any resulting change, which is currently indeterminable, to the Company’s financial position would be reflected in its financial statements at that future date.
     As of September 30, 2011, the Company was in a net income tax payable position of $6.2 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.

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED
12. Segments
     The Company reports its business activities in five business segments: (1) Domestic Offshore, (2) International Offshore, (3) Inland, (4) Domestic Liftboats and (5) International Liftboats. The financial information of the Company’s discontinued operations is not included in the results of operations presented for the Company’s reporting segments (See Note 5). The Company eliminates inter-segment revenue and expenses, if any.
     The following describes the Company’s reporting segments as of September 30, 2011:
     Domestic Offshore — includes 41 jackup rigs and two submersible rigs in the U.S. Gulf of Mexico that can drill in maximum water depths ranging from 80 to 350 feet. Seventeen of the jackup rigs are either working on short-term contracts or available for contracts, one is in the shipyard and twenty-three are cold stacked. Both 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 contracted offshore in Saudi Arabia, one jackup rig contracted offshore in Vietnam, one jackup rig contracted offshore in India, one jackup rig contracted offshore in the Democratic Republic of Congo and one platform rig under contract in Mexico. The Company has one jackup rig contracted in Angola, however, it is currently preparing to be transported to a shipyard in Mississippi to undergo repairs and is estimated to be out of service for approximately six months. 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 a Construction Management Agreement and the Services Agreement with Discovery Offshore with respect to each of the Rigs (See Note 3).
     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-five are operating or available and six 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.
     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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED
     Information regarding reportable segments is as follows (in thousands):
                                                 
    Three Months Ended September 30, 2011     Nine Months Ended September 30, 2011  
            Income (Loss)     Depreciation             Income (Loss)     Depreciation  
            from     &             from     &  
    Revenue     Operations     Amortization     Revenue     Operations     Amortization  
Domestic Offshore
  $ 60,246     $ (12,824 )   $ 17,977     $ 142,688     $ (55,121 )   $ 49,920  
International Offshore
    48,965       12,946       12,913       196,131       63,827       39,469  
Inland
    8,124       923       3,310       21,251       (7,649 )     11,338  
Domestic Liftboats
    16,718       615       4,136       44,209       (844 )     11,637  
International Liftboats
    28,938       8,523       4,905       88,291       26,084       14,379  
 
                                   
 
    162,991       10,183       43,241       492,570       26,297       126,743  
Corporate
          (13,216 )     654             (34,910 )     1,956  
 
                                   
Total Company
  $ 162,991     $ (3,033 )   $ 43,895     $ 492,570     $ (8,613 )   $ 128,699  
 
                                   
                                                 
    Three Months Ended September 30, 2010     Nine Months Ended September 30, 2010  
            Income (Loss)     Depreciation             Income (Loss)     Depreciation  
            from     &             from     &  
    Revenue     Operations     Amortization     Revenue     Operations     Amortization  
Domestic Offshore
  $ 25,058     $ (32,066 )   $ 17,277     $ 88,163     $ (82,712 )   $ 50,986  
International Offshore
    74,429       26,893       14,404       221,364       73,616       43,808  
Inland
    5,745       (8,628 )     4,991       15,676       (21,663 )     18,736  
Domestic Liftboats
    24,612       9,424       3,314       53,950       9,851       11,182  
International Liftboats
    27,765       9,431       4,199       80,914       21,227       13,258  
 
                                   
 
    157,609       5,054       44,185       460,067       319       137,970  
Corporate
          (8,895 )     797             (28,855 )     2,412  
 
                                   
Total Company
  $ 157,609     $ (3,841 )   $ 44,982     $ 460,067     $ (28,536 )   $ 140,382  
 
                                   
                 
    Total Assets  
    September 30,     December 31,  
    2011     2010  
Domestic Offshore
  $ 891,593     $ 772,950  
International Offshore
    740,054       712,988  
Inland
    121,283       136,229  
Domestic Liftboats
    84,064       86,013  
International Liftboats
    161,691       167,561  
Delta Towing
    2,605       56,631  
Corporate
    52,735       62,937  
 
           
Total Company
  $ 2,054,025     $ 1,995,309  
 
           
13. Commitments and Contingencies
Legal Proceedings
     The Company is involved in various claims and lawsuits in the normal course of business. As of September 30, 2011, management did not believe any accruals were necessary in accordance with FASB ASC 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED
     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.
Shareholder Derivative Suits
     FCPA Litigation
     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 its 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.
     On October 19, 2011, the District Court sustained special exceptions filed by the Company and the other defendants (collectively “Defendants”). The special exceptions filed by the Defendants sought the dismissal of the action due to the plaintiff’s failure to plead sufficient facts giving rise to a cause of action. The District Court ordered the action will be dismissed with prejudice if the plaintiff fails to amend his petition by November 4, 2011 and plead sufficient facts giving rise to a cause of action against the Defendants.
     Say-on-Pay Litigation
     In June, two separate shareholder derivative actions were filed against the Company in response to the Company’s failure to receive a majority advisory vote in favor of its 2010 executive compensation. On June 8, 2011, the first action was filed in the District Court of Harris County, Texas, and on June 23, 2011, the second action was filed in the United States District Court for the District of Delaware. Subsequently, on July 21, 2011, the plaintiff in the Harris County action filed a concurrent action in the Federal District Court for the Southern District of Texas. Each action was ostensibly filed on behalf of and for the benefit of the Company, naming the Company as a nominal defendant and certain of its officers and directors, as well as its compensation consultant, as defendants alleging, among other claims, breach of fiduciary duty and unjust enrichment. The petitions allege that pay increases to the Company’s

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED
executive officers in 2010 were unwarranted and violated Company policy. The plaintiffs in each matter seek damages, injunctive and/or equitable relief purportedly on behalf of the Company, certain corporate actions, and an award of their costs and attorney’s fees.
     The Company does not expect the ultimate outcome of any of these shareholder derivative 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
     The Company is self-insured for the deductible portion of its insurance coverage. Management believes adequate accruals have been made on known and estimated exposures up to the deductible portion of the Company’s insurance coverage. Management believes that claims and liabilities in excess of the amounts accrued are adequately insured. However, 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.
     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.
     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 liability coverage 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.

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED
     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 2011, in connection with the renewal of certain of its insurance policies, the Company entered into an agreement to finance a portion of its annual insurance premiums. Approximately $25.8 million was financed through this arrangement, of which $13.0 million was outstanding as of September 30, 2011. The interest rate on the note is 3.59% and it is scheduled to mature in March 2012.
Surety Bonds, Bank Guarantees and Unsecured Letters of Credit
     The Company had $17.6 million outstanding related to surety bonds at September 30, 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.
     The Company had $1.0 million in unsecured bank guarantees and a $0.1 million unsecured letter of credit outstanding at September 30, 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, which is included in Accrued Liabilities on the Consolidated Balance Sheets, as of September 30, 2011 and December 31, 2010, respectively, while the Company provides additional information and responds to auditor requests.
14. Accounting Pronouncements
     In May 2011, the FASB issued Accounting Standards Update (“ASU”) No. 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“ASU 2011-04”) which changes the wording used to describe many of the requirements in U.S. GAAP for measuring fair value and disclosing information about fair value measurements. Some of the amendments clarify the FASB’s intent about the application of existing fair value measurement requirements while other amendments change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. The amendments in this ASU are effective prospectively for interim and annual periods beginning after December 15, 2011, with no early adoption permitted. The Company does not expect the adoption of this standard to have a material impact on its consolidated financial statements.
     In June 2011, the FASB issued ASU No. 2011-05, Presentation of Comprehensive Income (“ASU 2011-05”), which eliminates the option to present components of other comprehensive income as part of the statement of changes in stockholders’ equity. The amendments in this standard require that an entity present the total of comprehensive income, the components of net income, and the components of other comprehensive income in a single continuous statement of comprehensive income or in two separate but consecutive statements. Under either method, the entity is required to present on the face of the financial statements reclassification adjustments for items that are reclassified from other comprehensive income to net income in the statement(s) where the components of net income and the components of other comprehensive income are presented. For public entities, the amendments in this ASU are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 and are to be applied retrospectively, with early adoption permitted. The Company does not expect the adoption of this standard to have a material impact on its consolidated financial statements.

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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 September 30, 2011 and for the three and nine months ended September 30, 2011 and September 30, 2010, included elsewhere herein, and with our Annual Report on Form 10-K for the year ended December 31, 2010, as amended on Form 8-K filed on July 8, 2011. 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, as amended on Form 8-K filed July 8, 2011, for the year ended December 31, 2010, Item 1A of Part II of our quarterly report on Form 10-Q, as amended on Form 8-K filed July 8, 2011, for the quarter ended March 31, 2011, Item 1A of Part II of our quarterly report on Form 10-Q for the quarter ended June 30, 2011 and Item 1A of Part II of this quarterly report 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. We own a fleet of 49 jackup rigs, 17 barge rigs, two submersible rigs, one platform rig 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.
Asset Purchase
     On April 27, 2011, we completed our acquisition of 20 jackup rigs and related assets, accounts receivable, accounts payable and certain contractual rights from Seahawk (“Seahawk Transaction”) for total consideration of approximately $150.3 million consisting of $25.0 million of cash and 22.1 million shares of Hercules common stock, net of a working capital adjustment. The fair value of the shares issued was determined using the closing price of our common stock of $5.68 on April 27, 2011. The results of Seahawk are included in our results from the date of acquisition.
Asset Disposition
     In May 2011, we completed the sale of substantially all of Delta Towing’s assets and certain liabilities for aggregate consideration of $30 million in cash (the “Delta Towing Sale”) and recognized a loss on the sale of approximately $13 million. We retained the working capital of our Delta Towing business which was approximately $6 million at the date of sale. The results of operations of the Delta Towing segment are reflected in the Consolidated Statements of Operations for the three and nine months ended September 30, 2011 and 2010 as discontinued operations.
Financial Statement Recast
     In connection with the Delta Towing sale, we have recast certain prior period financial information to reflect the results of operations of the Delta Towing assets as discontinued operations for all periods presented.
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. Although these options were set to expire in late October 2011, Discovery Offshore is currently in discussions with the shipyard to extend the exercise date on these two options.

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     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 of 11.5 Norwegian Kroner per share 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 September 30, 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 five business segments, which, as of October 26, 2011, included the following:
     Domestic Offshore — includes 41 jackup rigs and two submersible rigs in the U.S. Gulf of Mexico that can drill in maximum water depths ranging from 80 to 350 feet. Seventeen of the jackup rigs are either working on short-term contracts or available for contracts, one is in the shipyard and twenty-three are cold stacked. Both 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 contracted offshore in Saudi Arabia, one jackup rig contracted offshore in Vietnam, one jackup rig contracted offshore in India, one jackup rig contracted offshore in the Democratic Republic of Congo and one platform rig contracted offshore in Mexico. We have one jackup rig contracted in Angola, however, it is currently preparing to be transported to a shipyard in Mississippi to undergo repairs and is estimated to be out of service for approximately six months. In addition, we have one jackup rig warm stacked and one jackup rig cold stacked in Bahrain. In addition, to owning and operating our own rigs, we have the Construction Management Agreement and the Services Agreement with Discovery Offshore with respect to each of the Rigs.
     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-five are operating or available and six 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.
     In July 2011, we sold Hercules 152 for gross proceeds of $5.0 million. The financial information for Hercules 152 has been reported as part of the Domestic Offshore segment. In September 2011, we sold Hercules 190 and Hercules 254 for gross proceeds of $4.1 million. The financial information for Hercules 190 and Hercules 254 have been reported as part of the Domestic Offshore segment.
     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.

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     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 October 26, 2011 totaled approximately $375.7 million for our executed contracts. Approximately $70.2 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 management agreements, 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.
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 continue 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.

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Regulations
     The United States Coast Guard recently issued a Policy Letter that provides for more frequent inspections of foreign flagged Mobile Offshore Drilling Units (MODUs) that operate on the United States Outer Continental Shelf (OCS). The Coast Guard will make determinations to conduct more frequent inspections of foreign flagged MODUs in accordance with its newly-implemented Mobile Offshore Drilling Unit Safety and Environmental Protection Compliance Targeting Matrix. We may be subject to increased costs and potential downtime for certain of our rigs operating on the OCS if such rigs are determined by the Coast Guard to need additional oversight and inspection under this new Policy Letter.
     In addition to this new Coast Guard Policy Letter, the BOEMRE is also continuing to review whether it can directly regulate drilling contractors. To this point, the BOEMRE has only had jurisdiction over the operators of oil and gas properties, but has, in response to the Macondo well blowout in April 2010, been considering expanding its authority to include the regulation of drilling contractors. If the BOEMRE is granted such authority over drilling contractors, we could be subject to additional regulations with respect to our operations in the United States Gulf of Mexico, which may have an adverse effect on our business and results of operations.
Recent Events
     On September 18, 2011, we were conducting a required annual spud can inspection on the Hercules 185 in protected waters offshore Angola. While conducting the inspection, it was determined that the spud can on the starboard leg had detached from the leg. While preparing the rig for heavy-lift transport to a shipyard in Pascagoula, Mississippi to conduct the spud can repairs, additional leg damage was identified. The additional damage must be repaired before the rig can be transported to the shipyard in Mississippi. We are currently in the process of repairing the additional leg damage and preparing the rig for the transport to Pascagoula, Mississippi. Until a full inspection of the rig is completed, it is impossible to determine the full extent of the damage, the scope and cost of the repairs necessary to return the rig to service and the anticipated time needed to complete the required repairs. However, we currently estimate that the rig will be out of service for approximately six months. During this period, the rig will be at zero dayrate pursuant to its contract with Cabinda Gulf Oil Company (“Cabinda Gulf”). We have discussed the expected downtime of the rig with Cabinda Gulf and Cabinda Gulf has indicated that it intends to accept the rig after the completion of the repairs and to continue the contract, although Cabinda Gulf may have the right to terminate the contract and be paid $1.0 million by us for liquidated damages. We expect to be insured for damage to the rig up to the insured value of $35.0 million, subject to a $3.5 million deductible and other customary limitations and exclusions. We have incurred approximately $2.0 million during the three months ended September 30, 2011 related to rig repairs, inspections and other costs, of which all or a portion of these costs will be applied to the deductible associated with this claim. In addition, the rig had a net book value of $52.3 million as of September 30, 2011.
     On September 30, 2011, the Starfish, a 140 class liftboat (the “Vessel”), was underway in the Gulf of Mexico in Ship Shoal Block 116 when it was hit by a series of waterspouts and capsized. The Vessel has been anchored and secured by a salvage company retained by us. We anticipate salvaging the Vessel when weather conditions are favorable. Our underwriters have determined that the Vessel is considered to be a constructive total loss and, therefore, we will receive the full insured value of the Vessel, $2.5 million. We carry removal of wreck insurance adequately covering the salvage operation, subject to a $250,000 deductible. Additionally, we carry pollution insurance, subject to a $3 million deductible and other customary limitations. The Vessel had a net book value of $0.7 million.

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RESULTS OF OPERATIONS
     On April 27, 2011, we completed the Seahawk Transaction. The results of Seahawk are included in our results from the date of acquisition which impacts the comparability of the 2011 periods with the corresponding 2010 periods.
     The following table sets forth financial information by operating segment and other selected information for the periods indicated:
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2011     2010     2011     2010  
            (Dollars in thousands)        
            (As Adjusted)             (As Adjusted)  
Domestic Offshore:
                               
Number of rigs (as of end of period)
    43       25       43       25  
Revenue
  $ 60,246     $ 25,058     $ 142,688     $ 88,163  
Operating expenses
    53,184       38,701       140,390       115,082  
Depreciation and amortization expense
    17,977       17,277       49,920       50,986  
General and administrative expenses
    1,909       1,146       7,499       4,807  
 
                       
Operating loss
  $ (12,824 )   $ (32,066 )   $ (55,121 )   $ (82,712 )
 
                       
International Offshore:
                               
Number of rigs (as of end of period)
    9       9       9       9  
Revenue
  $ 48,965     $ 74,429     $ 196,131     $ 221,364  
Operating expenses
    29,098       31,065       99,803       98,394  
Depreciation and amortization expense
    12,913       14,404       39,469       43,808  
General and administrative expenses
    (5,992 )     2,067       (6,968 )     5,546  
 
                       
Operating income
  $ 12,946     $ 26,893     $ 63,827     $ 73,616  
 
                       
Inland:
                               
Number of barges (as of end of period)
    17       17       17       17  
Revenue
  $ 8,124     $ 5,745     $ 21,251     $ 15,676  
Operating expenses
    3,535       8,279       16,693       20,359  
Depreciation and amortization expense
    3,310       4,991       11,338       18,736  
General and administrative expenses
    356       1,103       869       (1,756 )
 
                       
Operating income (loss)
  $ 923     $ (8,628 )   $ (7,649 )   $ (21,663 )
 
                       
Domestic Liftboats:
                               
Number of liftboats (as of end of period)
    41       41       41       41  
Revenue
  $ 16,718     $ 24,612     $ 44,209     $ 53,950  
Operating expenses
    11,419       11,314       31,837       31,481  
Depreciation and amortization expense
    4,136       3,314       11,637       11,182  
General and administrative expenses
    548       560       1,579       1,436  
 
                       
Operating income (loss)
  $ 615     $ 9,424     $ (844 )   $ 9,851  
 
                       
International Liftboats:
                               
Number of liftboats (as of end of period)
    24       24       24       24  
Revenue
  $ 28,938     $ 27,765     $ 88,291     $ 80,914  
Operating expenses
    14,136       12,951       43,358       42,310  
Depreciation and amortization expense
    4,905       4,199       14,379       13,258  
General and administrative expenses
    1,374       1,184       4,470       4,119  
 
                       
Operating income
  $ 8,523     $ 9,431     $ 26,084     $ 21,227  
 
                       

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    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2011     2010     2011     2010  
            (Dollars in thousands)        
            (As Adjusted)             (As Adjusted)  
Total Company:
                               
Revenue
  $ 162,991     $ 157,609     $ 492,570     $ 460,067  
Operating expenses
    111,372       102,310       332,081       307,626  
Depreciation and amortization
    43,895       44,982       128,699       140,382  
General and administrative
    10,757       14,158       40,403       40,595  
 
                       
Operating loss
    (3,033 )     (3,841 )     (8,613 )     (28,536 )
Interest expense
    (20,389 )     (20,752 )     (59,035 )     (62,437 )
Expense of credit agreement fees
                (455 )      
Equity in losses of equity investment
    (34 )           (225 )      
Other, net
    (1,561 )     (22 )     (2,583 )     3,144  
 
                       
Loss before income taxes
    (25,017 )     (24,615 )     (70,911 )     (87,829 )
Income tax benefit
    7,973       8,478       25,921       38,267  
 
                       
Loss from continuing operations
    (17,044 )     (16,137 )     (44,990 )     (49,562 )
Income (loss) from discontinued operations, net of taxes
    52       1,076       (9,651 )     (439 )
 
                       
Net loss
  $ (16,992 )   $ (15,061 )   $ (54,641 )   $ (50,001 )
 
                       
     The following table sets forth selected operational data by operating segment for the period indicated:
                                         
    Three Months Ended September 30, 2011  
                                    Average  
                            Average     Operating  
    Operating     Available             Revenue     Expense  
    Days     Days     Utilization (1)     per Day (2)     per Day (3)  
Domestic Offshore
    1,228       1,656       74.2 %   $ 49,060     $ 32,116  
International Offshore
    508       736       69.0 %     96,388       39,535  
Inland
    262       276       94.9 %     31,008       12,808  
Domestic Liftboats
    2,246       3,220       69.8 %     7,443       3,546  
International Liftboats
    1,357       2,116       64.1 %     21,325       6,681  
                                         
    Three Months Ended September 30, 2010  
                                    Average  
                            Average     Operating  
    Operating     Available             Revenue     Expense  
    Days     Days     Utilization (1)     per Day (2)     per Day (3)  
Domestic Offshore
    637       1,012       62.9 %   $ 39,338     $ 38,242  
International Offshore
    538       828       65.0 %     138,344       37,518  
Inland
    269       276       97.5 %     21,357       29,996  
Domestic Liftboats
    3,203       3,496       91.6 %     7,684       3,236  
International Liftboats
    1,198       2,116       56.6 %     23,176       6,121  

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    Nine Months Ended September 30, 2011  
                                    Average  
                            Average     Operating  
    Operating     Available             Revenue     Expense  
    Days     Days     Utilization (1)     per Day (2)     per Day (3)  
Domestic Offshore
    3,075       4,099       75.0 %   $ 46,403     $ 34,250  
International Offshore
    1,654       2,184       75.7 %     118,580       45,697  
Inland
    739       819       90.2 %     28,756       20,382  
Domestic Liftboats
    5,676       9,855       57.6 %     7,789       3,231  
International Liftboats
    4,022       6,279       64.1 %     21,952       6,905  
                                         
    Nine Months Ended September 30, 2010  
                                    Average  
                            Average     Operating  
    Operating     Available             Revenue     Expense  
    Days     Days     Utilization (1)     per Day (2)     per Day (3)  
Domestic Offshore
    2,426       3,074       78.9 %   $ 36,341     $ 37,437  
International Offshore
    1,598       2,516       63.5 %     138,526       39,107  
Inland
    759       819       92.7 %     20,653       24,858  
Domestic Liftboats
    7,433       10,374       71.7 %     7,258       3,035  
International Liftboats
    3,596       6,430       55.9 %     22,501       6,580  
 
(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 September 30, 2011 and 2010
Revenue
     Consolidated. Total revenue for the three-month period ended September 30, 2011 (the “Current Quarter”) was $163.0 million compared with $157.6 million for the three-month period ended September 30, 2010 (the “Comparable Quarter”), an increase of $5.4 million, or 3%. This increase is further described below.
     Domestic Offshore. Revenue for our Domestic Offshore segment was $60.2 million for the Current Quarter compared with $25.1 million for the Comparable Quarter, an increase of $35.2 million, or 140%. Revenue for the Current Quarter includes $24.8 million related to the rigs acquired from Seahawk. Excluding the revenue from the rigs acquired from Seahawk, revenue increased $10.4 million due to increased operating days for the legacy Hercules rigs to 753 days during the Current Quarter from 637 days during the Comparable Quarter which contributed to an approximate $6 million increase. In addition, an increase in average dayrates for the legacy Hercules rigs, $47,133 in the Current Quarter compared to $39,338 in the Comparable Quarter, contributed to an approximate $5 million increase in revenue during the Current Quarter as compared to the Comparable Quarter.

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     International Offshore. Revenue for our International Offshore segment was $49.0 million for the Current Quarter compared with $74.4 million for the Comparable Quarter, a decrease of $25.5 million, or 34% primarily related to the decline in dayrates. The Hercules 258 and Hercules 260 contributed to a decrease of $11.1 million and $12.6 million, respectively, as their contracts matured in June and May 2011, respectively, and subsequently operated at lower dayrates. Additionally, there is no provision of marine services associated with the current contracts. Average revenue per rig per day decreased to $96,388 in the Current Quarter from $138,344 in the Comparable Quarter primarily due to lower average dayrates earned on Hercules 258 and Hercules 260.
     Inland. Revenue for our Inland segment was $8.1 million for the Current Quarter compared with $5.7 million for the Comparable Quarter, an increase of $2.4 million, or 41%. This increase was driven primarily by a 45% increase in average dayrates in the Current Quarter as compared to the Comparable Quarter.
     Domestic Liftboats. Revenue from our Domestic Liftboats segment was $16.7 million for the Current Quarter compared with $24.6 million in the Comparable Quarter, a decrease of $7.9 million, or 32%. This decrease resulted primarily from a 30% decline in operating days, largely due to activity associated with the Macondo well blowout incident remediation efforts in the Comparable Quarter, which contributed to an approximate $7 million decrease in revenue. In addition average revenue per liftboat per day declined to $7,443 in the Current Quarter compared with $7,684 in the Comparable Quarter, which contributed to an approximate $1 million decrease in revenue.
     International Liftboats. Revenue for our International Liftboats segment was $28.9 million for the Current Quarter compared with $27.8 million in the Comparable Quarter, an increase of $1.2 million, or 4%. This increase resulted primarily from an increase in operating days, which contributed to an approximate $3 million increase in revenue. Partially offsetting this increase, average revenue per liftboat per day declined to $21,325 in the Current Quarter compared with $23,176 in the Comparable Quarter which contributed to an approximate $2 million decrease in revenue.
Operating Expenses
     Consolidated. Total operating expenses for the Current Quarter were $111.4 million compared with $102.3 million in the Comparable Quarter, an increase of $9.1 million, or 9%. This increase is further described below.
     Domestic Offshore. Operating expenses for our Domestic Offshore segment were $53.2 million in the Current Quarter compared with $38.7 million in the Comparable Quarter, an increase of $14.5 million, or 37%. Operating expenses for the Current Quarter include approximately $21 million related to the rigs acquired from Seahawk. Excluding the operating expenses related to the rigs acquired from Seahawk, operating expenses decreased approximately $6 million driven by a decrease in equipment rentals, insurance costs, labor costs and repairs and maintenance expenses of $1.8 million, $1.5 million, $1.2 million and $1.0 million, respectively, offset by an increase in workers’ compensation expenses of $2.5 million. Additionally, the Comparable Quarter included an accrual of approximately $3.0 million related to a multi-year state sales and use tax audit. Average operating expenses per rig per day were $32,116 in the Current Quarter compared with $38,242 in the Comparable Quarter.
     International Offshore. Operating expenses for our International Offshore segment were $29.1 million in the Current Quarter compared with $31.1 million in the Comparable Quarter, a decrease of $2.0 million, or 6%. Hercules 258 and Hercules 260 contributed to a decrease of $3.8 million and $2.6 million respectively, due primarily to not providing marine services under their current contracts. These decreases were partially offset by a $4.3 million increase in operating expenses for Hercules 185. Average operating expenses per rig per day were $39,535 in the Current Quarter compared with $37,518 in the Comparable Quarter.
     Inland. Operating expenses for our Inland segment were $3.5 million in the Current Quarter compared with $8.3 million in the Comparable Quarter, a decrease of $4.7 million, or 57%. The Current Quarter was impacted by $2.3 million of additional net gains on asset sales during the Current Quarter as compared to the Comparable Quarter. Additionally, the Comparable Quarter included an accrual of approximately $3.0 million related to a multi-year state sales and use tax audit. Average operating expenses per rig per day were $12,808 in the Current Quarter compared with $29,996 in the Comparable Quarter.
     Domestic Liftboats. Operating expenses for our Domestic Liftboats segment were $11.4 million in the Current Quarter compared with $11.3 million in the Comparable Quarter, an increase of $0.1 million, or 1%.
     International Liftboats. Operating expenses for our International Liftboats segment were $14.1 million for the Current Quarter compared with $13.0 million in the Comparable Quarter, an increase of $1.2 million, or 9%. The increase is due to an increase in labor

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costs, repairs and maintenance expenses and catering expenses of $0.5 million, $0.5 million and $0.4 million, respectively, in the Current Quarter as compared to the Comparable Quarter. These increases are partially offset by a decrease in equipment rentals of $0.5 million in the Current Quarter as compared to the Comparable Quarter. Average operating expenses per vessel per day were $6,681 in the Current Quarter compared with $6,121 in the Comparable Quarter.
Depreciation and Amortization
     Depreciation and amortization expense in the Current Quarter was $43.9 million compared with $45.0 million in the Comparable Quarter, a decrease of $1.1 million, or 2%. This decrease resulted primarily from reduced depreciation in the Current Quarter of approximately $6 million due to asset sales and fully depreciated assets as well as asset impairments recorded in the fourth quarter of 2010, partially offset by an approximate $4 million increase in depreciation in the Current Quarter due to capital additions, including $2.6 million of depreciation related to the addition of the rigs acquired from Seahawk. Additionally, drydock amortization increased $1.5 million.
General and Administrative Expenses
     General and administrative expenses in the Current Quarter were $10.8 million compared with $14.2 million in the Comparable Quarter, a decrease of $3.4 million, or 24%. The decrease is related to a $9.9 million reduction in bad debt expense in the Current Quarter as compared to the Comparable Quarter, of which $6.5 million related to additional recoveries over the Comparable Quarter from one international customer, partially offset by an increase of $5.0 million in legal and professional service fees.
Interest Expense
     Interest expense in the Current Quarter was $20.4 million compared with $20.8 million in the Comparable Quarter, a decrease of $0.4 million, or 2%. This decrease was related primarily to the impact of our interest rate collar outstanding in the Comparable Quarter, somewhat offset by the increased rate on our term loan.
Other Expense
     Other Expense in the Current Quarter was $1.6 million due primarily to a decrease in the fair market value of our Discovery Offshore Warrants in the Current Quarter.
Income Tax Benefit
     Our income tax benefit was $8.0 million on a pre-tax loss of $25.0 million, for an effective rate of 31.9%, during the Current Quarter, compared to a benefit of $8.5 million on a pre-tax loss of $24.6 million, for an effective rate of 34.4%, 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 adjustments for various discrete items, including certain return to provision adjustments. In some cases our income tax is based on gross revenues or deemed profits under local tax laws rather than income before taxes. In addition, our assets move between taxing jurisdictions and operating structures with differing tax rates. As a result, variations in our effective tax rate from period to period may have limited correlation with pre-tax income or loss.
Discontinued Operations
     We had income from our discontinued Delta Towing operations of $0.1 million during the Current Quarter compared to $1.1 million during the Comparable Quarter.
For the Nine Months Ended September 30, 2011 and 2010
Revenue
     Consolidated. Total revenue for the nine-month period ended September 30, 2011 (the “Current Period”) was $492.6 million compared with $460.1 million for the nine-month period ended September 30, 2010 (the “Comparable Period”), an increase of $32.5 million, or 7%. This increase is further described below.

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     Domestic Offshore. Revenue for our Domestic Offshore segment was $142.7 million for the Current Period compared with $88.2 million for the Comparable Period, an increase of $54.5 million, or 62%, primarily due to revenue of $42.0 million related to the rigs acquired from Seahawk. Excluding the revenue from the rigs acquired from Seahawk, revenue increased $12.5 million for the legacy Hercules rigs due to an increase in average dayrates, $45,064 in the Current Period compared to $36,341 in the Comparable Period, which contributed to an approximate $21 million increase in revenue. This increase was partially offset by a decline in operating days for the legacy Hercules rigs to 2,234 days during the Current Period from 2,426 days during the Comparable Period which contributed to an approximate $9 million decrease in revenue during the Current Period as compared to the Comparable Period.
     International Offshore. Revenue for our International Offshore segment was $196.1 million for the Current Period compared with $221.4 million for the Comparable Period, a decrease of $25.2 million, or 11%. Hercules 258 and Hercules 260 contributed to a decrease of $15.6 million and $19.5 million, respectively, as their contracts matured in June and May 2011, respectively, and subsequently operated at lower dayrates. Additionally, there is no provision of marine services associated with the current contracts. These decreases are partially offset by Hercules 185 operating in the Current Period compared to not meeting revenue recognition criteria in the Comparable Period which contributed to a $15.1 million increase in revenue. Average revenue per rig per day decreased to $118,580 in the Current Period from $138,526 in the Comparable Period primarily due to lower average dayrates earned on Hercules 258 and Hercules 260.
     Inland. Revenue for our Inland segment was $21.3 million for the Current Period compared with $15.7 million for the Comparable Period, an increase of $5.6 million, or 36%. This increase was driven primarily by a 39% increase in average dayrates in the Current Period as compared to the Comparable Period.
     Domestic Liftboats. Revenue from our Domestic Liftboats segment was $44.2 million for the Current Period compared with $54.0 million in the Comparable Period, a decrease of $9.7 million, or 18%. This decrease resulted primarily from a 24% decline in operating days which contributed to an approximate $14 million decrease in revenue, largely due to activity associated with the Macondo well blowout incident remediation efforts in the Comparable Period. This decrease was partially offset by an increase in average revenue per liftboat per day to $7,789 in the Current Period compared with $7,258 in the Comparable Period, which contributed to an approximate $4 million increase in revenue.
     International Liftboats. Revenue for our International Liftboats segment was $88.3 million for the Current Period compared with $80.9 million in the Comparable Period, an increase of $7.4 million, or 9%. This increase resulted primarily from an increase in operating days during the Current Period to 4,022 days from 3,596 days in the Comparable Period, which contributed to an approximate $9 million increase in revenue. This increase was partially offset by a decrease in average revenue per liftboat per day to $21,952 in the Current Period compared with $22,501 in the Comparable Period, which contributed to an approximate $2 million decrease in revenue.
     Operating Expenses
     Consolidated. Total operating expenses for the Current Period were $332.1 million compared with $307.6 million in the Comparable Period, an increase of $24.5 million, or 8%. This increase is further described below.
     Domestic Offshore. Operating expenses for our Domestic Offshore segment were $140.4 million in the Current Period compared with $115.1 million in the Comparable Period, an increase of $25.3 million, or 22%, primarily due to operating expenses of approximately $33 million related to the rigs acquired from Seahawk. Excluding the operating expenses related to the rigs acquired from Seahawk, operating expenses decreased approximately $8 million driven by a decrease in labor costs, equipment rentals, insurance costs, repairs and maintenance costs and freight costs of $7.4 million, $4.0 million, $1.9 million, $1.8 million and $1.1 million, respectively, offset by an increase in workers’ compensation expenses of $9.5 million as well as $2.8 million fewer gains on asset sales in the Current Period as compared to the Comparable Period. Additionally, the Comparable Period included an accrual of approximately $3.0 million related to a multi-year state sales and use tax audit. Average operating expenses per rig per day were $34,250 in the Current Period compared with $37,437 in the Comparable Period.
     International Offshore. Operating expenses for our International Offshore segment were $99.8 million in the Current Period compared with $98.4 million in the Comparable Period, an increase of $1.4 million, or 1%. The increase was driven by i) increased operating expenses for Hercules 185 which contributed to a $8.6 million increase in the Current Period as compared to the Comparable Period as well as ii) permanent importation costs for Rig 3 of approximately $8 million during the Current Period. Partially offsetting these increases i) Hercules 205 was transferred to the Domestic Offshore segment during the first quarter of 2010 which contributed to a $3.1 million

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decrease, ii) Hercules 156 was cold stacked in December 2010 which contributed to a $3.1 million decrease, iii) Hercules 260 contributed to a $4.0 million decrease primarily due to not providing marine services under its new contract and iv) Hercules 258 contributed to a $4.1 million decrease primarily due to not providing marine services under its current contract. Average operating expenses per rig per day were $45,697 in the Current Period compared with $39,107 in the Comparable Period.
     Inland. Operating expenses for our Inland segment were $16.7 million in the Current Period compared with $20.4 million in the Comparable Period, a decrease of $3.7 million, or 18%. This decrease is primarily due to the Comparable Period accrual of approximately $3.0 million related to a multi-year state sales and use tax audit. Average operating expenses per rig per day were $20,382 in the Current Period compared with $24,858 in the Comparable Period.
     Domestic Liftboats. Operating expenses for our Domestic Liftboats segment were $31.8 million in the Current Period compared with $31.5 million in the Comparable Period, an increase of $0.4 million, or 1%.
     International Liftboats. Operating expenses for our International Liftboats segment were $43.4 million for the Current Period compared with $42.3 million in the Comparable Period, an increase of $1.0 million, or 2%. The increase is primarily due to additional labor costs of $1.7 million in the Current Period, partially offset by $1.2 million of mobilization costs amortized in the Comparable Period.
Depreciation and Amortization
     Depreciation and amortization expense in the Current Period was $128.7 million compared with $140.4 million in the Comparable Period, a decrease of $11.7 million, or 8%. This decrease resulted primarily from reduced depreciation in the Current Period of approximately $20 million due to asset sales and fully depreciated assets as well as asset impairments recorded in the fourth quarter of 2010, partially offset by an approximate $8 million increase in depreciation in the Current Period due to capital additions, including $4.4 million of depreciation related to the addition of the rigs acquired from Seahawk. Additionally, drydock amortization increased $1.4 million.
General and Administrative Expenses
     General and administrative expenses in the Current Period were $40.4 million compared with $40.6 million in the Comparable Period, a decrease of $0.2 million. The decrease is related to a $12.4 million reduction in bad debt expense in the Current Period as compared to the Comparable Period, largely offset by an increase of $10.0 million in legal and professional service fees, of which $3.4 million related to Seahawk Transaction costs. Additionally, labor and burden costs increased $1.2 million, of which $0.6 million related to the impact of the Company’s liability retention awards.
Interest Expense
     Interest expense in the Current Period was $59.0 million compared with $62.4 million in the Comparable Period, a decrease of $3.4 million, or 5%. This decrease was related primarily to the impact of our interest rate collar outstanding in the Comparable Period, somewhat offset by the increased rate on our term loan.
Expense of Credit Agreement Fees
     During the Current Period, 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.
Other Expense
     Other Expense in the Current Period was $2.6 million compared to Other Income in the Comparable Period of $3.1 million, an increase to expense of $5.7 million, primarily due to the Current Period recording of the fair market value of our Discovery Offshore Warrants of $3.1 million as well as a $3.3 million currency gain in the Comparable Period due to the devaluation of the Venezuelan Bolivar currency. These increases to expense are partially offset by additional adjustments related to numerous currencies.

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Income Tax Benefit
     Our income tax benefit was $25.9 million on a pre-tax loss of $70.9 million, for an effective rate of 36.6%, during the Current Period, compared to a benefit of $38.3 million on a pre-tax loss of $87.8 million, for an effective rate of 43.6%, for the Comparable Period. The effective tax rate in the Current Period decreased as compared to the Comparable Period due to mix of earnings (losses) from different jurisdictions as well as the prior year benefit of $5.8 million related to the effective compromise settlement with the Mexican tax authorities on certain tax liabilities, partially offset by adjustments for various discrete items, including certain return to provision adjustments in the Comparable Period. In some cases our income tax is based on gross revenues or deemed profits under local tax laws rather than income before taxes. In addition, our assets move between taxing jurisdictions and operating structures with differing tax rates. As a result, variations in our effective tax rate from period to period may have limited correlation with pre-tax income or loss.
Discontinued Operations
     We had a loss from our discontinued Delta Towing operations of $9.7 million during the Current Period compared to a loss from our discontinued Delta Towing operations of $0.4 million during the Comparable Period, a loss increase of $9.2 million. The increase in loss was primarily the result of the $13.4 million loss recognized for the Delta Towing sale in May 2011.
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.

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     The following table presents a reconciliation of the GAAP financial measure to the corresponding adjusted financial measure (in thousands):
                                 
    For the Three Months     For the Nine Months  
    Ended September 30,     Ended September 30,  
    2011     2010     2011     2010  
Loss from Continuing Operations
  $ (17,044 )   $ (16,137 )   $ (44,990 )   $ (49,562 )
Interest expense
    20,389       20,752       59,035       62,437  
Income tax benefit
    (7,973 )     (8,478 )     (25,921 )     (38,267 )
Depreciation and amortization
    43,895       44,982       128,699       140,382  
 
                       
EBITDA
    39,267       41,119       116,823       114,990  
 
                       
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 business combinations, 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, as amended on Form 8-K filed July 8, 2011, 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.
     Drilling activity levels in the shallow water U.S. Gulf of Mexico is dependent on natural gas and crude oil prices, as well as our customers’ ability to obtain necessary drilling permits to operate in the region. As of October 26, 2011, the spot price for Henry Hub natural gas was $3.65 per MMbtu, with the twelve month strip, or average of the next twelve months’ futures contracts, at $3.92 per MMbtu. While we expect natural gas will continue to account for the majority of hydrocarbon production in the region, and the performance of our Domestic Offshore segment will remain dependent on natural gas prices, our customers appear to be increasingly focused on drilling activities that contain greater concentrations of crude oil and condensates. We expect this trend to continue, given the current high price for crude oil. Further, it is our understanding that much of the crude oil produced from the U.S. Gulf of Mexico is sold at Louisiana Light Sweet (“LLS”) posted prices, which trades at a premium to other crude benchmarks, such as West Texas Intermediate (“WTI”). As of October 26, 2011, the spot price for LLS crude was $110.55 per barrel, compared to WTI spot price of $90.20 per barrel.

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     In the wake of the Macondo well blowout incident, new regulations for offshore drilling imposed by the BOEMRE in June 2010 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 for the foreseeable future.
     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. 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 41 rigs as of October 25, 2011. Of the 41 actively marketed rigs in the U.S. Gulf of Mexico, we estimate that approximately 36 are contracted.
     We are encouraged by the reduction in the marketed supply of jackup rigs in the U.S. Gulf of Mexico, the relatively limited supply of uncontracted rigs, and the high price of crude oil, all contributing to a rising dayrate environment. Tempering these positive developments in the U.S. Gulf of Mexico is the continued slow pace of permit approval, and market expectations for a prolonged period of 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.
     Additionally, based on the improved 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. These factors, coupled with our reduction of wages during the financial crisis, have resulted in an outlook for rising labor costs in our Domestic Offshore segment. Further, maintaining a skilled workforce may become harder, particularly if drilling activity in the U.S. and globally continues to rise and competition intensifies for the pool of experienced offshore labor.
     Demand for our rigs in our International Offshore segment is primarily dependent on crude oil prices. Strong year-to-date crude oil prices, 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 into 2012. 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 October 25, 2011, there were 377 jackup rigs actively marketed in international regions, of which 32 rigs were uncontracted. Further, there are 77 new jackup rigs either under construction or on order globally for delivery through 2014, of which 61 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.
     Our international drilling fleet consists of eight jackup rigs and one platform rig. In recent months, we successfully negotiated three-year contracts for two rigs in the Middle East, and a four-year contract for the platform rig. One of our jackup rigs, the Hercules 185 in West Africa, experienced damage to the starboard leg of the rig. We currently estimate that the Hercules 185 will be out of service through the first quarter of 2012 undergoing repairs. We believe that the damage is insured, subject to a $3.5 million deductible and other customary limitations and exclusions. While the Hercules 185 is contracted through February 2014, the rig will not generate revenue while it is out of service. Our remaining jackup rigs are either on short term contracts or idle. We believe that the improving fundamentals in the international jackup market will be beneficial, as we seek additional contracts for idle rigs or rigs that have contract terms nearing expiration.
     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 stabilized in 2010, but remain depressed relative to historical levels. As of October 24, 2011, there were 24 marketed barge rigs, of which 18 were contracted. We expect industry activity levels to remain relatively flat into 2012, barring a significant increase in natural gas prices and/or property exchanges to new operators that may spur drilling activity in this region.

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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. On occasion, domestic liftboat demand will experience a sharp increase due to the occurrence of exogenous events such as hurricanes or maritime incidents that result in extraordinary damage to offshore infrastructure or require coastal restoration work.
     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. Since the issuance of this mandate, our Domestic Liftboat segment has experienced an increased shift in revenue mix to plugging and abandonment services. Further increases in plugging and abandonment related services are uncertain, although we expect such services will provide a relatively stable base of activity for our domestic liftboats over the next several years.
     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. Year-to-date, utilization has been hampered by longer than expected downtime in the shipyard for several vessels in West Africa, partly due to shipyard and equipment availability, as well as local labor disputes in the region. 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 nine month period ended September 30, 2011 are as follows (in millions):
         
Net Cash Provided by Operating Activities
  $ 58.4  
Net Cash Provided by (Used in) Investing Activities:
       
Acquisition of Seahawk Assets
    (25.0 )
Additions of Property and Equipment
    (33.5 )
Deferred Drydocking Expenditures
    (12.9 )
Cash Paid for Equity Investment
    (34.2 )
Proceeds from Sale of Assets and Businesses, Net
    58.5  
Decrease in Restricted Cash
    (2.5 )
 
     
Total
    (49.6 )
Net Cash Provided by (Used in) Financing Activities:
       
Long-term Debt Repayments
    (18.6 )
Payment of Debt Issuance Costs
    (2.1 )
Other
    2.5  
 
     
Total
    (18.2 )
 
     
Net Decrease in Cash and Cash Equivalents
  $ (9.4 )
 
     
Business Combination
     On April 27, 2011, we completed the Seahawk Transaction. The results of Seahawk are included in our results from the date of acquisition.

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Equity Investment and Derivative Asset
     Our total equity investment in Discovery Offshore was $34.9 million, or 28% as of September 30, 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 totaling $24.2 million, or 12.9 million shares for the nine months ended September 30, 2011, which includes $12.3 million, or 7.5 million shares for the three months ended September 30, 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 $2.0 million as of September 30, 2011 that, if exercised, would be recorded as an increase to 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 estimated useful life of the two new-build Discovery Offshore rigs, of which $0.1 million was recognized for both the three and nine months ended September 30, 2011, respectively. Subsequent changes in the fair value of the warrants are recognized to other income (expense). We recognized $1.8 million and $3.1 million to other expense related to the change in the fair value of the warrants during the three and nine months ended September 30, 2011, respectively.
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. During the nine months ended September 30, 2011, $14.0 million has been recorded as deferred revenue and $12.5 million was outstanding at September 30, 2011. We recognized $0.8 million and $1.5 million to revenue during the three and nine months ended September 30, 2011, respectively under the percentage-of-completion method of accounting. Additionally, $0.7 million and $1.3 million in cost was recognized during the three and nine months ended September 30, 2011, respectively under the percentage-of-completion method of accounting related to activities associated with the performance of contract obligations.
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 $456.5 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 September 30, 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 $449.4 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.

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Cash Requirements and Contractual Obligations
Debt
     Our current debt structure is used to fund our business operations.
     We have a $596.5 million credit facility, consisting of a $456.5 million term loan facility and a $140.0 million revolving credit facility. The availability under the $140.0 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 interest rates on borrowings under the Credit Facility are 5.50% plus LIBOR for Eurodollar Loans and 4.50% plus the Alternate Base Rate for ABR Loans. The minimum LIBOR is 2.00% for Eurodollar Loans, or a minimum base rate of 3.00% with respect to ABR Loans. Under the credit agreement, as amended, which governs the credit facility (the “Credit Agreement”), we must among other things:
    Maintain a total leverage ratio for any test period calculated as the ratio of consolidated indebtedness on the test date to consolidated EBITDA for the trailing twelve months, all as defined in the Credit Agreement according to the following schedule:
         
    Maximum Total  
Test Date   Leverage Ratio  
 
September 30, 2011
    7.50 to 1.00  
December 31, 2011
    7.75 to 1.00  
March 31, 2012
    7.50 to 1.00  
June 30, 2012
    7.25 to 1.00  
September 30, 2012
    6.75 to 1.00  
December 31, 2012
    6.25 to 1.00  
March 31, 2013
    6.00 to 1.00  
June 30, 2013
    5.75 to 1.00  
 
    At September 30, 2011, our total leverage ratio was 5.03 to 1.00.
    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 September 30, 2011, as calculated pursuant to the Credit Agreement, our total liquidity was $265.5 million.
    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
    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 September 30, 2011, our fixed charge coverage ratio was 1.35 to 1.00.
    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;

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  —    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.
     Our obligations under the Credit Agreement are secured by liens on a majority of our vessels and substantially all of our other personal property. Substantially all of our domestic subsidiaries, and several of our international subsidiaries, guarantee the obligations under the Credit Agreement and have granted similar liens on 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 our Credit Agreement.
     The Credit Agreement requires that we meet certain financial ratios and tests, which we met as of September 30, 2011. 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 credit facility, the 10.5% Senior Secured Notes and the 3.375% Convertible Senior Notes and in the foreclosure of liens on our 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. In addition to our scheduled payments, during the second quarter of 2011, we used a portion of the net proceeds from the sale of the Delta Towing assets to retire $15.0 million of the outstanding balance on our term loan facility.
     As of September 30, 2011, no amounts were outstanding and $1.8 million in standby letters of credit had been issued under our revolving credit facility, therefore the remaining availability under this revolving credit facility was $138.2 million. As of September 30, 2011, $456.5 million was outstanding on the term loan facility and the interest rate was 7.5%. The annualized effective rate of interest was 7.60% for the nine months ended September 30, 2011 after giving consideration to revolver fees.
     In connection with the amendment of the Credit Agreement in March 2011 (“2011 Credit Amendment”), we 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.
     We recognized a decrease in fair value of five thousand dollars and $0.3 million related to the hedge ineffectiveness of our interest rate collar, settled October 1, 2010 per the contract, as Interest Expense in our Consolidated Statements of Operations for the three and nine months ended September 30, 2010, respectively. We had a net unrealized gain on hedge transactions of $1.8 million, net of tax of $0.9 million, and $5.8 million, net of tax of $3.1 million for the three and nine months ended September 30, 2010, respectively. Overall, our interest expense was increased by $2.7 million and $9.1 million during the three and nine months ended September 30, 2010, respectively 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 and nine months ended September 30, 2011 as our interest rate collar’s final settlement occurred in 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 September 30, 2011, $300.0 million notional amount of the 10.5% Senior Secured Notes was outstanding.

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     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 September 30, 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 $89.2 million at September 30, 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 September 30, 2011, the number of conversion shares potentially issuable in relation to the 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.

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     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:
                                 
    September 30, 2011   December 31, 2010
    Carrying   Fair   Carrying   Fair
    Value   Value   Value   Value
            (in millions)        
Term Loan Facility, due July 2013
  $ 456.5     $ 436.8     $ 475.2     $ 443.7  
10.5% Senior Secured Notes, due October 2017
    293.5       287.8       292.9       245.1  
3.375% Convertible Senior Notes, due June 2038
    89.2       81.5       86.5       69.1  
7.375% Senior Notes, due April 2018
    3.5       2.9       3.5       2.2  
     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.
     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 $25.0 million primary liability coverage 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.
     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.

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     In 2011, in connection with the renewal of certain of our insurance policies, we entered into an agreement to finance a portion of our annual insurance premiums. Approximately $25.8 million was financed through this arrangement, of which $13.0 million was outstanding at September 30, 2011. The interest rate on the note is 3.59% and it is scheduled to mature in March 2012.
     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.
     Capital Expenditures
     We expect to spend approximately $15 million on capital expenditures and drydocking during the remainder of 2011. 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 Transaction), 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 our ongoing capital expenditures 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 September 30, 2011, we had $20.4 million of bank guarantees, letters of credit and surety

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bonds outstanding, consisting of $1.0 million in unsecured bank guarantees, a $0.1 million unsecured outstanding letter of credit, $1.8 million in standby letters of credit outstanding under our revolver and $17.6 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 September 30, 2011, we have restricted cash of $13.6 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. Except for the following, during the first nine months of 2011, there were no material changes outside the ordinary course of business in the specified contractual obligations.
    Net reduction of $13.8 million of surety bonds outstanding at December 31, 2010;
 
    Settled $6.0 million of insurance notes payable outstanding at December 31, 2010;
 
    Repaid $18.6 million of our term loan facility outstanding at December 31, 2010; and
 
    Financed $25.8 million related to the renewal of certain of our insurance policies.
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, as amended on Form 8-K filed July 8, 2011.
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;

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    expected completion times for our repair, refurbishment and upgrade projects, including the repair project for the Hercules 185;
 
    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, as amended on Form 8-K filed July 8, 2011, 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 and rising cost of labor;
 
    labor relations and work stoppages, particularly in the West African and Mexican labor environments;

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    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 September 30, 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, $89.2 million and $293.5 million, respectively.
     As of September 30, 2011, the interest rate for the $456.5 million outstanding under the term loan was 7.5%. If the interest rate averaged 1% more for 2011 than the rates as of September 30, 2011, annual interest expense would increase by approximately $4.6 million. This sensitivity analysis assumes there are no changes in our financial structure and excludes the impact of our interest rate derivatives, if any.
     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:
                                 
    September 30, 2011   December 31, 2010
    Carrying   Fair   Carrying   Fair
    Value   Value   Value   Value
            (in millions)        
Term Loan Facility, due July 2013
  $ 456.5     $ 436.8     $ 475.2     $ 443.7  
10.5% Senior Secured Notes, due October 2017
    293.5       287.8       292.9       245.1  
3.375% Convertible Senior Notes, due June 2038
    89.2       81.5       86.5       69.1  
7.375% Senior Notes, due April 2018
    3.5       2.9       3.5       2.2  

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Fair Value of Warrants and Derivative Asset
     At September 30, 2011, the fair value of derivative instruments was $2.0 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
  $ 1,185  
50% increase in stock price
    2,535  
10% increase in assumed volatility
    705  
25% decrease in stock price
    (950 )
50% decrease in stock price
    (1,605 )
10% decrease in assumed volatility
    (735 )
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.
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, as amended on Form 8-K filed July 8, 2011.
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

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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.
The continuing worldwide economic problems have materially reduced our revenue, profitability and cash flows.
     The worldwide economic problems that commenced in late 2008 led to a reduction in the availability of liquidity and credit to fund business operations worldwide, and adversely affected our customers, suppliers and lenders. The economic decline caused a reduction in worldwide demand for energy and resulted in lower oil and natural gas prices. While oil prices and, to a lesser extent, natural gas prices have recently rebounded, demand for our services depends on oil and natural gas industry activity and capital expenditure levels that are directly affected by trends in oil and natural gas prices. Any prolonged reduction in oil and natural gas prices will further depress the current levels of exploration, development and production activity. Perceptions of longer-term lower oil and natural gas prices by oil and gas companies can similarly reduce or defer major expenditures. Lower levels of activity result in a corresponding decline in the demand for our services, which could have a material adverse effect on our revenue and profitability.
Global financial and economic circumstances may have impacts on our business and financial condition that we currently cannot predict, and may limit our ability to finance our business and refinance our debt at a reasonable cost of capital.
     We may face challenges if conditions in the financial markets are inadequate to finance our activities and refinance our debt as it comes due at a reasonable cost of capital. Continuing concerns over the worldwide economic outlook, the availability and costs of credit, and the sovereign debt crisis have contributed to increased volatility in the global financial markets and commodity prices and diminished expectations for the global economy. These conditions could make it more difficult for us to access capital on reasonable terms and to refinance our debt at reasonable costs.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
     The following table sets forth for the periods indicated certain information with respect to our purchases of our Common Stock:
                                 
                    Total Number of     Maximum Number of  
    Total Number of             Shares Purchased as     Shares That May Yet  
    Shares Purchased     Average Price Paid     Part of a Publicly     Be Purchased Under  
Period   (1)     per Share     Announced Plan (2)     Plan (2)  
July 1-31, 2011
        $       N/A       N/A  
August 1-31, 2011
    431       3.31       N/A       N/A  
September 1-30, 2011
    735       4.23       N/A       N/A  
 
                             
Total
    1,166       3.89       N/A       N/A  
 
                             

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(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.
ITEM 6. EXHIBITS
     
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.
 
   
101.INS*
  XBRL Instance Document
 
   
101.SCH*
  XBRL Schema Document
 
   
101.CAL*
  XBRL Calculation Linkbase Document
 
   
101.LAB*
  XBRL Label Linkbase Document
 
   
101.PRE*
  XBRL Presentation Linkbase Document
Attached as Exhibit 101 to this report are documents formatted in XBRL (Extensible Business Reporting Language). Users of this data are advised pursuant to Rule 406T of Regulation S-T that the interactive data filed is deemed not filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, and otherwise not subject to liability under these sections. The financial information contained in the XBRL-related documents is “unaudited” or “unreviewed.”
 
*   Filed herewith

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SIGNATURES
     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
         
  HERCULES OFFSHORE, INC.
 
 
  By:   /s/ John T. Rynd    
    John T. Rynd   
    Chief Executive Officer and President
(Principal Executive Officer)
 
 
 
         
  By:   /s/ Stephen M. Butz    
    Stephen M. Butz   
    Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
 
 
 
         
  By:   /s/ Troy L. Carson    
    Troy L. Carson   
    Chief Accounting Officer
(Principal Accounting Officer)
 
 
 
Date: October 27, 2011

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