e10vq
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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, 2009
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   56-2542838
(State or other jurisdiction of   (I.R.S. Employer
incorporation or organization)   Identification No.)
     
9 Greenway Plaza, Suite 2200    
Houston, Texas   77046
(Address of principal executive offices)   (Zip Code)
(713) 350-5100
(Registrant’s telephone number, including area code)
 
     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES     þ     NO     o
     Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES      o     NO      o
     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
             
Large accelerated filer þ    Accelerated filer o    Non-accelerated filer o
(Do not check if a smaller reporting company)
  Smaller reporting company o 
     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES     o     NO      þ
     Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practicable date.
     
Common Stock, par value $0.01 per share   Outstanding as of October 26, 2009
    114,649,249
 
 


 

HERCULES OFFSHORE, INC.
INDEX
         
    Page No.
       
 
       
       
    3  
    4  
    5  
    6  
    7  
 
       
    24  
    43  
    44  
 
       
       
 
       
    44  
    44  
    48  
    48  
 
       
    49  
 EX-31.1
 EX-31.2
 EX-32.1

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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,  
    2009     2008  
    (Unaudited)     (As Adjusted)  
ASSETS
               
Current Assets:
               
Cash and Cash Equivalents
  $ 219,898     $ 106,455  
Restricted Cash
    3,657        
Accounts Receivable, Net of Allowance for Doubtful Accounts of $10,701 and $7,756 as of September 30, 2009 and December 31, 2008, respectively
    192,967       293,089  
Prepaids
    26,234       23,033  
Current Deferred Tax Asset
    18,766       17,379  
Assets Held for Sale
          39,623  
Other
    17,405       19,946  
 
           
 
    478,927       499,525  
Property and Equipment, Net
    1,975,534       2,049,030  
Other Assets, Net
    42,658       42,340  
 
           
 
  $ 2,497,119     $ 2,590,895  
 
           
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current Liabilities:
               
Short-term Debt and Current Portion of Long-term Debt
  $ 9,000     $ 11,455  
Insurance Note Payable
    14,838       11,126  
Accounts Payable
    68,472       99,823  
Accrued Liabilities
    78,968       83,424  
Interest Payable
    13,923       506  
Taxes Payable
    32,616       32,440  
Other Current Liabilities
    37,410       35,966  
 
           
 
    255,227       274,740  
Long-term Debt, Net of Current Portion
    942,727       1,015,764  
Other Liabilities
    27,435       35,529  
Deferred Income Taxes
    278,080       339,547  
Commitments and Contingencies
               
Stockholders’ Equity:
               
Common Stock, $0.01 Par Value; 200,000 Shares Authorized; 114,837 and 89,459 Shares Issued, Respectively; 113,334 and 87,976 Shares Outstanding, Respectively
    1,148       895  
Capital in Excess of Par Value
    1,912,175       1,785,462  
Treasury Stock, at Cost, 1,503 Shares and 1,483 Shares, Respectively
    (50,146 )     (50,081 )
Accumulated Other Comprehensive Loss
    (8,265 )     (14,932 )
Retained Deficit
    (861,262 )     (796,029 )
 
           
 
    993,650       925,315  
 
           
 
  $ 2,497,119     $ 2,590,895  
 
           
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     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
            (As Adjusted)             (As Adjusted)  
Revenues
  $ 159,262     $ 315,738     $ 566,444     $ 798,338  
Costs and Expenses:
                               
Operating Expenses
    123,358       180,978       388,699       470,138  
Impairment of Property and Equipment
                26,882        
Depreciation and Amortization
    51,802       50,256       151,739       141,150  
General and Administrative
    16,814       17,447       48,556       57,777  
 
                       
    191,974       248,681       615,876       669,065  
 
                       
Operating Income (Loss)
    (32,712 )     67,057       (49,432 )     129,273  
Other Income (Expense):
                               
Interest Expense
    (24,131 )     (16,807 )     (54,481 )     (47,985 )
Expense of Credit Agreement Fees
    (15,073 )           (15,073 )      
Gain on Early Retirement of Debt, Net
                13,747        
Other, Net
    70       543       2,760       2,818  
 
                       
Income (Loss) Before Income Taxes
    (71,846 )     50,793       (102,479 )     84,106  
Income Tax Benefit (Provision)
    24,876       (18,938 )     39,211       (30,988 )
 
                       
Income (Loss) from Continuing Operations
    (46,970 )     31,855       (63,268 )     53,118  
Loss from Discontinued Operation, Net of Taxes
    (1,290 )     (168 )     (1,965 )     (766 )
 
                       
Net Income (Loss)
  $ (48,260 )   $ 31,687     $ (65,233 )   $ 52,352  
 
                       
Basic Earnings (Loss) Per Share:
                               
Income (Loss) from Continuing Operations
  $ (0.48 )   $ 0.36     $ (0.69 )   $ 0.60  
Loss from Discontinued Operation
    (0.02 )           (0.02 )     (0.01 )
 
                       
Net Income (Loss)
  $ (0.50 )   $ 0.36     $ (0.71 )   $ 0.59  
 
                       
Diluted Earnings (Loss) Per Share:
                               
Income (Loss) from Continuing Operations
  $ (0.48 )   $ 0.36     $ (0.69 )   $ 0.60  
Loss from Discontinued Operation
    (0.02 )           (0.02 )     (0.01 )
 
                       
Net Income (Loss)
  $ (0.50 )   $ 0.36     $ (0.71 )   $ 0.59  
 
                       
Weighted Average Shares Outstanding:
                               
Basic
    97,159       87,950       91,298       88,478  
Diluted
    97,159       88,508       91,298       89,180  
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,  
            2009     2008  
                    (As Adjusted)  
Cash Flows from Operating Activities:
                       
Net Income (Loss)
          $ (65,233 )   $ 52,352  
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:
                       
Depreciation and Amortization
            151,739       141,168  
Stock-Based Compensation Expense
            6,208       10,382  
Deferred Income Taxes
            (64,535 )     11,239  
Provision for Doubtful Accounts Receivable
            4,468       364  
Amortization of Deferred Financing Fees
            2,851       2,882  
Amortization of Original Issue Discount
            3,196       2,598  
Non-Cash Loss on Derivatives
            5,554        
Gain on Insurance Settlement
            (8,700 )      
Gain on Disposal of Assets
            (58 )     (3,649 )
Expense of Credit Agreement Fees
            15,073        
Gain on Early Retirement of Debt, Net
            (13,747 )      
Impairment of Property and Equipment
            26,882        
Excess Tax Benefit from Stock-Based Arrangements
            (4,458 )     (5,469 )
(Increase) Decrease in Operating Assets -
                       
Accounts Receivable
            95,654       (119,893 )
Insurance Claims Receivable
            (553 )     (369 )
Prepaid Expenses and Other
            21,647       30,221  
Increase (Decrease) in Operating Liabilities -
                       
Accounts Payable
            (32,815 )     6,124  
Insurance Note Payable
            (19,612 )     (30,528 )
Other Current Liabilities
            4,192       21,246  
Tax Sharing Agreement Settlement
                (4,000 )
Other Liabilities
            (6,763 )     17,924  
 
                   
Net Cash Provided by Operating Activities
            120,990       132,592  
Cash Flows from Investing Activities:
                       
Acquisition of Assets
                  (320,839 )
Additions of Property and Equipment
            (71,395 )     (184,843 )
Deferred Drydocking Expenditures
            (13,719 )     (13,547 )
Proceeds from Sale of Marketable Securities
                  39,300  
Insurance Proceeds Received
            9,168       29,229  
Proceeds from Sale of Assets, Net
            23,305       14,584  
Increase in Restricted Cash
            (3,657 )      
 
                   
Net Cash Used in Investing Activities
            (56,298 )     (436,116 )
Cash Flows from Financing Activities:
                       
Short-term Debt Borrowings (Repayments), Net
            (2,455 )     686  
Long-term Debt Borrowings
                  350,000  
Long-term Debt Repayments
            (20,555 )     (106,720 )
Redemption of 3.375% Convertible Senior Notes
            (6,099 )      
Common Stock Issuance (Repurchase)
            83,344       (49,228 )
Proceeds from Exercise of Stock Options
                  5,127  
Excess Tax Benefit from Stock-Based Arrangements
            4,458       5,469  
Payment of Debt Issuance Costs
            (9,931 )     (8,085 )
Other
            (11 )      
 
                   
Net Cash Provided by Financing Activities
            48,751       197,249  
 
                   
Net Increase (Decrease) in Cash and Cash Equivalents
            113,443       (106,275 )
Cash and Cash Equivalents at Beginning of Period
            106,455       212,452  
 
                 
Cash and Cash Equivalents at End of Period
          $ 219,898     $ 106,177  
 
                   
The accompanying notes are an integral part of these financial statements.

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)
(Unaudited)
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
            (As Adjusted)             (As Adjusted)  
Net Income (Loss)
  $ (48,260 )   $ 31,687     $ (65,233 )   $ 52,352  
Other Comprehensive Income, Net of Taxes:
                               
Changes Related to Hedge Transactions
    5,085       2,028       6,667       354  
 
                       
Comprehensive Income (Loss)
  $ (43,175 )   $ 33,715     $ (58,566 )   $ 52,706  
 
                       
The accompanying notes are an integral part of these financial statements.

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
UNAUDITED
1. General
     Hercules Offshore, Inc. and its majority owned subsidiaries (the “Company”) provides shallow-water drilling and marine services to the oil and natural gas exploration and production industry in the U.S. Gulf of Mexico and international locations through its Domestic Offshore, International Offshore, Inland, Domestic Liftboats, International Liftboats and Delta Towing segments (See Note 11). At September 30, 2009, the Company owned a fleet of 30 jackup rigs, 17 barge rigs, three submersible rigs, one platform rig, a fleet of marine support vessels operated through Delta Towing, a wholly owned subsidiary, and 60 liftboat vessels and operated an additional five liftboat vessels owned by a third party. In addition, the Company owns four retired jackup rigs and nine retired inland barges, all located in the U.S. Gulf of Mexico, which are currently not expected to re-enter active service. The Company currently operates in nine countries on three continents.
     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, 2009, Consolidated Statements of Operations and Consolidated Statements of Comprehensive Income (Loss) for the three and nine months ended September 30, 2009 and 2008, and Consolidated Statements of Cash Flows for the nine months ended September 30, 2009 and 2008. Although the Company believes the disclosures in these financial statements are adequate to make the interim information presented not misleading, certain information relating to the Company’s organization and footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles have been condensed or omitted in this Form 10-Q pursuant to Securities and Exchange Commission rules and regulations. These financial statements should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2008 and the notes thereto included in the Company’s Annual Report on Form 10-K as amended on Form 8-K, filed September 23, 2009, to reflect changes to the Company’s accounting for convertible debt. The results of operations for the three and nine months ended September 30, 2009 are not necessarily indicative of the results expected for the full year.
     The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, the Company evaluates its estimates, including those related to bad debts, investments, intangible assets, property, plant and equipment, income taxes, insurance, employment benefits and contingent liabilities. The Company bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates.
     In January 2009, the Company entered into agreements with Mosvold Middle East Jackup I Ltd. and Mosvold Middle East Jackup II Ltd. whereby it would market, manage and operate two high-specification new-build jackup drilling rigs each with a maximum water depth of 300 feet. However, in October 2009, the agreements with Mosvold Middle East Jackup I Ltd. and Mosvold Middle East Jackup II Ltd. were terminated by mutual agreement due to uncertainties in the timing of the delivery of the rigs and disputes between the owner and builder of the rigs.
Recent Common Stock Offering
     In September 2009, the Company raised approximately $82.3 million in net proceeds from an underwritten public offering of 17,500,000 shares of its common stock. In addition, on October 9, 2009, the Company sold an additional 1,313,590 shares of its common stock pursuant to the partial exercise of the underwriters’ over-allotment option and raised an additional $6.3 million in net proceeds (See Note 14). In October 2009, the Company used 50% of the net proceeds from these sales of common stock to repay a portion of its outstanding indebtedness under its term loan facility, and may use some or all of the remaining proceeds to repay additional indebtedness.
Reclassifications
     Certain reclassifications have been made to conform prior year financial information to the current period presentation.

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED
Revenue Recognition
     Revenues generated from our contracts are recognized as services are performed. For certain contracts, the Company may receive lump-sum fees for the mobilization of equipment and personnel. Mobilization fees received and costs incurred to mobilize a rig from one market to another under contracts longer than one month are recognized as services are performed over the term of the related drilling contract. Amounts related to mobilization fees are summarized below (in thousands):
                                 
    Three Months Ended September 30,   Nine Months Ended September 30,
    2009   2008   2009   2008
Mobilization revenue deferred
  $ 130     $ 11,050     $ 12,130     $ 19,327  
Mobilization expense deferred
    671             2,014       3,398  
Mobilization revenue recognized
    4,371       3,111       12,520       9,287  
Mobilization expense recognized
    1,295       1,595       2,688       4,551  
     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.
Other Assets
     Other assets consist of drydocking costs for marine vessels, other intangible assets, deferred income taxes, deferred costs, financing fees, investments, deposits and other. Drydocking costs are capitalized at cost and amortized on the straight-line method over a period of 12 months. Drydocking costs, net of accumulated amortization, at September 30, 2009 and December 31, 2008, were $7.0 million and $6.5 million, respectively. Amortization expense for drydocking costs was $4.5 million and $4.9 million for the three months ended September 30, 2009 and 2008, respectively, and $13.1 million and $14.7 million for the nine months ended September 30, 2009 and 2008, respectively.
     Financing fees are deferred and amortized over the life of the applicable debt instrument. However, in the event of an early repayment of debt, the related unamortized deferred financing fees are expensed in connection with the repayment. Unamortized deferred financing fees at September 30, 2009 and December 31, 2008 were $8.8 million and $18.2 million, respectively. The amortization expense related to the deferred financing fees is included in Interest Expense on the Consolidated Statements of Operations. Amortization expense for financing fees was $0.8 million and $1.2 million for the three months ended September 30, 2009 and 2008, respectively, and $2.9 million for both the nine months ended September 30, 2009 and 2008. The Company recognized a pretax charge of $10.8 million, $7.0 million, net of tax, related to the write off of unamortized issuance costs in connection with the July 2009 Credit Amendment, as well as a pretax charge of $1.4 million, $0.9 million, net of tax, related to the write off of unamortized issuance costs related to its 3.375% Convertible Senior Notes in connection with the April 2009 debt repurchase and the June 2009 debt retirement (See Note 5).
Other Intangible Assets
     As of September 30, 2009 and December 31, 2008, the Company had certain international customer contracts with a carrying value of $2.9 million and $7.2 million, net of accumulated amortization of $14.7 million and $10.4 million, respectively, included in Other Assets, Net on the Consolidated Balance Sheets. The value of each contract is being amortized over its respective life.
     Amortization expense was $1.1 million and $1.9 million for the three months ended September 30, 2009 and 2008, respectively, and $4.3 million and $6.1 million for the nine months ended September 30, 2009 and 2008, respectively. Future estimated amortization expense for the carrying amount of these intangible assets as of September 30, 2009 is expected to be as follows (in thousands):
         
Remainder of 2009
  $ 650  
2010
    1,590  
2011
    658  
2012
     
2013
     

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED
Cash and Cash Equivalents and Marketable Securities
     Cash and cash equivalents include cash on hand, demand deposits with banks and all highly liquid investments with original maturities of three months or less. From time to time the Company may invest a portion of its available cash in marketable securities. Marketable securities are classified as available for sale and are stated at fair value on the Consolidated Balance Sheets. At September 30, 2009 and December 31, 2008, the Company had no investments in marketable securities.
     Realized and unrealized gains and losses related to marketable securities are calculated using the specific identification method. Unrealized gains or losses, net of taxes, are included in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets until realized. Realized gains or losses are included in Other, Net in the Consolidated Statements of Operations. Proceeds of $39.3 million were received from sales and maturities of marketable securities for the nine months ended September 30, 2008. There were no realized or unrealized gains or losses related to these securities in the three months nor the nine months ended September 30, 2009 and 2008.
Restricted Cash
     The Company has restricted cash of $3.7 million to support surety bonds primarily related to the Company’s Mexico operations. As of December 31, 2008, the Company had no restricted cash balances outstanding.
2. Earnings Per Share
     The reconciliation of the numerator and denominator used for the computation of basic and diluted earnings per share is as follows (in thousands):
                                 
    Three Months Ended September 30,   Nine Months Ended September 30,
    2009   2008   2009   2008
Denominator:
                               
Weighted average basic shares
    97,159       87,950       91,298       88,478  
Add effect of stock equivalents
          558             702  
 
                               
Weighted average diluted shares
    97,159       88,508       91,298       89,180  
 
                               
     The Company calculates basic earnings per share by dividing net income by the weighted average number of shares outstanding. Diluted earnings per share is computed by dividing net income by the weighted average number of shares outstanding during the period as adjusted for the dilutive effect of the Company’s stock option and restricted stock awards. The effect of stock option and restricted stock awards is not included in the computation for periods in which a net loss occurs, because to do so would be anti-dilutive. Stock equivalents of 4,817,059 and 4,510,640 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, 2009, respectively. Stock equivalents of 1,233,207 and 772,901 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, 2008, respectively.
3. Asset Acquisition
     In February 2008, the Company entered into a definitive agreement to purchase three jackup drilling rigs and related equipment for $320.0 million. The Company completed the purchase of the Hercules 350 and the Hercules 261 and related equipment during March 2008, while the purchase of the Hercules 262 and related equipment was completed in May 2008.
4. Dispositions and Assets Held for Sale
     In June 2009, the Company entered into an agreement to sell its Hercules 100 and Hercules 110 jackup drilling rigs for a total purchase price of $12.0 million. The Hercules 100 was classified as “retired” and was stacked in Sabine Pass, Texas, and the Hercules 110 was cold-stacked in Trinidad. The closing of the sale of the Hercules 100 and Hercules 110 occurred in August 2009 and the net proceeds of $11.8 million from the sale were used to repay a portion of the Company’s term loan facility. The Company realized approximately $26.9 million ($13.1 million, net of tax) of impairment charges related to the write-down of the Hercules 110 to fair value less costs to sell during the second quarter of 2009 (See Note 7). The financial information for the Hercules 100 has historically been reported as part of the Domestic Offshore Segment and the Hercules 110 financial information has been reported as part of the International Offshore Segment.
     During the second quarter of 2008, the Company sold Hercules 256 for gross proceeds of $8.5 million, which approximated the carrying value of this asset.

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED
     There were no assets held for sale as of September 30, 2009. Balance sheet information for the assets held for sale as of December 31, 2008 is as follows (in thousands):
         
    December 31,  
    2008  
Other
  $ 123  
Property and Equipment, Net
    39,500  
 
     
Current Assets Held for Sale
  $ 39,623  
 
     
5. Debt
     Debt is comprised of the following (in thousands):
                 
    September 30, 2009     December 31, 2008  
            (As Adjusted)  
Term Loan Facility, due July 2013
  $ 865,944     $ 886,500  
3.375% Convertible Senior Notes due June 2038
    82,271       134,752  
7.375% Senior Notes, due April 2018
    3,512       3,512  
Foreign Overdraft Facility
          2,455  
 
           
Total Debt
    951,727       1,027,219  
Less Short-term Debt and Current Portion of Long-term Debt
    9,000       11,455  
 
           
Total Long-term Debt, Net of Current Portion
  $ 942,727     $ 1,015,764  
 
           
Senior secured credit agreement
     In July 2007, the Company entered into a $1,050.0 million credit facility, consisting of a $900.0 million term loan facility and a $150.0 million revolving credit facility which is governed by the credit agreement (“Credit Agreement”). In connection with the Credit Agreement, the Company entered into derivative instruments with the purpose of hedging future interest payments (See Note 6). In April 2008, the Company entered into an agreement to increase the revolving credit facility to $250.0 million.
July 2009 Credit Amendment
     On July 27, 2009 the Company amended its Credit Agreement (“Credit Amendment”) in order to revise its covenants to be more favorable to the Company. A fee of 0.50%, which approximated $4.8 million, was paid to lenders consenting to the Credit Amendment based on their total commitment. The Credit Amendment reduced the revolving credit facility by $75.0 million to $175.0 million. The commitment fee on the revolving credit facility increased from 0.375% to 1.00%. The availability under the $175.0 million revolving credit facility must be used for working capital, capital expenditures and other general corporate purposes and cannot be used to prepay the term loan. Additionally, the Credit Amendment establishes a minimum London Interbank Offered Rate (“LIBOR”) rate of 2.00% and 3.00% with respect to the Company’s Alternative Base Rate (“ABR”) Loans and increases the

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED
margin applicable to Eurodollar Loans and ABR Loans, subject to a grid based on the aggregate principal amount of the term loans outstanding as follows ($ in millions):
                                 
Principal Amount Outstanding   Margin Applicable to:    
Less than or equal to:   Greater than:   Eurodollar Loans   ABR Loans
$ 882.00     $ 684.25       6.50 %     5.50 %  
 
  684.25       484.25       5.00 %     4.00 %  
 
  484.25             4.00 %     3.00 %  
 
     The Credit Amendment also modifies certain provisions of the Credit Agreement to, among other things:
    Eliminate the requirement that the Company comply with the total leverage ratio financial covenant for the nine month period commencing October 1, 2009 and ending on June 30, 2010 and amend the maximum total leverage ratio following the expiration of the nine month period to be more favorable to the Company;
 
    Require maintenance of a minimum level of liquidity, measured as the amount of unrestricted cash and cash equivalents on hand and availability under the revolving credit facility, of (i) $100.0 million for the period between October 1, 2009 through December 31, 2010, (ii) $75.0 million during calendar year 2011 and (iii) $50.0 million thereafter;
 
    Revise the fixed charge coverage ratio definition and reduce the minimum fixed charge coverage ratio that the Company must maintain in a manner that is more favorable to the Company;
 
    Require mandatory prepayments of debt outstanding under the Credit Agreement with 100% of excess cash flow for the fiscal year ending December 31, 2009 and 50% of excess cash flow thereafter and with proceeds from:
  §   unsecured debt issuances, with the exception of refinancing, through June 30, 2010;
 
  §   secured debt issuances;
 
  §   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 several of their vessels and substantially all of their other personal property.
     The Credit Agreement requires that the Company meet certain financial ratios and tests, which it met as of September 30, 2009. The Company’s failure to comply with such covenants would result in an event of default under the Credit Agreement. An event of default could prevent the Company from borrowing under the revolving credit facility, which would in turn have a material adverse effect on the Company’s available liquidity. Additionally, an event of default could result in the Company having to immediately repay all amounts outstanding under the Credit Agreement and in the foreclosure of liens on its assets.
     As of September 30, 2009, no amounts were outstanding and $10.0 million in standby letters of credit had been issued under the revolving credit facility. The remaining availability under this revolving credit facility was $165.0 million at September 30, 2009. As of September 30, 2009, $865.9 million was outstanding on the term loan facility and the interest rate was 8.5%. The annualized effective rate of interest was 6.54% for the nine months ended September 30, 2009 after giving consideration to revolver fees and derivative activities.
10.5% senior secured notes due 2017
     On October 20, 2009, the Company 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 (See Note 14). The interest on the notes will be payable in cash semi-annually in arrears on April 15 and October 15 of each year, commencing on April 15, 2010, 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 will be recorded at their discounted amount, with the discount to be amortized over the life of the notes. The Company used the net proceeds of approximately $284.4 from the offering to repay a portion of the indebtedness outstanding under its term loan facility.
     The notes will be 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 the Company’s secured indebtedness, other than these notes, does not exceed the lesser of $375.0 million and 15.0% of our 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 our secured indebtedness. If, after any such release of liens on collateral, the aggregate principal amount of the Company’s secured

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED
indebtedness, other than these notes, exceeds the greater of (a) $375.0 million and (b) 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.
     Prior to October 15, 2012, the Company may redeem the notes with the net cash proceeds of certain equity offerings, at a redemption price equal to 110.50% of the aggregate principal amount plus accrued and unpaid interest; provided, that (i) after giving effect to any such redemption, at least 65% of the notes originally issued would remain outstanding immediately after such redemption and (ii) the Company makes such redemption not more than 90 days after the consummation of such equity offering. In addition, prior to October 15, 2013, the Company may redeem all or part of the notes at a price equal to 100% of the aggregate principal amount of notes to be redeemed, plus the applicable premium and accrued and unpaid interest.
     On or after October 15, 2013, the Company may redeem the notes, in whole or part, at the redemption prices set forth below, together with accrued and unpaid interest to the redemption date.
         
Year   Optional Redemption Price
2013
    105.2500 %
2014
    102.6250 %
2015
    101.3125 %
2016 and thereafter
    100.0000 %
     If the Company experiences certain kinds of changes of control, it must offer to repurchase the notes at an offer price in cash equal to 101% of their principal amount, plus accrued and unpaid interest. Furthermore, following certain asset sales, the Company may be required to use the proceeds to offer to repurchase the notes at an offer price in cash equal to 100% of their principal amount, plus accrued and unpaid interest.
3.375% convertible senior notes due 2038
     As of January 1, 2009, the Company was required to adopt the provisions of Financial Accounting Standards Board (“FASB”) Codification Topic 470-20, Debt — Debt with Conversion and Other Options, with retrospective application to the terms of the 3.375% Convertible Senior Notes as they existed for all periods presented (See Note 13). The Consolidated Balance Sheet for December 31, 2008 has been restated to reflect the adoption, which resulted in a $30.1 million increase to Capital in Excess of Par Value, a $9.5 million increase to Deferred Income Taxes, a $27.0 million decrease to Long-term Debt and an increase to Retained Deficit of $12.6 million. The Consolidated Statements of Operations for the three and nine months ended September 30, 2008 have also been restated to reflect the adoption. The restatement of the Consolidated Statements of Operations for the three months ended September 30, 2008 resulted in the Company recognizing $2.0 million, $1.3 million, net of tax, in interest expense, or $0.01 per diluted share, related to discount amortization and $2.6 million, $1.5 million, net of tax, in interest expense, or $0.02 per diluted share, related to discount amortization for the nine months ended September 30, 2008.
     The carrying amount of the equity component of the 3.375% Convertible Senior Notes was $30.1 million at both September 30, 2009 and December 31, 2008. The principal amount of the liability component of the 3.375% Convertible Senior Notes, its unamortized discount and its net carrying amount was $95.9 million, $13.6 million and $82.3 million, respectively, as of September 30, 2009 and $161.8 million, $27.0 million and $134.8 million, respectively, as of December 31, 2008. The unamortized discount is being amortized to interest expense over the expected life of the 3.375% Convertible Senior Notes which ends June 3, 2013. During the three months ended September 30, 2009, the Company recognized $1.6 million, $1.1 million, net of tax, in interest expense, or $0.01 per diluted share, at an effective rate of 7.93%, of which $0.8 million related to the coupon rate of 3.375% and $0.8 million related to discount amortization. During the nine months ended September 30, 2009, the Company recognized $6.5 million, $4.3 million, net of tax, in interest expense, or $0.05 per diluted share, at an effective rate of 7.93%, of which $3.3 million related to the coupon rate of 3.375% and $3.2 million related to discount amortization.

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED
     Upon maturity or redemption, the Company determined it has the intent and ability to settle the principal amount of its 3.375% Convertible Senior Notes in cash, and any additional conversion consideration spread (the excess of conversion value over face value) in shares of the Company’s common stock (“Common Stock”).
     The notes will be convertible under certain circumstances into shares of the Company’s Common Stock at an initial conversion rate of 19.9695 shares of Common Stock per $1,000 principal amount of notes, which is equal to an initial conversion price of approximately $50.08 per share. Upon conversion of a note, a holder will receive, at the Company’s election, shares of Common Stock, cash or a combination of cash and shares of Common Stock. At September 30, 2009, the number of conversion shares potentially issuable in relation to the 3.375% Convertible Senior Notes was 1.9 million.
     In April 2009, the Company repurchased $20.0 million aggregate principal amount of the 3.375% Convertible Senior Notes for a cost of $6.1 million, resulting in a gain of $10.7 million. In addition, the Company expensed $0.4 million of unamortized issuance costs in connection with the retirement. In June 2009, the Company retired $45.8 million aggregate principal amount of its 3.375% Convertible Senior Notes in exchange for the issuance of 7,755,440 Common Stock valued at $4.38 per share and payment of accrued interest, resulting in a gain of $4.4 million. In addition, the Company expensed $1.0 million of unamortized issuance costs in connection with the retirement. The settlement consideration was allocated to the extinguishment of the liability component in an amount equal to the fair value of that component immediately prior to extinguishment, with the difference between this allocation and the net carrying amount of the liability component and unamortized debt issuance costs recognized as a gain or loss on debt extinguishment. If there would have been any remaining settlement consideration, it would have been allocated to the reacquisition of the equity component and recognized as a reduction of Stockholders’ Equity.
Other debt
     In connection with the TODCO acquisition in July 2007, one of our 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.
     The foreign overdraft facility, which was designed to manage local currency liquidity in Venezuela, was terminated in March 2009 and all outstanding amounts were repaid.
Fair value estimate
     The fair value of the Company’s 3.375% Convertible Senior Notes and term loan facility is estimated based on quoted prices in active markets. The Company believes the carrying value of its short-term debt instruments outstanding at December 31, 2008 approximate fair value. The following table provides the carrying value and fair value of the Company’s long-term debt instruments:
                                 
    September 30, 2009   December 31, 2008
    Carrying   Fair   Carrying   Fair
    Value   Value   Value   Value
            (in millions)        
Term Loan Facility, due July 2013
  $ 865.9     $ 844.3     $ 886.5     $ 571.8  
3.375% Convertible Senior Notes due June 2038
    82.3       71.6       134.8       77.2  
7.375% Senior Notes, due April 2018 (a)
    3.5       n/a       3.5       n/a  
 
(a)   The 7.375% Senior Notes have not been traded in recent periods and the Company believes that the fair value would not materially differ from the carrying value.
6. Derivative Instruments and Hedging
     The Company is required to recognize all of its derivative instruments as either assets or liabilities in the statement of financial position at fair value. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and further, on the type of hedging relationship. For those derivative instruments that are designated and qualify as hedging instruments, a company must designate the hedging instrument, based upon the exposure being hedged, as a fair value hedge, cash flow hedge, or a hedge of a net investment in a foreign operation.
     The Company periodically uses derivative instruments to manage its exposure to interest rate risk, including interest rate swap agreements to effectively fix the interest rate on variable rate debt and interest rate collars to limit the interest rate range on variable rate debt. These hedge transactions have historically been accounted for as cash flow hedges.

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED
     For derivative instruments that are designated and qualify as a cash flow hedge, the effective portion of the gain or loss on the derivative instrument is reported as a component of other comprehensive income and reclassified into earnings in the same line item associated with the forecasted transaction and in the period or periods during which the hedged transaction affects earnings. The effective portion of the interest rate swaps and collars hedging the exposure to variability in expected future cash flows due to changes in interest rates is reclassified into interest expense. The remaining gain or loss on the derivative instrument in excess of the cumulative change in the present value of future cash flows of the hedged item, if any, or hedged components excluded from the assessment of effectiveness, is recognized in Interest Expense in the Consolidated Statements of Operations during the current period.
     In May 2008 and July 2007, the Company entered into derivative instruments with the purpose of hedging future interest payments on its term loan facility. In May 2008, the Company entered into a floating to fixed interest rate swap with varying notional amounts beginning with $100.0 million with a settlement date of October 1, 2008 and ending with $75.0 million with a settlement date of December 31, 2009. The Company receives an interest rate of three-month LIBOR and pays a fixed coupon of 2.980% over six quarters. The terms and settlement dates of the swap match those of the term loan. In July 2007, the Company entered into a floating to fixed interest rate swap with decreasing notional amounts beginning with $400.0 million with a settlement date of December 31, 2007 and ending with $50.0 million which was settled on April 1, 2009. The Company received a payment equal to the product of three-month LIBOR and the notional amount and paid a fixed coupon of 5.307% on the notional amount over six quarters. The terms and settlement dates of the swap matched those of the term loan. In July 2007, the Company also entered into a zero cost LIBOR collar on $300.0 million of term loan principal with a final settlement date of October 1, 2010 with a ceiling of 5.75% and a floor of 4.99%. The counterparty is obligated to pay the Company in any quarter that actual LIBOR resets above 5.75% and the Company pays the counterparty in any quarter that actual LIBOR resets below 4.99%. The terms and settlement dates of the collar match those of the term loan.
     As a result of the inclusion of a LIBOR floor in the amended Credit Agreement, the Company does not believe, as of July 27, 2009 and on an ongoing basis, that the interest rate swaps and collars will be highly effective in achieving offsetting changes in cash flows attributable to the hedged interest rate risk during the period that the hedge was designated. As such, the Company has prospectively discontinued cash flow hedge accounting for the interest rate swaps and collars as of July 27, 2009 and will no longer apply cash flow hedge accounting to these instruments. Because cash flow hedge accounting will not be applied to these instruments, changes in fair value related to the interest rate swaps and collars subsequent to July 27, 2009 will be recorded in earnings on a go-forward basis. As a result of discontinuing the cash flow hedging relationship, the Company recognized a decrease in fair value of $1.2 million related to the interest rate swaps and collars as Interest Expense in its Consolidated Statement of Operations for the three and nine month periods ended September 30, 2009. The Company expects to realize all of the unrealized loss in the Consolidated Statements of Operations over the next twelve months.
     The following table provides the fair values of the Company’s interest rate derivatives (in thousands):
                     
September 30, 2009     December 31, 2008  
Balance Sheet   Fair     Balance Sheet   Fair  
Classification   Value     Classification   Value  
Derivatives(a):
                   
Interest rate contracts:
                   
Other
  $ 53     Other   $ 21  
 
               
Total Asset Derivatives
  $ 53     Total Asset Derivatives   $ 21  
 
               
Other Current Liabilities
  $ 15,286     Other Current Liabilities   $ 15,669  
Other Liabilities
    3,037     Other Liabilities     7,324  
 
               
Total Liability Derivatives
  $ 18,323     Total Liability Derivatives   $ 22,993  
 
               
 
(a)   These interest rate contracts were designated as cash flow hedges through July 27, 2009 at which point they became ineffective and are no longer designated as such.

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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 interest rate derivatives on the Consolidated Statements of Operations (in thousands):
                                                         
    I.       III.       V.
    Three Months       Three Months       Three Months
    Ended       Ended       Ended
    September 30,       September 30,       September 30,
Derivatives(a)   2009   2008   II.   2009   2008   IV.   2009   2008
Interest rate contracts
  $ 2,226     $ 65     Interest Expense   $ (4,398 )   $ (3,020 )   Interest Expense   $ (1,156 )   $  
                                                         
    I.       III.       V.
    Nine Months       Nine Months       Nine Months
    Ended       Ended       Ended
    September 30,       September 30,       September 30,
Derivatives(a)   2009   2008   II.   2009   2008   IV.   2009   2008
Interest rate contracts
  $ (1,654 )   $ (4,383 )   Interest Expense   $ (12,801 )   $ (7,287 )   Interest Expense   $ (1,156 )   $  
(a)   These interest rate contracts were designated as cash flow hedges through July 27, 2009 at which point they became ineffective and are no longer designated as such.
 
I.   Amount of Gain (Loss), Net of Taxes Recognized in Other Comprehensive Income on Derivative (Effective Portion)
 
II.   Classification of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion)
 
III.   Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion)
 
IV.   Classification of Gain (Loss) Recognized in Income on Derivative
 
V.   Amount of Gain (Loss) Recognized in Income on Derivative
A summary of the changes in Accumulated Other Comprehensive Loss (in thousands):
         
Cumulative unrealized loss, net of tax of $8,040, as of December 31, 2008
  $ (14,932 )
Reclassification of losses into net income, net of tax of $4,480
    8,321  
Other comprehensive losses, net of tax of $891
    (1,654 )
 
     
Cumulative unrealized loss, net of tax of $4,451, as of September 30, 2009
  $ (8,265 )
 
     
7. Fair Value Measurements
     FASB Codification Topic 820-10, Fair Value Measurements and Disclosures 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 our view of market assumptions in the absence of observable market information. The Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. FASB Codification Topic 820-10, Fair Value Measurements and Disclosures 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
The valuation techniques that may be used to measure fair value are as follows:
  (A)   Market approach — Uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities
 
  (B)   Income approach — Uses valuation techniques to convert future amounts to a single present amount based on current market expectations about those future amounts, including present value techniques, option-pricing models and excess earnings method
 
  (C)   Cost approach — Based on the amount that currently would be required to replace the service capacity of an asset (replacement cost)
     The following table represents our derivative assets and liabilities measured at fair value on a recurring basis as of September 30, 2009 (in thousands):
                                         
            Quoted Prices in            
    Total   Active Markets for            
    Fair Value   Identical Asset or   Significant Other   Significant    
    Measurement   Liability   Observable Inputs   Unobservable Inputs   Valuation
    September 30, 2009   (Level 1)   (Level 2)   (Level 3)   Technique
Derivative Assets
  $ 53     $     $ 53     $       A  
Derivative Liabilities
    18,323             18,323             A  
     The following table represents our assets measured at fair value on a non-recurring basis for which an impairment measurement was made as of September 30, 2009 (in thousands):
                                                 
            Quoted Prices in   Significant            
    Total   Active Markets for   Other   Significant        
    Fair Value   Identical Asset or   Observable   Unobservable        
    Measurement   Liability   Inputs   Inputs   Valuation   Total
    September 30, 2009   (Level 1)   (Level 2)   (Level 3)   Technique   Gain (Loss)
Assets Held for Sale
  $     $     $     $       A       $(26,882)  
     Long-lived assets held for sale at December 31, 2008 were written down to their fair value of $10.0 million, less cost to sell of $0.2 million (or net $9.8 million) in the second quarter of 2009, resulting in an impairment charge of approximately $26.9 million ($13.1 million, net of tax) related to the write-down of the Hercules 110 to fair value less cost to sell (See Note 4). The sale of the Hercules 110 was completed in August 2009 (See Note 4).
8. Stock-based Compensation
     The Company’s 2004 Long-Term Incentive Plan (the “2004 Plan”) provides for the granting of stock options, restricted stock, performance stock awards and other stock-based awards to selected employees and non-employee directors of the Company. At September 30, 2009, approximately 4.3 million shares were available for grant or award under the 2004 Plan.
     During the nine months ended September 30, 2009, the Company granted 1,788,125 stock options with a weighted average exercise price of $1.69 and 5,000 restricted stock awards with a weighted average grant-date fair value per share of $4.82.
     The Company recognized $2.1 million and $6.2 million in stock-based compensation expense during the three and nine months ended September 30, 2009, respectively, and $2.5 million and $10.4 million during the three and nine months ended September 30, 2008, respectively. The excess income tax benefit, the tax deduction that is in excess of the tax benefit recognized in the consolidated financial statements related to stock-based compensation, recognized for the three and nine months ended September 30, 2009 was $0.3 million and $4.5 million, respectively, and $0.1 million and $5.5 million for the three and nine months ended September 30, 2008, respectively.
     The unrecognized compensation cost related to the Company’s unvested stock options and restricted stock grants as of September 30, 2009 was $4.3 million and $5.6 million, respectively, and is expected to be recognized over a weighted-average period of 2.0 years and 1.0 years, respectively.

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED
9. Supplemental Cash Flow Information
     During the nine months ended September 30, 2009 and 2008, the Company had non-cash activities related to its interest rate derivatives of $6.7 million and $0.4 million, respectively. In addition, the Company had non-cash financing activities related to its June 2009 retirement of $45.8 million aggregate principal amount of its 3.375% Convertible Senior Notes in exchange for the issuance of 7,755,440 Common Stock valued at $4.38 per share ($34.0 million) and payment of accrued interest, resulting in a gain of $4.4 million (See Note 5).
                 
    Nine Months Ended September 30,
    2009   2008
    (In thousands)
Cash paid during the period for:
               
Interest, net of capitalized interest of $333 and $5,378, respectively
  $ 28,814     $ 25,441  
Income taxes
    19,565       39,785  
10. Income Tax
     In connection with the July 2007 acquisition of TODCO, the Company, as successor to TODCO, and TODCO’s former parent, Transocean Ltd., are parties to a tax sharing agreement that was originally entered into in connection with TODCO’s initial public offering in 2004. The tax sharing agreement was amended and restated in November 2006 in a negotiated settlement of disputes between Transocean and TODCO over the terms of the original tax sharing agreement. The tax sharing agreement continues to require that additional payments be made to Transocean based on a portion of the expected tax benefit from the exercise of certain compensatory stock options to acquire Transocean common stock attributable to current and former TODCO employees and board members. The estimated amount of payments to Transocean related to compensatory options that remain outstanding at September 30, 2009, assuming a Transocean stock price of $85.53 per share at the time of exercise of the compensatory options (the actual price of Transocean’s common stock at September 30, 2009), is approximately $1.3 million. The Company accounts for the exercise of Transocean stock options held by current and former TODCO employees and board members in the period in which such option is exercised. As tax deductions are generated from the exercise of the stock options the Company takes a current tax deduction for the value of the stock option tax deduction, pays Transocean for 55% of the value of the deduction and increases additional paid-in capital by 45% of the deduction. Because of the Company’s current NOL position, the tax benefit of the stock option deduction is reclassified as a reduction in net deferred tax liability. There is no certainty that the Company will realize future economic benefits from TODCO’s tax benefits equal to the amount of the payments required under the tax sharing agreement.
     The Company’s tax filings for various periods are subject to audit by the tax authorities in most jurisdictions where we conduct business. Internationally, income tax returns from 1998 through 2006 are currently under examination. In addition, several state examinations have commenced or will soon commence. The timing and effect on the Company’s consolidated financial statements of the resolution of these income tax examinations is highly uncertain due to various underlying factors. These factors include, among other things, the amount and nature of additional taxes potentially asserted by local tax authorities; the willingness of local tax authorities to negotiate a reasonable and appropriate settlement through an administrative process; and the impartiality of the local courts. The amounts ultimately paid, if any, upon the resolution of the issues raised by the tax authorities in any audit may differ materially from the amounts accrued for each year. While it is possible that some of these examinations may be resolved in the next 12 months, the Company cannot predict or provide assurance as to the ultimate outcome of existing or future tax assessments.
     In December 2002, TODCO received an assessment from SENIAT, the national Venezuelan tax authority, for approximately $20.7 million (based on the current exchange rates at the time of the assessment and inclusive of penalties) relating to calendar years 1998 through 2001. In March 2003, TODCO paid approximately $2.6 million of the assessment, plus approximately $0.3 million in interest, and we are contesting the remainder of the assessment with the Venezuelan Tax Court. After TODCO made the partial assessment payment, it received a revised assessment in September 2003 of approximately $16.7 million (based on the current exchange rates at the time of the assessment and inclusive of penalties). Thereafter, TODCO filed an administrative tax appeal with SENIAT and the tax authority rendered a decision that reduced the tax assessment to $8.1 million (based on the current exchange rates at the time of the decision). TODCO then initiated a judicial tax court appeal with the Venezuelan Tax Court to set aside the $8.1 million administrative tax assessment. In August 2008, the Venezuelan Tax Court ruled in favor of TODCO; however, SENIAT has the right to appeal this case to the Venezuelan Supreme Court. In July 2009, the Company settled the taxes and interest portion of the assessment for approximately 3.3 million Bolivares Fuertes, or approximately $1.5 million (based on the official exchange rate at the date of settlement). The Company is disputing any residual penalties which are currently assessed at 3.4 million Bolivares Fuertes, or $1.6 million (based on the official exchange rate at the date of assessment). The Company, as successor to TODCO, is fully indemnified by TODCO’s former parent, Transocean Ltd. related to this settlement. The Company does not expect the ultimate resolution of this tax assessment and settlement to have a material impact on its consolidated results of operations, financial condition

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED
or cash flows. In January 2008, SENIAT commenced an audit for the 2003 calendar year, which was completed in the fourth quarter of 2008. The Company has not yet received any proposed adjustments from SENIAT for that year.
     In March 2007, a subsidiary of the Company received an assessment from the Mexican tax authorities related to its operations for the 2004 tax year. This assessment contests the Company’s right to certain deductions and also claims it did not remit withholding tax due on certain of these deductions. The Company is pursuing its alternatives to resolve this assessment. In accordance with local statutory requirements, we have provided a surety bond for an amount equal to $13.0 million as of September 30, 2009, to contest these assessments. In 2008, the Mexican tax authorities commenced an audit for the 2005 tax year. Depending on the ultimate outcome of the 2004 assessment and the 2005 audit, the Company anticipates that the Mexican tax authorities could make similar assessments for other open tax years.
11. Segments
     The Company reports its business activities in six business segments: (1) Domestic Offshore, (2) International Offshore, (3) Inland, (4) Domestic Liftboats, (5) International Liftboats and (6) Delta Towing. The financial information of the Company’s discontinued operation is not included in the financial information presented for the Company’s reporting segments. The Company eliminates inter-segment revenue and expenses, if any.
     In January 2009, the Company reclassified four of its cold-stacked jackup rigs located in the U.S. Gulf of Mexico and 10 of its cold-stacked inland barges as retired. These rigs would require extensive refurbishment and currently are not expected to re-enter active service. In September 2009, the Company sold one of the retired inland barges. The following describes the Company’s reporting segments as of September 30, 2009:
     Domestic Offshore — includes 20 jackup rigs and three submersible rigs in the U.S. Gulf of Mexico that can drill in maximum water depths ranging from 85 to 350 feet. Eleven of the jackup rigs are either working on short-term contracts or available for contracts. Nine jackup rigs and all three submersibles are cold-stacked.
     International Offshore — includes 10 jackup rigs and one platform rig outside of the U.S. Gulf of Mexico. The Company has one jackup rig working offshore in each of Malaysia and Angola, as well as one jackup rig warm-stacked in each of Bahrain and Gabon. The Company has two jackup rigs working offshore in each of India and Saudi Arabia and two jackup rigs and one platform rig operating in Mexico. In August 2009, the company closed the sale of the Hercules 110 (See Note 4).
     Inland — includes a fleet of six conventional and 11 posted barge rigs that operate inland in marshes, rivers, lakes and shallow bay or coastal waterways along the U.S. Gulf Coast. Three of the Company’s inland barges are either operating on short-term contracts or available and 14 are cold-stacked.
     Domestic Liftboats — includes 41 liftboats in the U.S. Gulf of Mexico. Thirty-eight are operating in the U.S. Gulf of Mexico and three are cold-stacked. Four liftboats, which previously operated and were reported in the Domestic Liftboats segment during 2008 and through a significant portion of the nine months ended September 30, 2009, are now being managed by the International Liftboats segment pending their transfer to West Africa in October 2009.
     International Liftboats — includes 24 liftboats. Eighteen are operating offshore West Africa, including five liftboats owned by a third party. One liftboat is operating in the Middle East region and one liftboat is in the Middle East region available for contracts. In addition, four liftboats are being managed by the International Liftboats segment pending their transfer to West Africa in October 2009. These four liftboats are expected to be available for work between November 2009 and January 2010.
     Delta Towing — the Company’s Delta Towing business operates a fleet of 29 inland tugs, 12 offshore tugs, 34 crew boats, 46 deck barges, 17 shale barges and four spud barges along and in the U.S. Gulf of Mexico and along the Southeastern coast. As of September 30, 2009, 24 crew boats, 16 inland tugs and four offshore tugs were cold-stacked, and the remaining are working or available for contracts.
     The Company’s jackup rigs, submersible rigs and platform rigs are used primarily for exploration and development drilling in shallow waters. The Company’s liftboats are self-propelled, self-elevating vessels that support a broad range of offshore maintenance and construction services throughout the life of an oil or natural gas well.

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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, 2009     Nine Months Ended September 30, 2009  
            Income (Loss)                     Income (Loss)        
            from     Depreciation &             from     Depreciation &  
    Revenue     Operations     Amortization     Revenue     Operations     Amortization  
Domestic Offshore
  $ 18,959     $ (35,250 )   $ 15,118     $ 115,110     $ (67,370 )   $ 45,250  
International Offshore (a)
    90,041       26,746       16,769       295,250       86,806       48,702  
Inland
    2,437       (13,531 )     8,166       15,446       (47,147 )     24,442  
Domestic Liftboats
    19,268       956       5,048       60,762       4,187       15,844  
International Liftboats
    22,320       2,574       4,010       61,709       17,812       8,672  
Delta Towing
    6,237       (3,922 )     1,892       18,167       (11,244 )     6,318  
 
                                   
 
    159,262       (22,427 )     51,003       566,444       (16,956 )     149,228  
Corporate
          (10,285 )     799             (32,476 )     2,511  
 
                                   
Total Company
  $ 159,262     $ (32,712 )   $ 51,802     $ 566,444     $ (49,432 )   $ 151,739  
 
                                   
 
(a)   Income (Loss) from Operations for the Company’s International Offshore Segment includes a $26.9 million impairment of property and equipment charge for the nine months ended September 30, 2009.
                                                 
    Three Months Ended September 30, 2008     Nine Months Ended September 30, 2008  
            Income (Loss)                     Income (Loss)        
            from     Depreciation &             from     Depreciation &  
    Revenue     Operations     Amortization     Revenue     Operations     Amortization  
Domestic Offshore
  $ 112,733     $ 31,334     $ 17,546     $ 272,618     $ 53,021     $ 49,085  
International Offshore
    95,283       34,213       9,498       234,813       95,987       26,394  
Inland
    44,436       (1,229 )     11,350       124,966       (6,083 )     31,530  
Domestic Liftboats
    25,351       5,828       5,135       63,564       4,250       16,469  
International Liftboats
    20,323       5,054       3,143       58,919       19,954       7,495  
Delta Towing
    17,612       4,459       2,782       43,458       6,420       8,057  
 
                                   
 
    315,738       79,659       49,454       798,338       173,549       139,030  
Corporate
          (12,602 )     802             (44,276 )     2,120  
 
                                   
Total Company
  $ 315,738     $ 67,057     $ 50,256     $ 798,338     $ 129,273     $ 141,150  
 
                                   
                 
    Total Assets  
    September 30,     December 31,  
    2009     2008  
Domestic Offshore
  $ 831,574     $ 930,988  
International Offshore
    1,010,583       955,911  
Inland
    166,609       217,477  
Domestic Liftboats
    97,526       148,307  
International Liftboats
    164,524       168,356  
Delta Towing
    63,689       92,371  
Corporate
    162,614       77,485  
 
           
Total Company
  $ 2,497,119     $ 2,590,895  
 
           

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED
12. Commitments and Contingencies
Legal Proceedings
     The Company is involved in various claims and lawsuits in the normal course of business. As of September 30, 2009, management did not believe any accruals were necessary in accordance with FASB Codification Topic 450-20, Contingencies — Loss Contingencies.
     In connection with the July 2007 acquisition of TODCO, the Company assumed certain material legal proceedings from TODCO and its subsidiaries.
     In October 2001, TODCO was notified by the U.S. Environmental Protection Agency (“EPA”) that the EPA had identified a subsidiary of TODCO as a potentially responsible party under CERCLA in connection with the Palmer Barge Line superfund site located in Port Arthur, Jefferson County, Texas. Based upon the information provided by the EPA and the Company’s review of its internal records to date, the Company disputes the Company’s designation as a potentially responsible party and does not expect that the ultimate outcome of this case will have a material adverse effect on our consolidated results of operations, financial position or cash flows. The Company continues to monitor this matter.
     Robert E. Aaron et al. vs. Phillips 66 Company et al. Circuit Court, Second Judicial District, Jones County, Mississippi. This is the case name used to refer to several cases that have been filed in the Circuit Courts of the State of Mississippi involving 768 persons that allege personal injury or whose heirs claim their deaths arose out of asbestos exposure in the course of their employment by the defendants between 1965 and 2002. The complaints name as defendants, among others, certain of TODCO’s subsidiaries and certain subsidiaries of TODCO’s former parent to whom TODCO may owe indemnity, and other unaffiliated defendant companies, including companies that allegedly manufactured drilling-related products containing asbestos that are the subject of the complaints. The number of unaffiliated defendant companies involved in each complaint ranges from approximately 20 to 70. The complaints allege that the defendant drilling contractors used asbestos-containing products in offshore drilling operations, land based drilling operations and in drilling structures, drilling rigs, vessels and other equipment and assert claims based on, among other things, negligence and strict liability, and claims authorized under the Jones Act. The plaintiffs seek, among other things, awards of unspecified compensatory and punitive damages. All of these cases were assigned to a special master who has approved a form of questionnaire to be completed by plaintiffs so that claims made would be properly served against specific defendants. As of the date of this report, approximately 700 questionnaires were returned and the remaining plaintiffs, who did not submit a questionnaire reply, have had their suits dismissed without prejudice. Of the respondents, approximately 100 shared periods of employment by TODCO and its former parent which could lead to claims against either company, even though many of these plaintiffs did not state in their questionnaire answers that the employment actually involved exposure to asbestos. After providing the questionnaire, each plaintiff was further required to file a separate and individual amended complaint naming only those defendants against whom they had a direct claim as identified in the questionnaire answers. Defendants not identified in the amended complaints were dismissed from the plaintiffs’ litigation. To date, three plaintiffs named TODCO as a defendant in their amended complaints. It is possible that some of the plaintiffs who have filed amended complaints and have not named TODCO as a defendant may attempt to add TODCO as a defendant in the future when case discovery begins and greater attention is given to each individual plaintiff’s employment background. The Company continues to monitor a small group of these other cases. The Company has not determined which entity would be responsible for such claims under the Master Separation Agreement between TODCO and its former parent. The Company intends to defend vigorously and, based on the limited information available at this time, does not expect the ultimate outcome of these lawsuits to have a material adverse effect on its consolidated results of operations, financial position or cash flows.
     The Company and its subsidiaries are involved in a number of other lawsuits, all of which have arisen in the ordinary course of business. The Company does not believe that ultimate liability, if any, resulting from any such other pending litigation will have a material adverse effect on its business or consolidated financial position.
     The Company cannot predict with certainty the outcome or effect of any of the litigation matters specifically described above or of any other pending litigation. There can be no assurance that the Company’s belief or expectations as to the outcome or effect of any lawsuit or other litigation matter will prove correct, and the eventual outcome of these matters could materially differ from management’s current estimates.
Insurance
     The Company is self-insured for the deductible portion of its insurance coverage. Management believes adequate accruals have been made on known and estimated exposures up to the deductible portion of the Company’s insurance coverage. Management believes that claims and liabilities in excess of the amounts accrued are adequately insured. However, our insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect us against liability from all potential consequences.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED
     The Company maintains insurance coverage that includes coverage for physical damage, third party liability, workers’ compensation and employers’ liability, general liability, vessel pollution and other coverages.
     In May 2009, the Company completed the renewal of all of its key insurance policies. The Company’s primary marine package provides for hull and machinery coverage for the Company’s rigs and liftboats up to a scheduled value for each asset. The maximum coverage for these assets is $2.2 billion; however, coverage for U.S. Gulf of Mexico named windstorm damage is subject to an annual aggregate limit on liability of $100.0 million. The policies are subject to exclusions, limitations, deductibles, self-insured retention and other conditions. Deductibles for events that are not U.S. Gulf of Mexico named windstorm events are 12.5% of insured values per occurrence for drilling rigs, and $1.0 million per occurrence for liftboats, regardless of the insured value of the particular vessel. The deductibles for drilling rigs and liftboats in a U.S. Gulf of Mexico named windstorm event are the greater of $25.0 million or the operational deductible for each U.S. Gulf of Mexico named windstorm. The Company is self-insured for 15% above the deductibles for removal of wreck, sue and labor, collision, protection and indemnity general liability and hull and physical damage policies. The protection and indemnity coverage under the primary marine package has a $5.0 million limit per occurrence with excess liability coverage up to $200.0 million. The primary marine package also provides coverage for cargo and charterer’s legal liability. Vessel pollution is covered under a Water Quality Insurance Syndicate policy with a $3 million deductible proving limits as required. In addition to the marine package, the Company has separate policies providing coverage for onshore general liability, employer’s liability, auto liability and non-owned aircraft liability, with customary deductibles and coverage as well as a separate primary marine package for its Delta Towing business.
     In 2009, in connection with the renewal of certain of its insurance policies, the Company entered into agreements to finance a portion of its annual insurance premiums. Approximately $23.3 million was financed through these arrangements, and $14.8 million was outstanding at September 30, 2009. The interest rate on the $21.4 million note is 4.15% and the note is scheduled to mature in March 2010. The interest rate on the $1.9 million note is 3.75% and it is scheduled to mature in July 2010. The amounts financed in connection with the prior year renewal were fully paid as of March 31, 2009.
Surety Bonds and Unsecured Letters of Credit
     The Company has $36.9 million outstanding related to surety bonds at September 30, 2009. The surety bonds guarantee our performance as it relates to the Company’s drilling contracts, insurance, tax and other obligations in various jurisdictions. These obligations could be called at any time prior to the expiration dates. The obligations that are the subject of the surety bonds are geographically concentrated primarily in Mexico.
     The Company had $0.1 million in an unsecured letter of credit outstanding at September 30, 2009.
13. Accounting Pronouncements
     In June 2009, the FASB issued SFAS No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, a replacement of FASB Statement No. 162 (“SFAS No. 168”). SFAS No. 168 modifies the Generally Accepted Accounting Principles (“GAAP”) hierarchy by establishing only two levels of GAAP, authoritative and nonauthoritative accounting literature. Effective July 2009, the FASB Accounting Standards Codification (“ASC”), also know collectively as the “Codification” is considered the single source of authoritative U.S. accounting and reporting standards, excepts for additional authoritative rules and interpretive releases issued by the SEC. Nonauthoritative guidance and literature would include, among other things, FASB Concepts Statements, American Institute of Certified Public Accountants Issue Papers and Technical Practice Aids and accounting textbooks. The Codification was developed to organize GAAP pronouncements by topic so that users can more easily access authoritative accounting guidance. It is organized by topic, subtopic, section, and paragraph, each of which is identified by a numerical designation. This statement is effective for financial statements issued for interim and annual periods ending after September 15, 2009. Accordingly, accounting references have been updated.
     In August 2009, the FASB issued Accounting Standards Update (“ASU”) No. 2009-05, Fair Value Measurements and Disclosures (Topic 820) Measuring Liabilities at Fair Value (“ASU No. 2009-5”), which amends Subtopic 820-10, Fair Value Measurements and Disclosures-Overall for the fair value measurement of liabilities. ASU No. 2009-5 provides clarification that in circumstances in which a quoted price in an active market for the identical liability is not available, a reporting entity is required to measure fair value using one or more of the following techniques: (1) a valuation technique that uses the quoted price of the identical liability or similar liabilities when traded as assets; or (2) another valuation technique that is consistent with the principles of Topic 820, such as a present value technique or market approach. ASU No. 2009-5 is effective for the first reporting period after issuance. Accordingly, the Company adopted ASU No. 2009-5 in the third quarter 2009 with no impact to its financial statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED
     In May 2009, the FASB issued SFAS No. 165, Subsequent Events (“SFAS No. 165”), which was primarily codified into Topic 855, Subsequent Events in the ASC. SFAS No. 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date, but before financial statements are issued or are available to be issued. SFAS No. 165 requires disclosure of the date through which an entity has evaluated subsequent events and the basis for that date. This statement is effective for interim or annual financial periods ending after June 15, 2009. Accordingly, the Company adopted SFAS No. 165 in June 2009 with no impact to its financial statements.
     In April 2009, the FASB issued FSP No. FAS 107-1 and APB 28-1 Interim Disclosures about Fair Value of Financial Instruments (“FSP 107-1”), which was primarily codified into Topic 825, Financial Instruments in the ASC. This FSP extends the disclosure requirements of SFAS No. 107, Disclosures about Fair Value of Financial Instruments (“SFAS No. 107”), to interim financial statements of publicly traded companies as defined in APB Opinion No. 28, Interim Financial reporting.
     In April 2009, the FASB issued FSP No. FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset and Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly (“FSP 157-4”) which was primarily codified into Topic 820, Fair Value Measurements and Disclosures in the ASC. This FSP provides additional guidance on estimating fair value when the volume and level of transaction activity for an asset or liability have significantly decreased in relation to normal market activity for the asset or liability. The FSP also provides additional guidance on circumstances that may indicate that a transaction is not orderly. This statement is effective for interim or annual financial periods ending after June 15, 2009. Accordingly, the Company adopted FSP 157-4 in June 2009 with no impact to its financial statements (See Note 7).
     In May 2008, the FASB issued FSP 14-1, which was primarily codified into Topic 470-20, Debt — Debt with Conversion and Other Options in the ASC. FSP 14-1 clarifies the accounting for convertible debt instruments that may be settled in cash (including partial cash settlement) upon conversion. FSP 14-1 requires issuers to account separately for the liability and equity components of certain convertible debt instruments in a manner that reflects the issuer’s nonconvertible debt (unsecured debt) borrowing rate when interest cost is recognized. FSP 14-1 requires bifurcation of a component of the debt, classification of that component in equity and the accretion of the resulting discount on the debt to be recognized as part of interest expense in the Company’s consolidated statement of operations. The interest rate to be used under FSP 14-1 will therefore be significantly higher than the rate on the Company’s Convertible Senior Notes due 2038 that was previously used, which was equal to the coupon rate of 3.375 percent. As of January 1, 2009, the Company adopted FSP 14-1 with retrospective application to the terms of instruments as they existed for all periods presented (See Note 5).
     In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities (“SFAS No. 161”), which was primarily codified into Topic 815, Derivatives and Hedging in the ASC. SFAS No. 161 amends SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS No. 133”) requiring enhanced disclosures about an entity’s derivative and hedging activities, thereby improving the transparency of financial reporting. SFAS No. 161’s disclosures provide additional information on how and why derivative instruments are being used. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. Accordingly, the Company adopted SFAS No. 161 as of January 1, 2009 (See Note 6).
     In January 2008, the Company adopted, without material impact to its consolidated financial statements, the provisions of SFAS No. 157, which was primarily codified into Topic 820, Fair Value Measurements and Disclosures in the ASC, related to financial assets and liabilities and to nonfinancial assets and liabilities measured at fair value on a recurring basis. SFAS No. 157 defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements, rather, its application is made pursuant to other accounting pronouncements that require or permit fair value measurements. In February 2008, the FASB issued FSP SFAS No. 157-2, Effective Date of FASB Statement No. 157, primarily codified into Topic 820, Fair Value Measurements and Disclosures in the ASC, which defers the effective date of SFAS No. 157 for one year for certain nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. Effective January 1, 2009, the Company adopted, without material impact on its consolidated financial statements, the provision for nonfinancial assets and liabilities that are not required or permitted to be measured at fair value on a recurring basis, which include those measured at fair value in impairment testing and those initially measured at fair value in a business combination.
14. Subsequent Events
     The Company evaluated all events or transactions that occurred after September 30, 2009 up through October 29, 2009, the date the Company issued these financial statements. During this period the Company did not have any material recognizable subsequent events. However, the Company did have nonrecognizable subsequent events related to the following:
    In September 2009, the Company sold 17,500,000 shares of its common stock in a public offering (See Note 1). On October 9, 2009, the Company sold an additional 1,313,590 shares of its common stock pursuant to the partial exercise of the underwriters’ over-allotment option and raised an additional $6.3 million in net proceeds (See Note 1). The Company used

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
UNAUDITED
      50% of the net proceeds from these sales of common stock to repay a portion of its outstanding indebtedness under its term loan facility, and may use some or all of the remaining proceeds to repay additional indebtedness.
 
    In October 2009, the Company sold $300.0 million of Senior Secured Notes due 2017 through a private placement, which will bear interest at a rate of 10.5% per annum. The notes were sold at 97.383% of their face amount to yield 11.0%. The Company used the net proceeds from the offering to repay a portion of the indebtedness outstanding under its term loan facility (See Note 5).
 
    Subsequent to September 30, 2009, the Company made the following payments on its term loan facility:
  (i)   the Company used the net proceeds from the partial exercise of the underwriters’ over-allotment option and the Senior Secured Notes due 2017, which approximated $287.5 million, to repay a portion of the outstanding balance on the Company’s term loan facility; and
 
  (ii)   the Company utilized approximately $94.3 million of cash on hand which is reflected in the Company’s September 30, 2009 Balance Sheet, to repay a portion of the outstanding balance on the Company’s term loan facility.
    As of October 29, 2009, the balance outstanding under the Company’s term loan facility totaled $484.1 million, which reduces the margin applicable to the Company’s outstanding term loan facility borrowings under Eurodollar Loans from 6.50% to 4.00% and under ABR Loans from 5.50% to 3.00%.

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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, 2009 and for the three and nine months ended September 30, 2009 and September 30, 2008, included elsewhere herein, and with our Annual Report on Form 10-K for the year ended December 31, 2008, as amended on Form 8-K, filed September 23, 2009. The following information contains forward-looking statements. Please read “Forward-Looking Statements” below for a discussion of certain limitations inherent in such statements. Please also read “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2008, Item 1A of Part II of our quarterly report on Form 10-Q for the quarter ended June 30, 2009 and Item 1A of Part II of this quarterly report for a discussion of certain risks facing our company.
OVERVIEW
          We provide shallow-water drilling and marine services to the oil and natural gas exploration and production industry in the U.S. Gulf of Mexico and internationally. We provide these services to major integrated energy companies, independent oil and natural gas operators and national oil companies.
          We operate our business as six divisions: (1) Domestic Offshore, (2) International Offshore, (3) Inland, (4) Domestic Liftboats, (5) International Liftboats, and (6) Delta Towing. Previously, we reported an “Other” segment that included Delta Towing and certain land rigs. The land rigs were sold in December 2007, and the results of the land rig operations are included in Discontinued Operation.
          As of October 27, 2009, our business segments included the following:
          Domestic Offshore — includes 20 jackup rigs and three submersible rigs in the U.S. Gulf of Mexico that can drill in maximum water depths ranging from 85 to 350 feet. Eleven of the jackup rigs are either working on short-term contracts or available for contracts. Nine jackup rigs and all three submersibles are cold-stacked.
          International Offshore — includes 10 jackup rigs and one platform rig outside of the U.S. Gulf of Mexico. We have one jackup rig working offshore in each of Malaysia and Angola as well as one jackup rig warm-stacked in each of Bahrain and Gabon. We have two jackup rigs working offshore in each of India and Saudi Arabia. We have one jackup rig and one platform rig operating and one jackup rig ready-stacked in Mexico. In August 2009, we closed the sale of the Hercules 110 which was cold-stacked in Trinidad.
          Inland — includes a fleet of six conventional and 11 posted barge rigs that operate inland in marshes, rivers, lakes and shallow bay or coastal waterways along the U.S. Gulf Coast. Three of our inland barges are either operating on short-term contracts or available and 14 are cold-stacked.
          Domestic Liftboats — includes 41 liftboats in the U.S. Gulf of Mexico. Thirty-eight are operating in the U.S. Gulf of Mexico and three are cold-stacked. Four liftboats are mobilizing from the U.S. Gulf of Mexico to West Africa in October 2009.
          International Liftboats — includes 24 liftboats. Eighteen are operating offshore West Africa, including five liftboats owned by a third party. Two liftboats are operating in the Middle East region. Four liftboats are mobilizing from the U.S. Gulf of Mexico to West Africa in October 2009. These four liftboats are expected to be available for work between November 2009 and January 2010.
          Delta Towing — our Delta Towing business operates a fleet of 29 inland tugs, 12 offshore tugs, 34 crew boats, 46 deck barges, 17 shale barges and four spud barges along and in the U.S. Gulf of Mexico and along the Southeastern coast. In addition, 22 crew boats, 16 inland tugs and five offshore tugs are cold-stacked, and the remaining are working or available for contracts.
          In January 2009, we entered into agreements with Mosvold Middle East Jackup I Ltd. and Mosvold Middle East Jackup II Ltd. whereby we would market, manage and operate two high-specification new-build jackup drilling rigs each with a maximum water depth of 300 feet. However, in October 2009, the agreements with Mosvold Middle East Jackup I Ltd. and Mosvold Middle East Jackup II Ltd. were terminated by mutual agreement due to uncertainties in the timing of the delivery of the rigs and disputes between the owner and builder of the rigs.

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          In January 2009, we reclassified four of our cold-stacked jackup rigs located in the U.S. Gulf of Mexico and 10 of our cold-stacked inland barges as retired. These rigs would require extensive refurbishment and currently are not expected to re-enter active service. In September 2009, the Company sold one of the retired inland barges.
          Our jackup and submersible rigs and our barge rigs are used primarily for exploration and development drilling in shallow waters. Under most of our contracts, we are paid a fixed daily rental rate called a “dayrate,” and we are required to pay all costs associated with our own crews as well as the upkeep and insurance of the rig and equipment.
          Our liftboats are self-propelled, self-elevating vessels that support a broad range of offshore support services, including platform maintenance, platform construction, well intervention and decommissioning services throughout the life of an oil or natural gas well. Under most of our liftboat contracts, we are paid a fixed dayrate for the rental of the vessel, which typically includes the costs of a small crew of four to eight employees, and we also receive a variable rate for reimbursement of other operating costs such as catering, fuel, rental equipment and other items.
          Our revenues are affected primarily by dayrates, fleet utilization, the number and type of units in our fleet and mobilization fees received from our customers. Utilization and dayrates, in turn, are influenced principally by the demand for rig and liftboat services from the exploration and production sectors of the oil and natural gas industry. Our contracts in the U.S. Gulf of Mexico tend to be short-term in nature and are heavily influenced by changes in the supply of units relative to the fluctuating expenditures for both drilling and production activity. Our international drilling contracts and some of our liftboat contracts in West Africa are longer-term in nature.
          Our backlog at October 27, 2009 totaled approximately $538.9 million for our executed contracts. Approximately $82.1 million of this backlog is expected to be realized during the remainder of 2009. We calculate our backlog, or future contracted revenue, as the contract dayrate multiplied by the number of days remaining on the contract, assuming full utilization. Backlog excludes revenues for mobilization, demobilization, contract preparation and customer reimbursables. The amount of actual revenues earned and the actual periods during which revenues are earned will be different than the backlog disclosed or expected due to various factors. Downtime due to various operational factors, including unscheduled repairs, maintenance, weather and other factors (some of which are beyond our control), may result in lower dayrates than the full contractual operating dayrate. In some of the contracts, our customer has the right to terminate the contract without penalty and in certain instances, with little or no notice.
          Our operating costs are primarily a function of fleet configuration and utilization levels. The most significant direct operating costs for our Domestic Offshore, International Offshore and Inland segments are wages paid to crews, maintenance and repairs to the rigs, and insurance. These costs do not vary significantly whether the rig is operating under contract or idle, unless we believe that the rig is unlikely to work for a prolonged period of time, in which case we may decide to “cold-stack” or “warm-stack” the rig. Cold-stacking is a common term used to describe a rig that is expected to be idle for a protracted period and typically for which routine maintenance is suspended and the crews are either redeployed or laid-off. When a rig is cold-stacked, operating expenses for the rig are significantly reduced because the crew is smaller and maintenance activities are suspended. Placing rigs in service that have been cold-stacked typically requires a lengthy reactivation project that can involve significant expenditures and potentially additional regulatory review, particularly if the rig has been cold-stacked for a long period of time. Warm-stacking is a term used for a rig expected to be idle for a period of time that is not as prolonged as is the case with a cold-stacked rig. Maintenance is continued for warm-stacked rigs. Crews are reduced but a small crew is retained. Warm-stacked rigs generally can be reactivated in three to four weeks.
          The most significant costs for our Domestic Liftboats and International Liftboats segments are the wages paid to crews and the amortization of regulatory drydocking costs. Unlike our Domestic Offshore, International Offshore and Inland segments, a significant portion of the expenses incurred with operating each liftboat are paid for or reimbursed by the customer under contractual terms and prices. This includes catering, fuel, oil, rental equipment, crane overtime and other items. We record reimbursements from customers as revenues and the related expenses as operating costs. Our liftboats are required to undergo regulatory inspections every year and to be drydocked two times every five years; the drydocking expenses and length of time in drydock vary depending on the condition of the vessel. All costs associated with regulatory inspections, including related drydocking costs, are deferred and amortized over a period of twelve months.

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RESULTS OF OPERATIONS
          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,  
    2009     2008     2009     2008  
            (Dollars in thousands)          
            (As Adjusted)             (As Adjusted)  
Domestic Offshore:
                               
Number of rigs (as of end of period) (a)
    23       27       23       27  
Revenues
  $ 18,959     $ 112,733     $ 115,110     $ 272,618  
Operating expenses
    36,476       62,849       131,635       166,896  
Depreciation and amortization expense
    15,118       17,546       45,250       49,085  
General and administrative expenses
    2,615       1,004       5,595       3,616  
 
                       
Operating income (loss)
  $ (35,250 )   $ 31,334     $ (67,370 )   $ 53,021  
 
                       
International Offshore:
                               
Number of rigs (as of end of period) (b)
    11       12       11       12  
Revenues
  $ 90,041     $ 95,283     $ 295,250     $ 234,813  
Operating expenses
    44,209       50,518       127,478       110,618  
Impairment of property and equipment
                26,882        
Depreciation and amortization expense
    16,769       9,498       48,702       26,394  
General and administrative expenses
    2,317       1,054       5,382       1,814  
 
                       
Operating income
  $ 26,746     $ 34,213     $ 86,806     $ 95,987  
 
                       
Inland:
                               
Number of barges (as of end of period) (a)
    17       27       17       27  
Revenues
  $ 2,437     $ 44,436     $ 15,446     $ 124,966  
Operating expenses
    7,442       33,437       36,563       96,669  
Depreciation and amortization expense
    8,166       11,350       24,442       31,530  
General and administrative expenses
    360       878       1,588       2,850  
 
                       
Operating loss
  $ (13,531 )   $ (1,229 )   $ (47,147 )   $ (6,083 )
 
                       
Domestic Liftboats:
                               
Number of liftboats (as of end of period) (c)
    41       45       41       45  
Revenues
  $ 19,268     $ 25,351     $ 60,762     $ 63,564  
Operating expenses
    12,725       13,788       39,277       41,128  
Depreciation and amortization expense
    5,048       5,135       15,844       16,469  
General and administrative expenses
    539       600       1,454       1,717  
 
                       
Operating income
  $ 956     $ 5,828     $ 4,187     $ 4,250  
 
                       
International Liftboats:
                               
Number of liftboats (as of end of period) (c)
    24       20       24       20  
Revenues
  $ 22,320     $ 20,323     $ 61,709     $ 58,919  
Operating expenses
    14,457       10,660       31,677       27,776  
Depreciation and amortization expense
    4,010       3,143       8,672       7,495  
General and administrative expenses
    1,279       1,466       3,548       3,694  
 
                       
Operating income
  $ 2,574     $ 5,054     $ 17,812     $ 19,954  
 
                       
 
(a)   In January 2009, we retired four Domestic Offshore rigs and ten Inland barges.
 
(b)   In August 2009, we sold Hercules 110 which was cold-stacked in Trinidad.
 
(c)   The number of liftboats as of September 30, 2009 reflects the transfer of four liftboats from our Domestic Liftboats segment to our International Liftboats segment. The financial results of these four vessels are reflected in International Liftboats from the date of transfer which occurred during the three months ended September 30, 2009.

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    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
            (Dollars in thousands)          
            (As Adjusted)       (As Adjusted)  
Delta Towing:
                               
Revenues
  $ 6,237     $ 17,612     $ 18,167     $ 43,458  
Operating expenses
    8,049       9,726       22,069       27,051  
Depreciation and amortization expense
    1,892       2,782       6,318       8,057  
General and administrative expenses
    218       645       1,024       1,930  
 
                       
Operating income (loss)
  $ (3,922 )   $ 4,459     $ (11,244 )   $ 6,420  
 
                       
Total Company:
                               
Revenues
  $ 159,262     $ 315,738     $ 566,444     $ 798,338  
Operating expenses
    123,358       180,978       388,699       470,138  
Impairment of property and equipment
                26,882        
Depreciation and amortization expense
    51,802       50,256       151,739       141,150  
General and administrative expenses
    16,814       17,447       48,556       57,777  
 
                       
Operating income (loss)
    (32,712 )     67,057       (49,432 )     129,273  
Interest expense
    (24,131 )     (16,807 )     (54,481 )     (47,985 )
Expense of Credit Agreement Fees
    (15,073 )           (15,073 )      
Gain on early retirement of debt, net
                13,747        
Other, net
    70       543       2,760       2,818  
 
                       
Income (loss) before income taxes
    (71,846 )     50,793       (102,479 )     84,106  
Income tax benefit (provision)
    24,876       (18,938 )     39,211       (30,988 )
 
                       
Income (loss) from continuing operations
    (46,970 )     31,855       (63,268 )     53,118  
Loss from discontinued operation, net of taxes
    (1,290 )     (168 )     (1,965 )     (766 )
 
                       
Net income (loss)
  $ (48,260 )   $ 31,687     $ (65,233 )   $ 52,352  
 
                       
          The following table sets forth selected operational data by operating segment for the period indicated:
                                         
    Three Months Ended September 30, 2009
                                    Average
                            Average   Operating
    Operating   Available       Revenue   Expense
    Days   Days   Utilization (1)   per Day (2)   per Day (3)
Domestic Offshore
    424       1,012       41.9 %   $ 44,715     $ 36,043  
International Offshore
    768       1,006       76.3 %     117,241       43,945  
Inland
    116       276       42.0 %     21,009       26,964  
Domestic Liftboats
    2,466       3,596       68.6 %     7,813       3,539  
International Liftboats
    1,149       1,840       62.4 %     19,426       7,857  
                                         
    Three Months Ended September 30, 2008
                                    Average
                            Average   Operating
    Operating   Available       Revenue   Expense
    Days   Days   Utilization (1)   per Day (2)   per Day (3)
Domestic Offshore
    1,673       2,116       79.1 %   $ 67,384     $ 29,702  
International Offshore
    729       773       94.3 %     130,704       65,353  
Inland
    1,142       1,472       77.6 %     38,911       22,715  
Domestic Liftboats
    3,132       3,864       81.1 %     8,094       3,568  
International Liftboats
    1,143       1,656       69.0 %     17,780       6,437  

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    Nine Months Ended September 30, 2009
                                    Average
                            Average   Operating
    Operating   Available       Revenue   Expense
    Days   Days   Utilization (1)   per Day (2)   per Day (3)
Domestic Offshore
    1,994       3,532       56.5 %   $ 57,728     $ 37,269  
International Offshore
    2,351       2,763       85.1 %     125,585       46,138  
Inland
    414       1,302       31.8 %     37,309       28,082  
Domestic Liftboats
    7,349       11,308       65.0 %     8,268       3,473  
International Liftboats
    3,072       5,279       58.2 %     20,088       6,001  
                                         
    Nine Months Ended September 30, 2008
                                    Average
                            Average   Operating
    Operating   Available       Revenue   Expense
    Days   Days   Utilization (1)   per Day (2)   per Day (3)
Domestic Offshore
    4,383       6,142       71.4 %   $ 62,199     $ 27,173  
International Offshore
    2,025       2,214       91.5 %     115,957       49,963  
Inland
    3,097       4,505       68.7 %     40,351       21,458  
Domestic Liftboats
    7,198       11,921       60.4 %     8,831       3,450  
International Liftboats
    3,691       4,793       77.0 %     15,963       5,795  
 
(1)   Utilization is defined as the total number of days our rigs or liftboats, as applicable, were under contract, known as operating days, in the period as a percentage of the total number of available days in the period. Days during which our rigs and liftboats were undergoing major refurbishments, upgrades or construction, and days during which our rigs and liftboats are cold-stacked, are not counted as available days. Days during which our liftboats are in the shipyard undergoing drydocking or inspection are considered available days for the purposes of calculating utilization.
 
(2)   Average revenue per rig or liftboat per day is defined as revenue earned by our rigs or liftboats, as applicable, in the period divided by the total number of operating days for our rigs or liftboats, as applicable, in the period. Included in International Offshore revenue is a total of $4.3 million and $12.3 million related to amortization of deferred mobilization revenue and contract specific capital expenditures reimbursed by the customer for the three and nine months ended September 30, 2009, respectively and $3.1 million and $9.3 million for the three and nine months ended September 30, 2008, respectively. Included in International Liftboats revenue is a total of $0.1 million and $0.2 million related to amortization of deferred mobilization revenue for the three and nine months ended September 30, 2009, respectively. There was no such revenue in the three nor the nine months ended September 30, 2008 for International Liftboats.
 
(3)   Average operating expense per rig or liftboat per day is defined as operating expenses, excluding depreciation and amortization, incurred by our rigs or liftboats, as applicable, in the period divided by the total number of available days in the period. We use available days to calculate average operating expense per rig or liftboat per day rather than operating days, which are used to calculate average revenue per rig or liftboat per day, because we incur operating expenses on our rigs and liftboats even when they are not under contract and earning a dayrate. In addition, the operating expenses we incur on our rigs and liftboats per day when they are not under contract are typically lower than the per-day expenses we incur when they are under contract. Included in International Offshore operating expense is a total of $1.3 million and $2.7 million related to amortization of deferred mobilization expenses for the three and nine months ended September 30, 2009, respectively and $1.6 million and $4.6 million for the three and nine months ended September 30, 2008, respectively.
For the Three Months Ended September 30, 2009 and 2008
  Revenues
          Consolidated. Total revenues for the three-month period ended September 30, 2009 (the “Current Quarter”) were $159.3 million compared with $315.7 million for the three-month period ended September 30, 2008 (the “Comparable Quarter”), a decrease of $156.5 million, or 49.6%. This decrease is further described below.
          Domestic Offshore. Revenues for our Domestic Offshore segment were $19.0 million for the Current Quarter compared with $112.7 million for the Comparable Quarter, a decrease of $93.8 million, or 83.2%. This decrease resulted primarily from decreased operating days, 424 days during the Current Quarter as compared to 1,673 days during the Comparable Quarter, due to our cold stacking of rigs, and a 33.6% decrease in average dayrates during the Current Quarter as compared to the Comparable Quarter.

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          International Offshore. Revenues for our International Offshore segment were $90.0 million for the Current Quarter compared with $95.3 million for the Comparable Quarter, a decrease of $5.2 million, or 5.5%. Approximately $36 million of this decrease related to Hercules 156 and Hercules 170 in warm stack during the Current Quarter, a decline in dayrate on Hercules 205 and downtime due to leg repairs incurred on the Hercules 260. These decreases were partially offset by approximately $31 million due to increased operating days as a result of the commencement of Hercules 208 in August 2008, Hercules 261 in December 2008 and Hercules 262 in January 2009. Average revenue per rig per day decreased to $117,241 in the Current Quarter from $130,704 in the Comparable Quarter due primarily to the Current Quarter warm stacking of the Hercules 156, which operated at approximately $140,000 per day during the Comparable Quarter, and lower dayrates on Hercules 205 and Hercules 206, which both operated in the mid-$60,000 day rate range during the Current Quarter as compared to approximately $98,000 and approximately $112,000 per day, respectively, during the Comparable Quarter.
          Inland. Revenues for our Inland segment were $2.4 million for the Current Quarter compared with $44.4 million for the Comparable Quarter, a decrease of $42.0 million, or 94.5%. This decrease resulted primarily from decreased operating days, 116 days during the Current Quarter as compared to 1,142 days during the Comparable Quarter. Available days declined to 276 from 1,472, or 81.3%, during the Current Quarter as compared to the Comparable Quarter, respectively, due to our cold stacking plan. Average dayrates during the Current Quarter declined 46.0% to $21,009 per day as compared to the Comparable Quarter.
          Domestic Liftboats. Revenues from our Domestic Liftboats segment were $19.3 million for the Current Quarter compared with $25.4 million in the Comparable Quarter, a decrease of $6.1 million, or 24.0%. This decrease resulted primarily from decreased operating days, 2,466 days during the Current Quarter as compared to 3,132 days during the Comparable Quarter. In addition, the average revenue per vessel per day declined to $7,813 in the Current Quarter as compared to $8,094 per vessel per day in the Comparable Quarter, or a per vessel per day decrease of $281. The decrease in average revenue per vessel per day was due to lower dayrates as well as mix of vessel class.
          International Liftboats. Revenues for our International Liftboats segment were $22.3 million for the Current Quarter compared with $20.3 million in the Comparable Quarter, an increase of $2.0 million, or 9.8%. This increase resulted primarily from higher average revenue per liftboat per day of $19,426 in the Current Quarter compared with $17,780 in the Comparable Quarter primarily due to higher dayrates. Average utilization was 62.4% in the Current Quarter compared with 69.0% in the Comparable Quarter, while operating days increased slightly to 1,149 days in the Current Quarter as compared to 1,143 days in the Comparable Quarter.
          Delta Towing. Revenues for our Delta Towing segment were $6.2 million for the Current Quarter compared with $17.6 million in the Comparable Quarter, a decrease of $11.4 million, or 64.6%, due to decreased activity in both offshore and the transition zones.
Operating Expenses
          Consolidated. Total operating expenses for the Current Quarter were $123.4 million compared with $181.0 million in the Comparable Quarter, a decrease of $57.6 million, or 31.8%. This decrease is further described below.
          Domestic Offshore. Operating expenses for our Domestic Offshore segment were $36.5 million in the Current Quarter compared with $62.8 million in the Comparable Quarter, a decrease of $26.4 million, or 42.0%. The decrease was driven primarily by 1,104 fewer available days during the Current Quarter as compared to the Comparable Quarter, or a 52.2% decline, due to our cold stacking of rigs. As a part of our cold stacking plan, we reduced our labor force. Our cold stacking plan and lower activity on marketed rigs resulted in a reduction to our labor, repairs and maintenance and catering expenses. Average operating expenses per rig per day were $36,043 in the Current Quarter compared with $29,702 in the Comparable Quarter due in part to shore based support and cold-stacked rig costs being allocated over fewer available days.
          International Offshore. Operating expenses for our International Offshore segment were $44.2 million in the Current Quarter compared with $50.5 million in the Comparable Quarter, a decrease of $6.3 million, or 12.5%. Available days increased to 1,006 in the Current Quarter from 773 in the Comparable Quarter. Average operating expenses per rig per day were $43,945 in the Current Quarter compared with $65,353 in the Comparable Quarter. This average per day decrease related primarily to the Hercules 156 and Hercules 170 in warm stack during the Current Quarter and the initial start-up costs incurred during the Comparable Quarter relating to our India operations, offset partially by higher operating costs related to Hercules 185, which commenced its contract in July 2009.
          Inland. Operating expenses for our Inland segment were $7.4 million in the Current Quarter compared with $33.4 million in the Comparable Quarter, a decrease of $26.0 million, or 77.7%. Fourteen of our seventeen barges were cold stacked which reduced our available days from 1,472 in the Comparable Quarter to 276 in the Current Quarter. This reduction in available days coupled with the reduction in our labor force significantly reduced all of the segment’s variable operating costs. Average operating expenses per rig per day were $26,964 in the Current Quarter compared with $22,715 in the Comparable Quarter. The increase in cost per day was driven primarily by costs associated with shore based support and cold stacked barges being allocated over fewer available days.
          Domestic Liftboats. Operating expenses for our Domestic Liftboats segment were $12.7 million in the Current Quarter compared with $13.8 million in the Comparable Quarter, a decrease of $1.1 million, or 7.7%. Available days declined slightly to 3,596

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in the Current Quarter from 3,864 in the Comparable Quarter due to four vessels that were not marketed during the quarter in preparation of their mobilization to our International Liftboats segment which commenced in October 2009. Average operating expenses per vessel per day remained relatively static at $3,539 in the Current Quarter compared with $3,568 in the Comparable Quarter.
          International Liftboats. Operating expenses for our International Liftboats segment were $14.5 million for the Current Quarter compared with $10.7 million in the Comparable Quarter, an increase of $3.8 million, or 35.6%. Available days increased to 1,840 in the Current Quarter from 1,656 in the Comparable Quarter related to the Current Quarter availability of the Whale Shark and Amberjack, which were transferred to our International Liftboats segment from the Domestic Liftboats segment during 2008. Average operating expenses per liftboat per day were $7,857 in the Current Quarter compared with $6,437 in the Comparable Quarter due to higher catering and repairs and maintenance expenses, and the costs associated with preparing the four domestic vessels for transit to West Africa.
          Delta Towing. Operating expenses for our Delta Towing segment were $8.0 million for the Current Quarter compared with $9.7 million in the Comparable Quarter, a decrease of $1.7 million, or 17.2%. Due to the decline in activity both offshore and the transition zone, we have cold stacked certain assets in our fleet which resulted in lower labor, repairs and maintenance and fuel and oil expenses during the Current Quarter.
Depreciation and Amortization
          Depreciation and amortization expense in the Current Quarter was $51.8 million compared with $50.3 million in the Comparable Quarter, an increase of $1.5 million, or 3.1%. This increase resulted primarily from additional depreciation related to the commencement of Hercules 208 in August 2008, Hercules 261 in December 2008 and Hercules 262 in January 2009. These increases are partially offset by reduced depreciation due to the sale of Hercules 110 during the third quarter of 2009, the impairment of certain rigs, barges and related equipment in the fourth quarter of 2008 and lower amortization of our international contract values.
General and Administrative Expenses
          General and administrative expenses in the Current Quarter were $16.8 million compared with $17.4 million in the Comparable Quarter, a decrease of $0.6 million, or 3.6%. This decrease relates to the cost reduction initiatives implemented in late 2008 and in 2009 in response to the significant decline in activity in several of our business segments, partially offset by $1.9 million of bad debt expense recorded in the Current Quarter relating to certain Domestic Offshore customers and one International Offshore customer.
Interest Expense
          Interest expense in the Current Quarter was $24.1 million compared with $16.8 million in the Comparable Quarter, an increase of $7.3 million, or 43.6%. This increase was primarily related to the higher interest rate incurred on the outstanding term loan facility subsequent to the Credit Agreement amendment on July 27, 2009 as well as additional interest capitalized in the Comparable Quarter. In addition, we incurred approximately $1.2 million of additional interest expense during the Current Quarter related to the ineffective portion of our derivative contracts that were deemed ineffective subsequent to the amendment date. These increases were partially offset by lower interest expense incurred on our 3.375% Convertible Senior Notes during the Current Period as compared to the Comparable Period due to our December 2008, April 2009 and June 2009 retirements.
Expense of Credit Agreement Fees
          During the Current Quarter, we amended our credit agreement (the “Credit Agreement”), and repaid and terminated a portion of our credit facility. In doing so, we recorded the write-off of certain deferred debt issuance costs and certain fees directly related to these activities totaling $15.1 million.
Income Tax Benefit (Provision)
          Income tax benefit was $24.9 million on a pre-tax loss of $71.8 million during the Current Quarter, compared to a provision of $(18.9) million on pre-tax income of $50.8 million for the Comparable Quarter. The effective tax rate changed to a tax benefit of 34.6% in the Current Quarter from a tax provision of 37.3% in the Comparable Quarter. The change in the effective tax rate is due to the jurisdictional mix of earnings (losses).

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  Discontinued Operation
          We had a loss from discontinued operation, net of taxes of $1.3 million in the Current Quarter compared to a loss of $0.2 million in the Comparable Quarter, primarily related to $2.0 million of bad debt expense recorded in the Current Quarter relating to certain receivables we retained from our former land drilling business that was sold in the fourth quarter of 2007.
For the Nine Months Ended September 30, 2009 and 2008
  Revenues
          Consolidated. Total revenues for the nine-month period ended September 30, 2009 (the “Current Period”) were $566.4 million compared with $798.3 million for the nine-month period ended September 30, 2008 (the “Comparable Period”), a decrease of $231.9 million, or 29.0%. This decrease is further described below.
          Domestic Offshore. Revenues for our Domestic Offshore segment were $115.1 million for the Current Period compared with $272.6 million for the Comparable Period, a decrease of $157.5 million, or 57.8%. This decline resulted from decreased operating days due to our cold stacking of rigs, which contributed $137.9 million of the decrease, and lower average dayrates which contributed $19.6 million of the decrease. Average utilization was 56.5% in the Current Period compared with 71.4% in the Comparable Period.
          International Offshore. Revenues for our International Offshore segment were $295.3 million for the Current Period compared with $234.8 million for the Comparable Period, an increase of $60.4 million, or 25.7%. Approximately $130 million of this increase was due to increased operating days as a result of the commencement of the Hercules 260 in late April 2008, Hercules 258 in June 2008, Hercules 208 in August 2008, Hercules 261 in December 2008 and Hercules 262 in January 2009. These favorable increases were partially offset by approximately $70 million related to the Hercules 185 being in the shipyard for an upgrade for a portion of the Current Period, Hercules 156 and Hercules 170 in warm stack and the Hercules 110 in cold stack during the Current Period, and a lower average dayrate realized on Hercules 205. Average revenue per rig per day increased to $125,585 in the Current Period from $115,957 in the Comparable Period due primarily to higher average dayrates earned on Hercules 261 and Hercules 262 in the Current Period, partially offset by lower average dayrates earned on Hercules 205 and Hercules 206.
          Inland. Revenues for our Inland segment were $15.4 million in the Current Period compared with $125.0 million for the Comparable Period, a decrease of $109.5 million, or 87.6%. This decrease resulted primarily from decreased operating days, as average revenue per rig per day was only 7.5% lower in the Current Period as compared to the Comparable Period. Available days declined 71.1% during the Current Period as compared to the Comparable Period due to our cold stacking plan. Furthermore, average utilization was 31.8% on fewer available days in the Current Period compared with 68.7% in the Comparable Period as demand in the segment declined.
          Domestic Liftboats. Revenues for our Domestic Liftboats segment were $60.8 million for the Current Period compared with $63.6 million in the Comparable Period, a decrease of $2.8 million, or 4.4%. This decrease resulted primarily from lower average dayrates, which contributed $4.1 million of the decrease, partially offset by a $1.3 million increase due to a higher number of operating days in the Current Period. Operating days increased to 7,349 in the Current Period from 7,198 in the Comparable Period. Average utilization also increased to 65.0% in the Current Period from 60.4% in the Comparable Period. Average revenue per vessel per day was $8,268 in the Current Period compared with $8,831 in the Comparable Period, a decrease of $563 per day. The decrease in average revenue per vessel per day was due primarily to lower dayrates with a slight decrease due to mix of vessel class.
          International Liftboats. Revenues for our International Liftboats segment were $61.7 million for the Current Period compared with $58.9 million in the Comparable Period, an increase of $2.8 million, or 4.7%. This increase resulted from higher average dayrates, which contributed $15.2 million of the increase, significantly offset by fewer operating days, which contributed a $12.4 million decrease. Operating days decreased to 3,072 days in the Current Period from 3,691 days in the Comparable Period. Average revenue per liftboat per day was $20,088 in the Current Period compared with $15,963 in the Comparable Period, with average utilization of 58.2% in the Current Period compared with 77.0% in the Comparable Period.
          Delta Towing. Revenues for our Delta Towing segment were $18.2 million for the Current Period compared with $43.5 million in the Comparable Period, a decrease of $25.3 million, or 58.2%, due to decreased activity in both offshore and in the transition zone.
Operating Expenses
          Consolidated. Total operating expenses for the Current Period were $388.7 million compared with $470.1 million in the Comparable Period, a decrease of $81.4 million, or 17.3%. This decrease is further described below.
          Domestic Offshore. Operating expenses for our Domestic Offshore segment were $131.6 million in the Current Period compared with $166.9 million in the Comparable Period, a decrease of $35.3 million, or 21.1%. The decrease was driven primarily by

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lower labor, catering, repairs and maintenance, insurance and fuel and oil expenses, partially offset by higher workers’ compensation expenses. Available days decreased to 3,532 in the Current Period from 6,142 in the Comparable Period due to our cold stacking of rigs. Average operating expenses per rig per day were $37,269 in the Current Period compared with $27,173 in the Comparable Period due in part to shore based support and cold stacked rig costs being allocated over fewer available days.
          International Offshore. Operating expenses for our International Offshore segment were $127.5 million in the Current Period compared with $110.6 million in the Comparable Period, an increase of $16.9 million, or 15.2%. Available days increased to 2,763 in the Current Period from 2,214 in the Comparable Period. Average operating expenses per rig per day were $46,138 in the Current Period compared with $49,963 in the Comparable Period. This decrease related primarily to the Hercules 156 in warm stack during a portion of the Current Period and the initial start-up costs incurred during the Comparable Period related to our India operations.
          Inland. Operating expenses for our Inland segment were $36.6 million in the Current Period compared with $96.7 million in the Comparable Period, a decrease of $60.1 million, or 62.2%. By the end of the Current Period, fourteen of our seventeen barges were cold stacked which significantly reduced the segment’s variable operating costs. Average operating expenses per rig per day were $28,082 in the Current Period compared with $21,458 in the Comparable Period. The increase in cost per day was driven primarily by costs associated with shore based support and cold stacked barges being allocated over fewer available days.
          Domestic Liftboats. Operating expenses for our Domestic Liftboats segment were $39.3 million in the Current Period compared with $41.1 million in the Comparable Period, a decrease of $1.9 million, or 4.5% due primarily to lower labor expense, fuel and oil and insurance costs. Available days decreased to 11,308 in the Current Period from 11,921 in the Comparable Period due to four vessels that were not marketed during the third quarter 2009 in preparation of their mobilization to our International Liftboats Segment which commenced in October 2009 and due to the cold stacking of several liftboats during the Current Period that were available in the Comparable Period. Average operating expenses per vessel per day remained static at approximately $3,500 per day during the Current and Comparable Periods.
          International Liftboats. Operating expenses for our International Liftboats segment were $31.7 million in the Current Period compared with $27.8 million in the Comparable Period, an increase of $3.9 million, or 14.0%. Available days increased to 5,279 in the Current Period from 4,793 in the Comparable Period related to the Current Period availability of the Whale Shark and Amberjack, which were transferred to our International Liftboats segment from the Domestic Liftboats segment during 2008. Average operating expenses per liftboat per day were $6,001 in the Current Period compared with $5,795 in the Comparable Quarter due to higher repairs and maintenance expenses and costs associated with preparing the four domestic vessels for transit to West Africa.
          Delta Towing. Operating expenses for our Delta Towing segment were $22.1 million for the Current Period compared with $27.1 million in the Comparable Period, a decrease of $5.0 million, or 18.4%. Due to the decline in activity in both offshore and the transition zone, we have continued to cold stack certain assets in our fleet which resulted in lower labor, repairs and maintenance and fuel and oil expenses during the Current Period.
Impairment of Property and Equipment
          In June 2009, we entered into an agreement to sell Hercules 110, which was cold stacked in Trinidad, and incurred a $26.9 million impairment charge to write-down the rig to its fair value less costs to sell. The Hercules 110 was sold in August 2009. There was no such charge incurred during the Comparable Period.
Depreciation and Amortization
          Depreciation and amortization expense in the Current Period was $151.7 million compared with $141.2 million in the Comparable Period, an increase of $10.6 million, or 7.5%. This increase resulted primarily from additional depreciation related to the commencement of Hercules 260 in late April 2008, Hercules 350 in June 2008, Hercules 208 in August 2008, Hercules 261 in December 2008 and Hercules 262 in January 2009. These increases are partially offset by reduced depreciation due to the impairment of certain rigs, barges and related equipment in the fourth quarter of 2008 and lower amortization of our international contract values.
General and Administrative Expenses
          General and administrative expenses in the Current Period were $48.6 million compared with $57.8 million in the Comparable Period, a decrease of $9.2 million, or 16.0%. This decrease relates to the cost reduction initiatives implemented in late 2008 and in 2009 in response to the significant decline in activity in several of our business segments. In addition, the Comparable Period included $5.5 million in executive severance related costs.

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Interest Expense
          Interest expense in the Current Period was $54.5 million compared with $48.0 million in the Comparable Period, an increase of $6.5 million, or 13.5%. This increase was primarily related to the higher interest capitalized in the Comparable Period and higher interest expense incurred on our 3.375% Convertible Senior Notes which were outstanding for the entire Current Period as compared to only a portion of the Comparable Period. In addition, we incurred approximately $1.2 million of additional interest expense during the Current Period related to the ineffective portion of our derivative contracts that were deemed ineffective subsequent to the amendment date.
Expense of Credit Agreement Fees
          During the Current Period, we amended our Credit Agreement and repaid and terminated a portion of our credit facility. In doing so, we recorded the write-off of certain deferred debt issuance costs and certain fees directly related to these activities totaling $15.1 million.
Gain on Early Retirement of Debt, Net
          During the Current Period, we retired $65.8 million aggregate principal amount of the 3.375% Convertible Senior Notes for cash and equity consideration of approximately $40.1 million, resulting in a gain of $13.7 million, net of an associated write-off of a portion of our unamortized issuance costs.
Income Tax Benefit (Provision)
          Income tax benefit was $39.2 million on pre-tax loss of $102.5 million during the Current Period, compared to a provision of $(31.0) million on pre-tax income of $84.1 million for the Comparable Period. The effective tax rate changed to a tax benefit of 38.3% in the Current Period from a tax provision of 36.8% in the Comparable Period. The change in the effective tax rate is due to the jurisdictional mix of earnings (losses).
Discontinued Operation
          We had a loss from discontinued operation, net of taxes of $2.0 million in the Current Period compared to a loss of $0.8 million in the Comparable Period, primarily related to $2.0 million of bad debt expense recorded in the Current Period relating to certain receivables we retained from our former land drilling business that was sold in the Fourth Quarter of 2007.
CRITICAL ACCOUNTING POLICIES
          Critical accounting policies are those that are important to our results of operations, financial condition and cash flows and require management’s most difficult, subjective or complex judgments. Different amounts would be reported under alternative assumptions. We have evaluated the accounting policies used in the preparation of the unaudited consolidated financial statements and related notes appearing elsewhere in this quarterly report. We apply those accounting policies that we believe best reflect the underlying business and economic events, consistent with accounting principles generally accepted in the United States. We believe that our policies are generally consistent with those used by other companies in our industry.
          We periodically update the estimates used in the preparation of the financial statements based on our latest assessment of the current and projected business and general economic environment. During recent months, there has been substantial volatility and a decline in commodity prices. In addition, there has been uncertainty in the capital markets and available financing is limited. If these conditions persist for a prolonged length of time, our business and the businesses of our customers could be adversely impacted. This in turn could result in changes to estimates used in preparing our financial statements, including the assessment of certain of our assets for impairment.
          We believe that our more critical accounting policies include those related to property and equipment, revenue recognition, income tax, allowance for doubtful accounts, deferred charges, stock-based compensation, cash and cash equivalents and marketable securities and intangible assets. Inherent in such policies are certain key assumptions and estimates. For additional information regarding our critical accounting policies, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies” in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2008, as amended on Form 8-K, filed September 23, 2009.

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OUTLOOK
  Offshore
     In general, demand for our drilling rigs is a function of our customers’ capital spending plans, which are largely driven by current commodity prices and their expectations of future commodity prices. Demand in the U.S. Gulf of Mexico is particularly driven by natural gas prices, with demand internationally typically driven by oil prices.
     As of October 26, 2009, the spot price for Henry Hub natural gas was $4.51 per MMBtu, a significant decline from the high of $13.31 per MMBtu in July 2008. The twelve month strip, or the average of the next twelve month’s futures contract, was $5.58 per MMBtu on October 26, 2009. A myriad of factors have combined to cause the current depressed price of natural gas. The current worldwide economic downturn has reduced economic activity, which in turn has reduced energy consumption, creating a sharp decline in the demand for natural gas. On the supply side, increases in onshore production in the U.S., driven by a significant increase in onshore drilling activity through mid-2008 and a large number of discoveries, have also put downward pressure on natural gas prices. Growing deepwater production and potential increased deliveries of liquefied natural gas are additional factors which have weighed on natural gas prices. We believe the significant disparity between the relatively low spot price of natural gas and the higher twelve month strip reflects not only seasonal weakness during the current shoulder month, but also investors increasing expectations for an economic rebound leading to a recovery in industrial demand for natural gas, coupled with a belief that the recent decline in North American drilling activity will lead to declines in production. These factors, together with weather, will likely remain key drivers in the natural gas market for the foreseeable future.
     Oil prices declined significantly from mid-2008 to early 2009 as a result of the anticipated effects of global economic weakness, increase in oil inventories relative to consumption and a strengthening in the U.S. dollar. The price of West Texas intermediate crude (“WTI”) declined from $145.29 as of July 3, 2008, to a multi-year low of $31.41 in December 2008. However, they have since recovered meaningfully to $78.68 as of October 26, 2009.
     Many of our customers significantly reduced their capital spending in 2009 relative to 2008 spending. While the substantial declines in both natural gas and oil prices relative to 2008 are a primary factor, the weak global economic outlook, shut-in production related to damage sustained during Hurricanes Gustav and Ike, and a more difficult environment to raise outside capital have all contributed to this curtailed level of capital spending. This is particularly applicable to our U.S. Gulf of Mexico focused customers whose drilling programs are shorter-term in nature and can be adjusted more quickly in response to commodity price fluctuations. Many of these U.S. Gulf of Mexico focused customers are smaller and employ more financial leverage and may face difficulty in raising outside funding for drilling programs. Recent domestic bidding has signaled increased activity post the 2009 hurricane season, albeit at relatively low dayrates. Although the fourth quarter activity appears to be improved from the recent lows, 2010 activity will be dependent upon natural gas prices, among other factors. While international spending programs are much longer-term in nature, and the customers tend to have greater financial resources, international capital spending has also declined in 2009, following nine years of growth, but to a lesser degree.
     Global demand for jackup rigs has increased significantly over the last several years with international regions such as the Middle East, India and Mexico being particularly strong. Demand for jackups worldwide, excluding the U.S. Gulf of Mexico, increased from 200 in 2001 to 304 on October 26, 2009.
     Strong global demand for jackups over the past few years has encouraged newbuilds. According to ODS-Petrodata, as of October 26, 2009, approximately 73 new jackup rigs have been delivered since January 1, 2006. Further, 66 new jackup rigs remain either under construction or on order for delivery through 2012. Given the recent financial crisis and the weakened outlook, a number of orders have been cancelled, and we anticipate that several of these remaining orders will be delayed or cancelled. However, we expect the majority of these rigs will be delivered and will compete directly with our fleet. As a result of generally higher dayrates, longer duration contracts and lower insurance costs, which are prevalent internationally, among other factors, we believe the vast majority of the newbuild jackup rigs will target international regions rather than the U.S. Gulf of Mexico. Our ability to secure new contracts for our international fleet or to expand our international drilling operations may be limited by the increased supply of newbuild jackup rigs.
     In addition to spurring newbuilds, this international demand has drawn available rigs from the U.S. Gulf of Mexico. As a result, the supply of jackup rigs in the U.S. Gulf of Mexico has declined considerably over the last several years from a high of 157 jackups in 2001 to only 70 currently.
     While the overall current supply of jackup rigs in the U.S. Gulf of Mexico is 70, several of these rigs are either in the shipyard or cold-stacked, and the marketed supply is approximately 40 as of October 26, 2009. While the number of jackups located in the U.S. Gulf of Mexico has declined significantly over the last several years, current demand of approximately 22 jackups as of October 26, 2009 is also considerably lower than three years ago when 65 jackups were operating on October 26, 2006. A combination of factors have resulted in this decline in the number of rigs from the levels experienced over the previous several years, including declining target reservoir sizes, increasing finding, development and lifting costs and lower current natural gas prices.

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     A further reduction in the number of rigs operating in the U.S. Gulf of Mexico is possible; however, the pace of migration of jackup rigs from the region to international regions will likely slow as much of the expected growth in international demand will be met by the aforementioned newbuild deliveries. Further, a modest reduction in the supply in the U.S. Gulf of Mexico will likely not be sufficient to offset the impact of weak demand resulting from our customers’ curtailed capital spending in 2009 and 2010.
     The global financial and credit crisis has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. The shortage of liquidity and credit combined with recent substantial losses in worldwide equity markets has led to an extended global recession which results in a corresponding decline in the demand for our jackup rigs and other services.
     While the outlook for drilling activity in 2009 and 2010 has been hampered by the aforementioned weaker commodity prices and the global credit crisis, a number of factors give us optimism for the longer term. First, with steep initial decline rates in many North American natural gas basins and a substantial reduction in the rig count, the recent strong natural gas market production growth could quickly slow or even reverse. With respect to international markets, which are typically driven by crude oil prices, the lack of any significant oil production growth over the last five years, despite a more than doubling of international exploration and production capital spending over this period, leads us to believe that production would decline in response to a decrease in exploration and production spending.
     Furthermore, the offshore drilling market remains highly competitive and cyclical, and it has historically been difficult to forecast future market conditions. While future commodity price expectations have typically been a key driver for demand for drilling rigs, other factors also affect our customers’ drilling programs, including the quality of drilling prospects, exploration success, relative production costs, availability of insurance, and political and regulatory environments. Additionally, the offshore drilling business has historically been cyclical, marked by periods of low demand, excess rig supply and low dayrates, followed by periods of high demand, short rig supply and increasing dayrates. These cycles have been volatile and are subject to rapid change.
Inland
     The activity for inland barge drilling in the U.S. generally follows the same drivers as drilling in the U.S. Gulf of Mexico with activity following operators’ expectations of prices for natural gas and crude oil. Barge rig drilling activity historically lags activity in the U.S. Gulf of Mexico due to a number of factors such as the lengthy permitting process that operators must go through prior to drilling a well in Louisiana, where the majority of our inland drilling takes place, and the predominance of smaller independent operators active in inland waters.
     Inland barge drilling activity has slowed dramatically over the past year and dayrates have softened as a result of the number of the key operators that have curtailed or ceased their activity in the inland market for various reasons, including lack of funding, lack of drilling success and re-allocation of capital to other onshore basins. Recent bidding activity has increased, with a higher percent focused on crude oil. As of October 27, 2009, all three of our marketed inland barges had contracts for work. While we may have some increased activity for our inland barges based on recent bidding activity, we expect activity levels to remain very low versus historic norms for the duration of 2009 and into 2010.
Liftboats
     Demand for liftboats is typically a function of our customers’ demand for platform inspection and maintenance, well maintenance, offshore construction, well plugging and abandonment, and other related activities. Although activity levels for liftboats are not as closely correlated to movement in commodity prices as for offshore drilling rigs, commodity prices are still a key driver of the demand for liftboats. Despite the production maintenance related nature of the majority of the work, some of the work may be deferred from time to time.
     Following the active 2005 hurricane season, which caused tremendous damage to the infrastructure in the U.S. Gulf of Mexico, liftboat utilization and dayrates in the region were stronger than historical levels for approximately two years. As activity levels declined to more typical levels and supply increased, as approximately 20 new liftboats were delivered for work in the U.S. Gulf of Mexico since January 2007, dayrates softened.
     Activity levels increased again in late 2008 as customers addressed damage caused by the hurricanes Gustav and Ike; however, the damage was not as extensive as from the 2005 hurricane season, so the higher activity levels continued only into the first quarter of 2009. Dayrates once again increased, responding to the tightened supply and demand balance but have since declined again as the preponderance of the higher priority repair work has been completed.
     As of October 26, 2009, we believe that there were another 8 liftboats under construction or on order in the U.S., with anticipated delivery dates through 2010. Once delivered, these liftboats may further impact the demand and utilization of our domestic liftboat fleet.
     Our customers’ growth in international capital spending for the last several years, coupled with an aging infrastructure and significant increases in the cost of alternatives for servicing this infrastructure, has generally resulted in strong demand for our liftboats in West Africa. As international markets mature and the focus shifts from exploration to development, in locations such as

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West Africa, the Middle East and Southeast Asia, we would expect to experience strong demand growth for liftboats. We anticipate that there may be contract opportunities in international locations for liftboats currently working in the U.S. Gulf of Mexico and for newly constructed liftboats. In 2008, we mobilized two of our liftboats to the Middle East from the U.S. Gulf of Mexico, and we have recently commenced mobilization of four liftboats from the U.S. Gulf of Mexico to West Africa. While we believe that international demand for liftboats will continue to increase over the longer term, the political instability in certain regions may negatively impact our customers’ capital spending plans.
LIQUIDITY AND CAPITAL RESOURCES
          Recent Developments
          Common Stock Offering
          In September 2009, we raised approximately $82.3 million in net proceeds from an underwritten public offering of 17,500,000 shares of our common stock. In addition, on October 9, 2009, we sold an additional 1,313,590 shares of our common stock pursuant to the partial exercise of the underwriters’ over-allotment option and raised an additional $6.3 million in net proceeds. We used 50% of the net proceeds from these sales of common stock to repay a portion of our outstanding indebtedness under our term loan facility, and may use some or all of the remaining proceeds to repay additional indebtedness.
          10.5% Senior Secured Notes due 2017
          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 notes will be payable in cash semi-annually in arrears on April 15 and October 15 of each year, commencing on April 15, 2010, 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 will be recorded at their discounted amount, with the discount to be amortized over the life of the notes. We used the net proceeds of approximately $284.4 million from the offering to repay a portion of the indebtedness outstanding under our term loan facility.
          The notes will be 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 are 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. 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 (a) $375.0 million and (b) 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.
          Prior to October 15, 2012, we may redeem the notes with the net cash proceeds of certain equity offerings, at a redemption price equal to 110.50% of the aggregate principal amount plus accrued and unpaid interest; provided, that (i) after giving effect to any such redemption, at least 65% of the notes originally issued would remain outstanding immediately after such redemption and (ii) we make such redemption not more than 90 days after the consummation of such equity offering. In addition, prior to October 15, 2013, we may redeem all or part of the notes at a price equal to 100% of the aggregate principal amount of notes to be redeemed, plus the applicable premium and accrued and unpaid interest.

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          On or after October 15, 2013, we may redeem the notes, in whole or part, at the redemption prices set forth below, together with accrued and unpaid interest to the redemption date.
         
Year   Optional Redemption Price
2013
    105.2500 %
2014
    102.6250 %
2015
    101.3125 %
2016 and thereafter
    100.0000 %
          If we experience certain kinds of changes of control, we must offer to repurchase the notes at an offer price in cash equal to 101% of their principal amount, plus accrued and unpaid interest. Furthermore, following certain asset sales, we may be required to use the proceeds to offer to repurchase the notes at an offer price in cash equal to 100% of their principal amount, plus accrued and unpaid interest.
          Term Loan Facility Repayment
          Subsequent to September 30, 2009, we made the following payments on our term loan facility:
  (i)   we used the net proceeds from the partial exercise of the underwriters’ over-allotment option and the Senior Secured Notes due 2017, which approximated $287.5 million, to repay a portion of the outstanding balance on our term loan facility; and
 
  (ii)   we utilized approximately $94.3 million of cash on hand which is reflected in our September 30, 2009 Balance Sheet, to repay a portion of the outstanding balance on our term loan facility.
          As of October 29, 2009, the balance outstanding under our term loan facility totaled $484.1 million, which reduces the margin applicable to our outstanding term loan facility borrowings under Eurodollar Loans from 6.50% to 4.00% and under ABR Loans from 5.50% to 3.00%.
  Sources and Uses of Cash
          Sources and uses of cash for the nine-month period ended September 30, 2009 are as follows (in millions):
         
Net Cash Provided by Operating Activities
  $ 121.0  
Net Cash Provided by (Used in) Investing Activities:
       
Additions of Property and Equipment
    (71.4 )
Deferred Drydocking Expenditures
    (13.7 )
Insurance Proceeds Received
    9.1  
Proceeds from Sale of Assets, Net
    23.3  
Increase in Restricted Cash
    (3.7 )
 
     
Total
    (56.4 )
Net Cash Provided by (Used in) Financing Activities:
       
Debt Repayments, Net
    (23.0 )
Redemption of 3.375% Convertible Senior Notes
    (6.1 )
Common Stock Issuance
    83.3  
Payment of Debt Issuance Costs
    (9.9 )
Excess Tax Benefit from Stock-Based Arrangements
    4.5  
 
     
Total
    48.8  
 
     
Net Increase in Cash and Cash Equivalents
  $ 113.4  
 
     
     In June, 2009, we entered into an agreement to sell our Hercules 100 and Hercules 110 jackup drilling rigs for a total purchase price of $12.0 million. The Hercules 100 was classified as “retired” and has been stacked in the United States since April 1999, and the Hercules 110 was cold-stacked in Trinidad since August 2008. The closing of the sale of the Hercules 100 and Hercules 110 occurred in August 2009.
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

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proceeds of such debt to repay or refinance existing debt. We currently believe we will have adequate liquidity to fund our operations for the foreseeable future. However, to the extent we do not generate sufficient cash from operations we may need to raise additional funds through public or private debt or equity offerings to fund operations. Furthermore, we may need to raise additional funds through public or private debt or equity offerings or asset sales to meet certain covenants under the Credit Agreement, to refinance existing debt or for general corporate purposes.
     Our Credit Agreement requires that we meet certain financial ratios and tests, which we currently meet. Our failure to comply with such covenants would result in an event of default under the Credit Agreement. An event of default could prevent us from borrowing under the revolving credit facility, which would in turn have a material adverse effect on our available liquidity. Additionally, an event of default could result in us having to immediately repay all amounts outstanding under the term loan facility and the revolving credit facility and in the foreclosure of liens on our assets.
     Cash Requirements and Contractual Obligations
Debt
     Our current debt structure is used to fund our business operations.
     On July 27, 2009, we amended the Credit Agreement governing our $1,132.0 million credit facility with a syndicate of financial institutions (the “Credit Amendment”), consisting of an $882.0 million term loan and a $250.0 million revolving credit facility. A fee of 0.50% was paid to lenders consenting to the Credit Amendment, based on their total commitment, which approximated $4.8 million.
     The Credit Amendment reduced the revolving credit facility by $75.0 million to $175.0 million. The commitment fee on the revolving credit facility increased from 0.375% to 1.00%. Additionally, the Credit Amendment establishes a minimum London Interbank Offered Rate (“LIBOR”) rate of 2.00%, and 3.00%, with respect to our Alternative Base Rate (“ABR”) Loans and increases the margin applicable to Eurodollar Loans and ABR Loans, subject to a grid based on the aggregate principal amount of the Term Loans outstanding as follows ($ in millions):
                                 
Principal Amount Outstanding       Margin Applicable to:
Less than or equal to:   Greater than:       Eurodollar Loans   ABR Loans
$ 882.00     $ 684.25    
 
    6.50 %     5.50 %
  684.25       484.25    
 
    5.00 %     4.00 %
  484.25          
 
    4.00 %     3.00 %
     The Credit Amendment also modifies certain provisions of the Credit Agreement to, among other things:
    Eliminate the requirement that we comply with the total leverage ratio financial covenant for the nine month period commencing October 1, 2009 and ending on June 30, 2010 and amend the maximum total leverage ratio that we must comply with following the expiration of the nine month period to be more favorable to us;
    Require us to maintain a minimum level of liquidity, measured as the amount of unrestricted cash and cash equivalents we have on hand and availability under the revolving credit facility, of (i) $100.0 million for the period between October 1, 2009 through December 31, 2010, (ii) $75.0 million during calendar year 2011 and (iii) $50.0 million thereafter;
 
    Revise the fixed charge coverage ratio definition and reduce the minimum fixed charge coverage ratio that we must maintain in a manner that is more favorable to us;
 
    Require mandatory prepayments of debt outstanding under the Credit Agreement with 100% of excess cash flow for the fiscal year ending December 31, 2009 and 50% of excess cash flow thereafter and with proceeds from:
  §   unsecured debt issuances, with the exception of refinancing, through June 30, 2010;
 
  §   secured debt issuances;
 
  §   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.

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     The credit facility governed by the Credit Agreement, consists of an $882.0 million term loan which matures on July 11, 2013 and a $175.0 million revolving credit facility which matures on July 11, 2012. The availability under the $175.0 million revolving credit facility must be used for working capital, capital expenditures and other general corporate purposes and cannot be used to prepay our term loan. As of September 30, 2009, no amounts were outstanding and $10.0 million in stand-by letters of credit had been issued under the revolving credit facility, therefore the remaining availability under this revolving credit facility was $165.0 million. The revolving credit facility requires interest-only payments on a quarterly basis until the maturity date.
     As of September 30, 2009, $865.9 million was outstanding on the term loan facility and the interest rate was 8.5%. The annualized effective interest rate was 6.54% for the nine months ended September 30, 2009 after giving consideration to revolver fees and derivative activity. As of October 29, 2009, $484.1 million was outstanding on the term loan facility.
     Other covenants contained in the Credit Agreement restrict, among other things, asset dispositions, mergers and acquisitions, dividends, stock repurchases and redemptions, other restricted payments, debt issuances, liens, investments, convertible notes repurchases and affiliate transactions.
          In May 2008 and July 2007, we entered into derivative instruments with the purpose of hedging future interest payments on our term loan facility. We entered into a floating-to-fixed interest rate swap with varying notional amounts beginning with $100.0 million with a settlement date of October 1, 2008 and ending with $75.0 million with a settlement date of December 31, 2009. We receive an interest rate of three-month LIBOR and pay a fixed coupon of 2.980% over six quarters. The terms and settlement dates of the swap matched those of the term loan through July 27, 2009, the date of the Credit Amendment. We also entered into a zero cost LIBOR collar on $300.0 million of term loan principal with a final settlement date of October 1, 2010 with a ceiling of 5.75% and a floor of 4.99%. The counterparty is obligated to pay us in any quarter that actual LIBOR resets above 5.75% and we pay the counterparty in any quarter that actual LIBOR resets below 4.99%. The terms and settlement dates of the collar matched those of the term loan through July 27, 2009, the date of the Credit Amendment. As a result of the inclusion of a LIBOR floor in the amended Credit Agreement, we do not believe, as of July 27, 2009 and on an ongoing basis, that the interest rate swaps and collars will be highly effective in achieving offsetting changes in cash flows attributable to the hedged interest rate risk during the period that the hedge was designated. As such, we have prospectively discontinued cash flow hedge accounting for the interest rate swaps and collars as of July 27, 2009 and will no longer apply cash flow hedge accounting to these instruments. Because cash flow hedge accounting will not be applied to these instruments, changes in fair value related to the interest rate swaps and collars subsequent to July 27, 2009 will be recorded in earnings on a go-forward basis. As a result of discontinuing the cash flow hedging relationship, we recognized a decrease in fair value of $1.2 million related to the hedge ineffectiveness of our interest rate swaps and collars as Interest Expense in our Consolidated Statements of Operations for the three and nine month periods ended September 30, 2009. 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, 2008 related to these instruments. The change in the fair value of our hedging instruments resulted in a decrease in derivative liabilities of $4.7 million during the nine months ended September 30, 2009. We had net unrealized gains on hedge transactions of $5.1 million, net of tax of $2.7 million, and $6.7 million, net of tax of $3.6 million for the three and nine months ended September 30, 2009, respectively and $2.0 million, net of tax of $1.1 million, and $0.4 million, net of tax of $0.2 million for the three and nine months ended September 30, 2008, respectively. Overall, our interest expense was increased by $5.6 million and $14.0 million during the three and nine months ended September 30, 2009, respectively and $3.0 million and $7.3 million during the three and nine months ended September 30, 2008, respectively, as a result of our interest rate derivative instruments.
     On June 3, 2008, we completed an offering of $250.0 million convertible senior notes at a coupon rate of 3.375% (“3.375% Convertible Senior Notes”) with a maturity in June 2038. As of September 30, 2009, $95.9 million notional amount of the $250.0 million 3.375% Convertible Senior Notes was outstanding. The carrying amount of the 3.375% Convertible Senior Notes was $82.3 million at September 30, 2009.
     The interest on the 3.375% Convertible Senior Notes is payable in cash semi-annually in arrears, on June 1 and December 1 of each year until June 1, 2013, after which the principal will accrete at an annual yield to maturity of 3.375% per year. We will also pay contingent interest during any six-month interest period commencing June 1, 2013, for which the trading price of these notes for a specified period of time equals or exceeds 120% of their accreted principal amount. The notes will be convertible under certain circumstances into shares of our common stock (“Common Stock”) at an initial conversion rate of 19.9695 shares of Common Stock per $1,000 principal amount of notes, which is equal to an initial conversion price of approximately $50.08 per share. Upon conversion of a note, a holder will receive, at our election, shares of Common Stock, cash or a combination of cash and shares of Common Stock. We may redeem the notes at our option beginning June 6, 2013, and holders of the notes will have the right to require us to repurchase the notes on June 1, 2013 and certain dates thereafter or on the occurrence of a fundamental change.
     During December 2008 and April 2009, we repurchased $88.2 million and $20.0 million aggregate principal amount of the 3.375% Convertible Senior Notes, respectively, for a cost of $44.8 million and $6.1 million, respectively. In addition, during December 2008 and April 2009 we expensed $2.1 million and $0.4 million of unamortized issuance costs, respectively, in connection with the retirement. In June 2009, we retired $45.8 million aggregate principal amount of its 3.375% Convertible Senior Notes in exchange for the issuance of 7,755,440 Common Shares valued at $4.38 per share and payment of accrued interest, resulting in a gain of $4.4 million. In addition, we expensed $1.0 million of unamortized issuance costs in connection with the retirement. The settlement consideration was allocated to the extinguishment of the liability component in an amount equal to the fair value of that

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component immediately prior to extinguishment, with the difference between this allocation and the net carrying amount of the liability component and unamortized debt issuance costs recognized as a gain or loss on debt extinguishment. If there would have been any remaining settlement consideration, it, would have been allocated to the reacquisition of the equity component and recognized as a reduction of Stockholders’ Equity.
     The foreign overdraft facility, which was designed to manage local currency liquidity in Venezuela, was terminated in March 2009 and all outstanding amounts were repaid.
     The fair value of our 3.375% Convertible Senior Notes and term loan facility is estimated based on quoted prices in active markets. We believe the carrying value of our short-term debt instruments outstanding at December 31, 2008 approximate fair value. The following table provides the carrying value and fair value of our long-term debt instruments:
                                 
    September 30, 2009   December 31, 2008
    Carrying   Fair   Carrying   Fair
    Value   Value   Value   Value
            (in millions)        
Term Loan Facility, due July 2013
  $ 865.9     $ 844.3     $ 886.5     $ 571.8  
3.375% Convertible Senior Notes due June 2038
    82.3       71.6       134.8       77.2  
7.375% Senior Notes, due April 2018 (a)
    3.5       n/a       3.5       n/a  
 
(a)   The 7.375% Senior Notes have not been traded in recent periods and we believe that the fair value would not materially differ from the carrying value.
     In May 2009, we completed the renewal of all of our key insurance policies. Our primary marine package provides for hull and machinery coverage for our rigs and liftboats up to a scheduled value for each asset. The maximum coverage for these assets is $2.2 billion; however, coverage for U.S. Gulf of Mexico named windstorm damage is subject to an annual aggregate limit on liability of $100.0 million. The policies are subject to exclusions, limitations, deductibles, self-insured retention and other conditions. Deductibles for events that are not U.S. Gulf of Mexico named windstorm events are 12.5% of insured values per occurrence for drilling rigs, and $1.0 million per occurrence for liftboats, regardless of the insured value of the particular vessel. The deductibles for drilling rigs and liftboats in a U.S. Gulf of Mexico named windstorm event are the greater of $25.0 million or the operational deductible for each U.S. Gulf of Mexico named windstorm. We are self-insured for 15% above the deductibles for removal of wreck, sue and labor, collision, protection and indemnity general liability and hull and physical damage policies. The protection and indemnity coverage under the primary marine package has a $5.0 million limit per occurrence with excess liability coverage up to $200.0 million. The primary marine package also provides coverage for cargo and charterer’s legal liability. Vessel pollution is covered under a Water Quality Insurance Syndicate policy with a $3 million deductible proving limits as required. In addition to the marine package, we have separate policies providing coverage for onshore general liability, employer’s liability, auto liability and non-owned aircraft liability, with customary deductibles and coverage as well as a separate primary marine package for our Delta Towing business.
     In 2009, in connection with the renewal of certain of our insurance policies, we entered into a agreements to finance a portion of our annual insurance premiums. Approximately $23.3 million was financed through these arrangements, and $14.8 million was outstanding at September 30, 2009. The interest rate on the $21.4 million note is 4.15% and it is scheduled to mature in March 2010. The interest rate on the $1.9 million note is 3.75% and it is scheduled to mature in July 2010. The amounts financed in connection with the prior year renewal were fully paid as of March 31, 2009.
  Capital Expenditures
     We expect to spend approximately $15 million on capital expenditures and drydocking, during the remainder of 2009. Planned capital expenditures include refurbishment or upgrades to certain of our rigs, liftboats, and other marine vessels. The timing and amounts we actually spend in connection with our plans to upgrade and refurbish other selected rigs and liftboats are subject to our discretion and will depend on our view of market conditions and our cash flows.
     Costs associated with refurbishment or upgrade activities which substantially extend the useful life or operating capabilities of the asset are capitalized. Refurbishment entails replacing or rebuilding the operating equipment. An upgrade entails increasing the operating capabilities of a rig or liftboat. This can be accomplished by a number of means, including adding new or higher specification equipment to the unit, increasing the water depth capabilities or increasing the capacity of the living quarters, or a combination of each.
     We are required to inspect and drydock our liftboats on a periodic basis to meet U.S. Coast Guard requirements. The amount of expenditures is impacted by a number of factors, including, among others, our ongoing maintenance expenditures, adverse weather, changes in regulatory requirements and operating conditions. In addition, from time to time we agree to perform modifications to our rigs and liftboats as part of a contract with a customer. When market conditions allow, we attempt to recover these costs as part of the contract cash flow.

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     From time to time, we may review possible acquisitions of rigs, liftboats or businesses, joint ventures, mergers or other business combinations, and we may have outstanding from time to time bids to acquire certain assets from other companies. We may not, however, be successful in our acquisition efforts. We are generally restricted by our Credit Agreement from making acquisitions for cash consideration, except to the extent the acquisition is funded by an issuance of our stock or cash proceeds from the issuance of stock, or unless we are in compliance with our financial covenants as they existed prior to the Credit Amendment. If we acquire additional assets, we would expect that the ongoing capital expenditures for our company as a whole would increase in order to maintain our equipment in a competitive condition.
     Our ability to fund capital expenditures would be adversely affected if conditions deteriorate in our business or if we experience poor results in our operations.
  Off-Balance Sheet Arrangements
  Guarantees
     Our obligations under the credit facility 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 several of their vessels and substantially all of their other personal property.
  Letters of Credit and Surety Bonds
          We execute letters of credit and surety bonds in the normal course of business. While these obligations are not normally called, these obligations could be called by the beneficiaries at any time before the expiration date should we breach certain contractual or payment obligations. As of September 30, 2009, we had $47.0 million of letters of credit and surety bonds outstanding, consisting of $0.1 million in an unsecured outstanding letter of credit, $10.0 million letters of credit outstanding under our revolver and $36.9 million outstanding in surety bonds that guarantee our performance as it relates to our drilling contracts, insurance, tax and other obligations in various jurisdictions. If the beneficiaries called these letters of credit and surety bonds, the called amount would become an on-balance sheet liability, and we would be required to settle the liability with cash on hand or through borrowings under our available line of credit. We have restricted cash of $3.7 million to support surety bonds primarily related to the Company’s Mexico 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 2009, there were no material changes outside the ordinary course of business in the specified contractual obligations:
    Retired $65.8 million aggregate principal amount of the 3.375% Convertible Senior Notes;
 
    Repaid $20.6 million of our term loan facility outstanding at December 31, 2008;
 
    Settled the $11.1 million insurance note payable outstanding at December 31, 2008; and
 
    Financed $23.3 million related to the renewal of certain of our insurance policies.
          Subsequent to September 30, 2009, we repaid $381.8 million of our term loan facility outstanding at December 31, 2008 with cash on hand, proceeds from the underwriters’ over-allotment option and our offering of 10.5% Senior Secured Notes.
          For additional information about our contractual obligations as of December 31, 2008, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources— Contractual Obligations” in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2008, as amended on Form 8-K, filed September 23, 2009.
Accounting Pronouncements
          See Note 13 to our condensed consolidated financial statements included elsewhere in this report.
FORWARD-LOOKING STATEMENTS
          This Quarterly Report on Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical fact, included in this quarterly report that address outlook, activities, events or developments that we expect, project, believe or anticipate will or may occur in the future are forward-looking statements. These include such matters as:

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    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, when such contracts expire;
    demand for our rigs and our liftboats and our earnings;
    activity levels of our customers and their expectations of future energy prices;
    sufficiency and availability of funds for required capital expenditures, working capital and debt service;
    success of our cost cutting measures and plans to dispose of certain assets;
    expected completion times for our refurbishment and upgrade projects;
    our plans to increase international operations;
    expected useful lives of our rigs and liftboats;
    future capital expenditures and refurbishment, reactivation, transportation, repair and upgrade costs;
    our ability to effectively reactivate rigs that we have recently stacked;
    liabilities and restrictions under coastwise laws of the United States and regulations protecting the environment;
    expected outcomes of litigation, claims and disputes and their expected effects on our financial condition and results of operations; and
    expectations regarding offshore drilling activity and dayrates, market conditions, demand for our rigs and liftboats, operating revenues, operating and maintenance expense, insurance coverage, insurance expense and deductibles, interest expense, debt levels and other matters with regard to outlook.
We have based these statements on our assumptions and analyses in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. Forward-looking statements by their nature involve substantial risks and uncertainties that could significantly affect expected results, and actual future results could differ materially from those described in such statements. Although it is not possible to identify all factors, we continue to face many risks and uncertainties. Among the factors that could cause actual future results to differ materially are the risks and uncertainties described under “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2008, Item 1A of Part II of our quarterly report on Form 10-Q for the quarter ended June 30, 2009, Item 1A of Part II of this quarterly report and the following:
    oil and natural gas prices and industry expectations about future prices;
    demand for 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, West Africa and other oil and natural gas producing regions or acts of terrorism or piracy;
    the impact of governmental laws and regulations;
    the adequacy and costs of sources of credit and liquidity;
    uncertainties relating to the level of activity in offshore oil and natural gas exploration, development and production;
 
    competition and market conditions in the contract drilling and liftboat industries;
    the availability of skilled personnel in view of recent reductions in our personnel;

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    labor relations and work stoppages, particularly in the West African and Mexican labor environments;
    operating hazards such as hurricanes, severe weather and seas, fires, cratering, blowouts, war, terrorism and cancellation or unavailability of insurance coverage, or insufficient coverage;
    the effect of litigation and contingencies; and
    our inability to achieve our plans or carry out our strategy.
          Many of these factors are beyond our ability to control or predict. Any of these factors, or a combination of these factors, could materially affect our future financial condition or results of operations and the ultimate accuracy of the forward-looking statements. These forward-looking statements are not guarantees of our future performance, and our actual results and future developments may differ materially from those projected in the forward-looking statements. Management cautions against putting undue reliance on forward-looking statements or projecting any future results based on such statements or present or prior earnings levels. In addition, each forward-looking statement speaks only as of the date of the particular statement, and we undertake no obligation to publicly update or revise any forward-looking statements except as required by applicable law.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
          We are currently exposed to market risk from changes in interest rates. From time to time, we may enter into derivative financial instrument transactions to manage or reduce our market risk, but we do not enter into derivative transactions for speculative purposes. A discussion of our market risk exposure in financial instruments follows.
          Interest Rate Exposure
          We are subject to interest rate risk on our fixed-interest and variable-interest rate borrowings. Variable rate debt, where the interest rate fluctuates periodically, exposes us to short-term changes in market interest rates. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes us to changes in market interest rates reflected in the fair value of the debt and to the risk that we may need to refinance maturing debt with new debt at a higher rate.
          As of September 30, 2009, the long-term borrowings that were outstanding subject to fixed interest rate risk consisted of the 7.375% Senior Notes due April 2018 and the 3.375% Convertible Senior Notes due June 2038. The carrying amount of the 7.375% Senior Notes was $3.5 million. The carrying amount of the 3.375% Convertible Senior Notes was $82.3 million.
          As of September 30, 2009, the interest rate for the $865.9 million outstanding under the term loan was 8.5%. If the interest rate averaged 1% more for 2009 than the rates as of September 30, 2009, annual interest expense would increase by approximately $8.7 million. This sensitivity analysis assumes there are no changes in our financial structure and excludes the impact of our derivatives.
          The fair value of our 3.375% Convertible Senior Notes and term loan facility is estimated based on quoted prices in active markets. We believe the carrying value of our short-term debt instruments outstanding at December 31, 2008 approximate fair value. The following table provides the carrying value and fair value of our long-term debt instruments:
                                 
    September 30, 2009   December 31, 2008
    Carrying   Fair   Carrying   Fair
    Value   Value   Value   Value
            (in millions)        
Term Loan Facility, due July 2013
  $ 865.9     $ 844.3     $ 886.5     $ 571.8  
3.375% Convertible Senior Notes due June 2038
    82.3       71.6       134.8       77.2  
7.375% Senior Notes, due April 2018 (a)
    3.5       n/a       3.5       n/a  
 
(a)   The 7.375% Senior Notes have not been traded in recent periods and we believe that the fair value would not materially differ from the carrying value.
          Interest Rate Swaps and Derivatives
          We manage our debt portfolio to achieve an overall desired position of fixed and floating rates and may employ hedge transactions such as interest rate swaps and zero cost LIBOR collars as tools to achieve that goal. The major risks from interest rate derivatives include changes in the interest rates affecting the fair value of such instruments, potential increases in interest expense due

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to market decreases in floating interest rates and the creditworthiness of the counterparties in such transactions. The counterparties to our interest rate swaps and zero cost LIBOR collar are creditworthy multinational commercial banks. We believe that the risk of counterparty nonperformance is not currently material, but counterparty risk has recently increased throughout the financial system. Our interest expense was increased by $5.6 million and $14.0 million for the three and nine months ended September 30, 2009, respectively and $3.0 million and $7.3 million for the three and nine months ended September 30, 2008, respectively, as a result of our interest rate derivative transactions. (See the information set forth under the caption “Debt” in Part 1, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations- Liquidity and Capital Resources.)
          In connection with the credit facility, in July 2007, we entered into hedge transactions with the purpose of fixing the interest rate on decreasing notional amounts beginning with $400.0 million with a settlement date of December 31, 2007 and ending with $50.0 million which was settled on April 1, 2009. We also entered into a zero cost LIBOR collar on $300.0 million of term loan principal with a final settlement date of October 1, 2010 with a ceiling of 5.75% and a floor of 4.99%.
          In addition, as it relates to our credit facility, in May 2008 we entered into a floating to fixed interest rate swap with the purpose of fixing the interest rate on varying notional amounts beginning with $100.0 million with a settlement date of October 1, 2008 and ending with $75.0 million with a settlement date of December 31, 2009.
          As a result of the inclusion of a LIBOR floor in the amended Credit Agreement, we do not believe, as of July 27, 2009 and on an ongoing basis, that the interest rate swaps and collars will be highly effective in achieving offsetting changes in cash flows attributable to the hedged interest rate risk during the period that the hedge was designated. As such, we have prospectively discontinued cash flow hedge accounting for the interest rate swaps and collars as of July 27, 2009 and will no longer apply cash flow hedge accounting to these instruments. Because cash flow hedge accounting will not be applied to these instruments, changes in fair value related to the interest rate swaps and collars subsequent to July 27, 2009 will be recorded in earnings on a go-forward basis.
ITEM 4. CONTROLS AND PROCEDURES
          We carried out an evaluation, under the supervision and with the participation of our management, including John T. Rynd, our Chief Executive Officer and President, and Lisa W. Rodriguez, our Senior Vice President and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 as of the end of the period covered by this quarterly report. Based upon that evaluation, Mr. Rynd and Ms. Rodriguez, acting in their capacities as our principal executive officer and our principal financial officer, concluded that, as of September 30, 2009, our disclosure controls and procedures were effective, in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the SEC’s rules and forms, of information required to be disclosed by us in the reports that we file or submit under the Exchange Act.
          There were no changes in our internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
     The information set forth under the caption “Legal Proceedings” in Note 12 of the Notes to Unaudited Consolidated Financial Statements in Item 1 of Part 1 of this report is incorporated by reference in response to this item.
ITEM 1A. RISK FACTORS
          Except for the additional and updated disclosures set forth below, for additional information about our risk factors, see Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2008 and Item 1A of Part II of our quarterly report on Form 10-Q for the quarter ended June 30, 2009.
Our business depends on the level of activity in the oil and natural gas industry, which is significantly affected by volatile oil and natural gas prices.
          Our business depends on the level of activity in oil and natural gas exploration, development and production in the U.S. Gulf of Mexico and internationally, and in particular, the level of exploration, development and production expenditures of our customers. Demand for our drilling services is adversely affected by declines associated with depressed oil and natural gas prices. Even the perceived risk of a decline in oil or natural gas prices often causes oil and gas companies to reduce spending on exploration, development and production. Reductions in capital expenditures of our customers have reduced rig utilization and day rates. In particular, changes in the price of natural gas materially affect our operations because drilling in the shallow-water U.S. Gulf of Mexico is primarily focused on developing and producing natural gas reserves. However, higher prices do not necessarily translate

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into increased drilling activity since our clients’ expectations about future commodity prices typically drive demand for our services. Oil and natural gas prices are extremely volatile and have recently declined considerably. On July 2, 2008 natural gas prices were $13.31 per million British thermal unit, or MMBtu, at the Henry Hub. They subsequently declined sharply, reaching a low of $1.88 per MMBtu at the Henry Hub on September 4, 2009. As of October 26, 2009, the closing price of natural gas at the Henry Hub was $ 4.51 per MMBtu. The spot price for West Texas intermediate crude has recently ranged from a high of $145.29 per barrel as of July 3, 2008, to a low of $31.41 per barrel as of December 22, 2008, with a closing price of $78.68 per barrel as of October 26, 2009. Commodity prices are affected by numerous factors, including the following:
    the demand for oil and natural gas in the United States and elsewhere;
 
    the cost of exploring for, developing, producing and delivering oil and natural gas, and the relative cost of onshore production or importation of natural gas;
 
    political, economic and weather conditions in the United States and elsewhere;
 
    imports of liquefied natural gas;
 
    expectations regarding future commodity prices;
 
    advances in exploration, development and production technology;
 
    the ability of the Organization of Petroleum Exporting Countries, commonly called “OPEC,” to set and maintain production levels and pricing;
 
    the level of production in non-OPEC countries;
 
    domestic and international tax policies and governmental regulations;
 
    the development and exploitation of alternative fuels, and the competitive, social and political position of natural gas as a source of energy compared with other energy sources;
 
    the policies of various governments regarding exploration and development of their oil and natural gas reserves;
 
    the worldwide military and political environment and uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or other crises in the Middle East, West Africa and other significant oil and natural gas producing regions; and
 
    acts of terrorism or piracy that affect our areas of operations, especially in Nigeria, where armed conflict, civil unrest and acts of terrorism have recently increased.
As a result of the worldwide recession, reduction in the demand for drilling and liftboat services has materially eroded dayrates and utilization rates for our units, adversely affecting our financial condition and results of operations. The current worldwide recession has led to a sharp decline in energy consumption, which has materially and adversely affected our results of operations. Continued hostilities in the Middle East and West Africa and the occurrence or threat of terrorist attacks against the United States or other countries could contribute to the current recession in the economies of the United States and other countries where we operate. A sustained or deeper recession could further limit economic activity and thus result in an additional decrease in energy consumption, which in turn would cause our revenues and margins to further decline and limit our future growth prospects.
The offshore service industry is highly cyclical and is currently experiencing low demand and low dayrates. The volatility of the industry, coupled with our short-term contracts, has resulted and could continue to result in sharp declines in our profitability.
          Historically, the offshore service industry has been highly cyclical, with periods of high demand and high dayrates often followed by periods of low demand and low dayrates. Periods of low demand, such as the current recession, intensify the competition in the industry and often result in rigs or liftboats being idle for long periods of time. In response to the current recession, we have stacked additional rigs and liftboats and entered into lower dayrate contracts. As a result of the cyclicality of our industry, we expect our results of operations to be volatile and to decrease during market declines such as the current recession.
Maintaining idle rigs or the sale of assets below their then carrying value may cause us to experience losses and may result in impairment charges.
          Prolonged periods of low rig utilization and dayrates, the cold stacking of idle rigs or the sale of assets below their then carrying value may cause us to experience losses. These events may also result in the recognition of impairment charges on certain of our drilling rigs if future cash flow estimates, based upon information available to management at the time, indicate that their carrying value may not be recoverable or if we sell assets at below their then current carrying value.

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Our amended credit agreement imposes significant additional costs and operating and financial restrictions on us, which may prevent us from capitalizing on business opportunities and taking certain actions.
          Our amended credit agreement imposes significant additional costs and operating and financial restrictions on us. These restrictions limit our ability to, among other things:
    make certain types of loans and investments;
 
    pay dividends, redeem or repurchase stock, prepay, redeem or repurchase other debt or make other restricted payments;
 
    incur or guarantee additional indebtedness;
 
    use proceeds from asset sales, new indebtedness or equity issuances for general corporate purposes or investment into our current business;
 
    invest in certain new joint ventures;
 
    create or incur liens;
 
    place restrictions on our subsidiaries’ ability to make dividends or other payments to us;
 
    sell our assets or consolidate or merge with or into other companies;
 
    engage in transactions with affiliates; and
 
    enter into new lines of business.
          In addition, under our amended credit agreement, we are required to prepay our term loan with 100% of our excess cash flow for the fiscal year ending December 31, 2009 and, thereafter, 50% of our excess cash flow through the fiscal year ending December 31, 2012. Our term loan must also be prepaid using the proceeds from unsecured debt issuances (with the exception of refinancing), secured debt issuances and sales of assets in excess of $25 million annually, as well as 50% of proceeds from equity issuances (excluding those for permitted acquisitions or to meet the minimum liquidity requirements) unless we have achieved a specified leverage ratio. The amended credit agreement imposes additional costs on us, including higher interest rates with respect to the debt outstanding under our credit facility. Our amended credit agreement also imposes significant financial and operating restrictions on us. These restrictions will further limit our ability to acquire assets, except in cases in which the consideration is equity (the net cash proceeds of an issuance thereof) or we are in compliance with our financial covenants as they existed prior to the amendment of the credit agreement. Our compliance with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures, finance our acquisitions, equipment purchases and development expenditures, or withstand the present or any future downturn in our business.
If we are unable to comply with the restrictions and covenants in our amended credit agreement, there could be a default, which could result in an acceleration of repayment of funds that we have borrowed.
Our credit agreement requires that we meet certain financial ratios and tests. Effective July 27, 2009, we entered into an amendment of our credit agreement to provide additional flexibility in certain financial covenants. However, there can be no assurance that we will be able to comply with the modified financial covenants. Furthermore, the amendment to our credit agreement also imposes additional and different covenants and restrictions, including the imposition of a requirement to maintain a minimum level of liquidity at all times. Our ability to comply with these financial covenants and restrictions can be affected by events beyond our control. Continued reduced activity levels in the oil and natural gas industry could adversely impact our ability to comply with such covenants in the future. Our failure to comply with such covenants would result in an event of default under the credit agreement. An event of default could prevent us from borrowing under our revolving credit facility, which could in turn have a material adverse effect on our available liquidity. In addition, an event of default could result in our having to immediately repay all amounts outstanding under the Credit Facility and in foreclosure of liens on our assets. As of September 30, 2009, we were in compliance with all of our financial covenants under the credit agreement.

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Our contracts are generally short term, and we will experience reduced profitability if our customers reduce activity levels or terminate or seek to renegotiate our drilling or liftboat contracts or if we experience downtime, operational difficulties, or safety-related issues.
          Currently, all of our drilling contracts with major customers are dayrate contracts, where we charge a fixed charge per day regardless of the number of days needed to drill the well. Likewise, under our current liftboat contracts, we charge a fixed fee per day regardless of the success of the operations that are being conducted by our customer utilizing our liftboat. During depressed market conditions, a customer may no longer need a rig or liftboat that is currently under contract or may be able to obtain a comparable rig or liftboat at a lower daily rate. As a result, customers may seek to renegotiate the terms of their existing drilling contracts or avoid their obligations under those contracts. In addition, our customers may have the right to terminate, or may seek to renegotiate, existing contracts if we experience downtime, operational problems above the contractual limit or safety-related issues, if the rig or liftboat is a total loss, if the rig or liftboat is not delivered to the customer within the period specified in the contract or in other specified circumstances, which include events beyond the control of either party.
          In the U.S. Gulf of Mexico, contracts are generally short term, and oil and natural gas companies tend to reduce activity levels quickly in response to downward changes in oil and natural gas prices. Due to the short-term nature of most of our contracts, a decline in market conditions can quickly affect our business if customers reduce their levels of operations.
          Some of our contracts with our customers include terms allowing them to terminate contracts without cause, with little or no prior notice and without penalty or early termination payments. In addition, we could be required to pay penalties if some of our contracts with our customers are terminated due to downtime, operational problems or failure to deliver. Some of our other contracts with customers may be cancelable at the option of the customer upon payment of a penalty, which may not fully compensate us for the loss of the contract. Early termination of a contract may result in a rig or liftboat being idle for an extended period of time. The likelihood that a customer may seek to terminate a contract is increased during periods of market weakness. In the first two quarters of 2009, certain of our customers, both domestically and internationally, have sought early termination of their contracts with us. If our customers cancel some of our significant contracts, such as the contracts in our International Offshore segment, and we are unable to secure new contracts on substantially similar terms, our revenues and profitability would be materially reduced.
We can provide no assurance that our current backlog of contract drilling revenue will be ultimately realized.
          As of October 27, 2009, our total contract drilling backlog for our Domestic Offshore, International Offshore, International Liftboats and Inland segments was approximately $538.9 million. We calculate our contract revenue backlog, or future contracted revenue, as the contract dayrate multiplied by the number of days remaining on the contract, assuming full utilization. Backlog excludes revenues for mobilization, demobilization, contract preparation and customer reimbursables. We may not be able to perform under our drilling contracts due to various operational factors, including unscheduled repairs, maintenance, operational delays, health, safety and environmental incidents, weather events in the Gulf of Mexico and elsewhere and other factors (some of which are beyond our control), and our customers may seek to cancel or renegotiate our contracts for various reasons, including the financial crisis or falling commodity prices. 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 inability or the inability of our customers to perform under our or their contractual obligations may have a material adverse effect on our financial position, results of operations and cash flows.
A small number of customers account for a significant portion of our revenues, and the loss of one or more of these customers could adversely affect our financial condition and results of operations.
     We derive a significant amount of our revenue from a few energy companies. Chevron Corporation represented approximately 12%, 21% and 35% of our consolidated revenues for the years ended December 31, 2008, 2007, and 2006, respectively. In addition, Oil and Natural Gas Corporation Limited, Chevron, Saudi Aramco and Pemex Exploración y Producción (“PEMEX”) accounted for 16%, 15%, 13% and 11% of our revenues for the nine months ended September 30, 2009, respectively. Our financial condition and results of operations will be materially adversely affected if these customers interrupt or curtail their activities, terminate their contracts with us, fail to renew their existing contracts or refuse to award new contracts to us and we are unable to enter into contracts with new customers at comparable dayrates. The loss of any of our significant customers could adversely affect our financial condition and results of operations.

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ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
          The following table set forth for the periods indicated certain information with respect to our purchases of our Common Stock:
                                 
                    Total Number of    
                    Shares Purchased   Maximum Number
                    as Part of a   of Shares That
    Total Number of           Publicly   May Yet Be
    Shares of   Average Price   Announced Plan   Purchased Under
Period   Purchased (1)   Paid per Share   (2)   Plan (2)
July 1-31, 2009
    2,647     $ 3.25       N/A       N/A  
August 1-31, 2009
    1,400       4.62       N/A       N/A  
September 1-30, 2009
    618       5.08       N/A       N/A  
 
                               
Total
    4,665       3.90       N/A       N/A  
 
                               
 
(1)   Represents the surrender of shares of common stock to satisfy tax withholding obligations in connection with the vesting of restricted stock issued to employees under our stockholder-approved long-term incentive plan.
 
(2)   We did not have at any time during the quarter, and currently do not have, a share repurchase program in place.
ITEM 6. EXHIBITS
1.1   Underwriting Agreement, dated September 24, 2009, by and between Hercules Offshore, Inc. and Morgan Stanley & Co. Incorporated and UBS Securities LLC, as representatives of the underwriters named in Schedule A thereto (incorporated by reference to Exhibit 1.1 to Hercules’ Current Report on Form 8-K dated September 30, 2009).
 
4.1   Indenture dated as of October 20, 2009, by and among Hercules Offshore, Inc., the Guarantors named therein and U.S. Bank National Association as Trustee and Collateral Agent (incorporated by reference to Exhibit 4.1 to Hercules’ Current Report on Form 8-K dated October 26, 2009).
 
4.2   Form of 10.50% Senior Secured Note due 2017 (incorporated by reference to Exhibit 4.2 to Hercules’ Current Report on Form 8-K dated October 26, 2009).
 
4.3   Security Agreement dated as of October 20, 2009, by and among Hercules Offshore, Inc. and the Guarantors party thereto and U.S. Bank National Association as Collateral Agent (incorporated by reference to Exhibit 4.3 to Hercules’ Current Report on Form 8-K dated October 26, 2009).
 
4.4   Registration Rights Agreement dated as of October 20, 2009, by and among Hercules Offshore, Inc., the Guarantors named therein and the Initial Purchasers party thereto (incorporated by reference to Exhibit 4.4 to Hercules’ Current Report on Form 8-K dated October 26, 2009).
 
10.1   Purchase Agreement, dated October 8, 2009, by and among Hercules Offshore, Inc., the guarantors party thereto, UBS Securities LLC, Banc of America Securities LLC, Deutsche Bank Securities Inc. and Morgan Stanley & Co. Incorporated, as representatives of the initial purchasers named in Schedule I thereto (incorporated by reference to Exhibit 10.1 to Hercules’ Current Report on Form 8-K dated October 14, 2009).
 
10.2   Intercreditor Agreement dated as of October 20, 2009, among Hercules Offshore, Inc., the subsidiaries party thereto as guarantors, UBS AG, Stamford Branch, as Bank Collateral Agent and U.S. Bank National Association, as Notes Collateral Agent (incorporated by reference to Exhibit 10.1 to Hercules’ Current Report on Form 8-K dated October 26, 2009).
31.1*     Certification of Chief Executive Officer of Hercules pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
31.2*     Certification of Chief Financial Officer of Hercules pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
32.1*     Certification of the Chief Executive Officer and the Chief Financial Officer of Hercules pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
*   Filed herewith

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SIGNATURES
          Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
         
  HERCULES OFFSHORE, INC.
 
 
  By:   /s/ John T. Rynd    
    John T. Rynd   
    Chief Executive Officer and President
(Principal Executive Officer)
 
 
 
     
  By:   /s/ Lisa W. Rodriguez    
    Lisa W. Rodriguez   
    Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
 
 
     
  By:   /s/ Troy L. Carson    
    Troy L. Carson   
    Vice President and Corporate Controller
(Principal Accounting Officer)
 
 
 
Date: October 29, 2009

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