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

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)

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

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

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

Large accelerated filer o		Accelerated filer þ		Non-accelerated filer o		Smaller reporting company o
				(Do not check if a smaller reporting company)

     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 July 23, 2010
		114,772,344

 

 

HERCULES OFFSHORE, INC.

INDEX

		Page No.
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements:
Consolidated Balance Sheets as of June 30, 2010 and December 31, 2009			3
Consolidated Statements of Operations for the three and six months ended June 30, 2010, and June 30, 2009			4
Consolidated Statements of Cash Flows for the six months ended June 30, 2010 and June 30, 2009			5
Consolidated Statements of Comprehensive Loss for the three and six months ended June 30, 2010, and June 30, 2009			6
Notes to Unaudited Consolidated Financial Statements			7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			23
Item 3. Quantitative and Qualitative Disclosures about Market Risk			44
Item 4. Controls and Procedures			45
PART II. OTHER INFORMATION
Item 1. Legal Proceedings			45
Item 1A. Risk Factors			45
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			46
Item 6. Exhibits			46
Signatures			47
EX-10.1
EX-10.2
EX-10.3
EX-10.4
EX-31.1
EX-31.2
EX-32.1

PART I. FINANCIAL INFORMATION

ITEM 1.		FINANCIAL STATEMENTS

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(In thousands, except par value)

		June 30,				December 31,
		2010				2009
		(Unaudited)
ASSETS
Current Assets:
Cash and Cash Equivalents		$	91,724			$	140,828
Restricted Cash			7,029				3,658
Accounts Receivable, Net of Allowance for Doubtful Accounts of $33,019 and $38,522 as of June 30, 2010 and December 31, 2009, Respectively			161,488				133,662
Prepaids			28,313				13,706
Current Deferred Tax Asset			12,195				22,885
Other			21,067				6,675
			321,816				321,414
Property and Equipment, Net			1,841,652				1,923,603
Other Assets, Net			29,756				32,459
		$	2,193,224			$	2,277,476
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term Debt and Current Portion of Long-term Debt		$	4,924			$	4,952
Insurance Notes Payable			21,930				5,484
Accounts Payable			50,803				51,868
Accrued Liabilities			52,949				67,773
Interest Payable			14,756				6,624
Taxes Payable			—				5,671
Other Current Liabilities			30,895				34,229
			176,257				176,601
Long-term Debt, Net of Current Portion			854,778				856,755
Other Liabilities			8,302				19,809
Deferred Income Taxes			205,283				245,799
Commitments and Contingencies
Stockholders’ Equity:
Common Stock, $0.01 Par Value; 200,000 Shares Authorized; 116,308 and 116,154 Shares Issued, Respectively; 114,762 and 114,650 Shares Outstanding, Respectively			1,163				1,162
Capital in Excess of Par Value			1,922,226				1,921,037
Treasury Stock, at Cost, 1,546 Shares and 1,504 Shares, Respectively			(50,320	)			(50,151	)
Accumulated Other Comprehensive Loss			(1,762	)			(5,773	)
Retained Deficit			(922,703	)			(887,763	)
			948,604				978,512
		$	2,193,224			$	2,277,476

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

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
(Unaudited)

		Three Months Ended June 30,								Six Months Ended June 30,
		2010				2009				2010				2009
Revenues		$	165,895			$	183,691			$	316,744			$	407,182
Costs and Expenses:
Operating Expenses			108,321				116,097				216,957				265,341
Impairment of Property and Equipment			—				26,882				—				26,882
Depreciation and Amortization			48,350				51,091				98,604				99,937
General and Administrative			14,798				15,450				27,101				31,742
			171,469				209,520				342,662				423,902
Operating Loss			(5,574	)			(25,829	)			(25,918	)			(16,720	)
Other Income (Expense):
Interest Expense			(21,259	)			(14,561	)			(42,998	)			(30,350	)
Gain on Early Retirement of Debt, Net			—				13,747				—				13,747
Other, Net			3,183				3,346				3,169				2,690
Loss Before Income Taxes			(23,650	)			(23,297	)			(65,747	)			(30,633	)
Income Tax Benefit			4,666				11,510				30,807				14,335
Loss from Continuing Operations			(18,984	)			(11,787	)			(34,940	)			(16,298	)
Loss from Discontinued Operation, Net of Taxes			—				(242	)			—				(675	)
Net Loss		$	(18,984	)		$	(12,029	)		$	(34,940	)		$	(16,973	)
Basic Loss Per Share:
Loss from Continuing Operations		$	(0.17	)		$	(0.13	)		$	(0.30	)		$	(0.18	)
Loss from Discontinued Operation			—				(0.01	)			—				(0.01	)
Net Loss		$	(0.17	)		$	(0.14	)		$	(0.30	)		$	(0.19	)
Diluted Loss Per Share:
Loss from Continuing Operations		$	(0.17	)		$	(0.13	)		$	(0.30	)		$	(0.18	)
Loss from Discontinued Operation			—				(0.01	)			—				(0.01	)
Net Loss		$	(0.17	)		$	(0.14	)		$	(0.30	)		$	(0.19	)
Weighted Average Shares Outstanding:
Basic			114,757				88,733				114,727				88,368
Diluted			114,757				88,733				114,727				88,368

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

CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)

		Six Months Ended June 30,
		2010				2009
Cash Flows from Operating Activities:
Net Loss		$	(34,940	)		$	(16,973	)
Adjustments to Reconcile Net Loss to Net Cash Provided by (Used In) Operating Activities:
Depreciation and Amortization			98,604				99,937
Stock-Based Compensation Expense			1,817				4,115
Deferred Income Taxes			(32,311	)			(25,063	)
Provision (Benefit) for Doubtful Accounts Receivable			(1,771	)			543
Amortization of Deferred Financing Fees			1,683				2,096
Amortization of Original Issue Discount			1,998				2,386
Non-Cash Loss on Derivatives			2,835				—
Gain on Insurance Settlement			—				(8,700	)
Gain on Disposal of Assets			(6,729	)			(332	)
Gain on Early Retirement of Debt, Net			—				(13,747	)
Impairment of Property and Equipment			—				26,882
Excess Tax Benefits from Stock-Based Arrangements			(377	)			(5,031	)
(Increase) Decrease in Operating Assets -
Accounts Receivable			(26,055	)			64,738
Prepaid Expenses and Other			13,027				8,383
Increase (Decrease) in Operating Liabilities -
Accounts Payable			(1,065	)			(31,542	)
Insurance Notes Payable			(7,669	)			(13,236	)
Other Current Liabilities			(30,370	)			(5,010	)
Other Liabilities			(12,175	)			(1,946	)
Net Cash Provided by (Used In) Operating Activities			(33,498	)			87,500
Cash Flows from Investing Activities:
Additions of Property and Equipment			(11,015	)			(62,068	)
Deferred Drydocking Expenditures			(7,574	)			(9,662	)
Insurance Proceeds Received			—				8,717
Proceeds from Sale of Assets, Net			9,969				4,722
Increase in Restricted Cash			(3,371	)			—
Net Cash Used in Investing Activities			(11,991	)			(58,291	)
Cash Flows from Financing Activities:
Short-term Debt Repayments			—				(2,455	)
Long-term Debt Repayments			(4,003	)			(2,250	)
Redemption of 3.375% Convertible Senior Notes			—				(6,099	)
Excess Tax Benefits from Stock-Based Arrangements			377				5,031
Other			11				(11	)
Net Cash Used in Financing Activities			(3,615	)			(5,784	)
Net Increase (Decrease) in Cash and Cash Equivalents			(49,104	)			23,425
Cash and Cash Equivalents at Beginning of Period			140,828				106,455
Cash and Cash Equivalents at End of Period		$	91,724			$	129,880

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

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(In thousands)
(Unaudited)

		Three Months Ended June 30,								Six Months Ended June 30,
		2010				2009				2010				2009
Net Loss		$	(18,984	)		$	(12,029	)		$	(34,940	)		$	(16,973	)
Other Comprehensive Income, Net of Taxes:
Changes Related to Hedge Transactions			1,932				1,988				4,011				1,582
Comprehensive Loss		$	(17,052	)		$	(10,041	)		$	(30,929	)		$	(15,391	)

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

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

1. General

     Hercules Offshore, Inc., a Delaware corporation, and its majority owned subsidiaries (the “Company”) provide shallow-water drilling and marine services to the oil and natural gas exploration and production industry globally through its Domestic Offshore, International Offshore, Inland, Domestic Liftboats, International Liftboats and Delta Towing segments (See Note 10). At June 30, 2010, 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 currently owns three retired jackup rigs and two retired inland barges, all located in the U.S. Gulf of Mexico, which are currently not expected to re-enter active service. The Company’s diverse fleet is capable of providing services such as oil and gas exploration and development drilling, well service, platform inspection, maintenance and decommissioning operations in several key shallow water provinces around the world.

     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 June 30, 2010, Consolidated Statements of Operations and Consolidated Statements of Comprehensive Loss for the three and six months ended June 30, 2010 and 2009, and Consolidated Statements of Cash Flows for the six months ended June 30, 2010 and 2009. 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, 2009 and the notes thereto included in the Company’s Annual Report on Form 10-K. The results of operations for the three and six months ended June 30, 2010 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 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 December 2009, the Company entered into an agreement with First Energy Bank B.S.C. (“MENAdrill”) whereby it would market, manage and operate two Friede & Goldman Super M2 design, new-build jackup drilling rigs each with a maximum water depth of 300 feet. The rigs are currently under construction and one is scheduled to be delivered in each of the fourth quarter of 2010 and the first quarter of 2011. The Company is actively marketing the rigs globally on an exclusive basis.

     In January 2010, the Company entered into an agreement with SKDP 1 Ltd., an affiliate of Skeie Drilling & Production ASA, to market, manage and operate an ultra high specification KFELS Class N new-build jackup drilling rig with a maximum water depth of 400 feet. The agreement was limited to a specified opportunity in the Middle East and expired by its terms during the second quarter when the rig was not selected by the operator.

Reclassifications

     Certain reclassifications have been made to conform prior year financial information to the current period presentation.

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, as long as collectability is reasonably assured. For certain contracts, the Company may receive lump-sum fees for the mobilization of equipment and personnel. Mobilization fees received and costs incurred to mobilize a rig from one market to another under contracts longer than ninety days are recognized as services are performed over the term of the related drilling contract. Amounts related to mobilization fees are summarized below (in thousands):

		Three Months Ended June 30,								Six Months Ended June 30,
		2010				2009				2010				2009
Mobilization revenue deferred		$	—			$	—			$	600			$	12,000
Mobilization expense deferred			—				—				—				132
Mobilization revenue recognized			4,134				4,233				7,911				8,149
Mobilization expense recognized			676				700				1,592				1,393

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

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

						As of				As of
		Balance Sheet				June 30,				December 31,
		Classification				2010				2009
Assets:
Deferred Mobilization and Contract Preparation Expense-Current Portion		Other				$	959			$	1,092
Deferred Mobilization and Contract Preparation Expense-Non-Current Portion		Other Assets, Net					23				1,651
Liabilities:
Deferred Mobilization Revenue-Current Portion		Other Current Liabilities					18,910				19,406
Deferred Mobilization Revenue-Non-Current Portion		Other Liabilities					3,502				12,628

Accounts Receivable and Allowance for Doubtful Accounts

     Accounts receivable are stated at the historical carrying amount net of write-offs and allowance for doubtful accounts. Management of the Company monitors the accounts receivable from its customers for any collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent factors. Accounts deemed uncollectible are charged to the allowance. The Company had an allowance of $33.0 million and $38.5 million at June 30, 2010 and December 31, 2009, respectively.

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 both June 30, 2010 and December 31, 2009, were $4.9 million. Amortization expense for drydocking costs was $3.4 million and $7.6 million for the three and six months ended June 30, 2010, respectively and $4.8 million and $8.6 million for the three and six months ended June 30, 2009, 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 June 30, 2010 and December 31, 2009 were $13.0 million and $14.7 million, respectively. The amortization

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

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 $1.7 million for the three and six months ended June 30, 2010, respectively and $1.0 million and $2.1 million for the three and six months ended June 30, 2009, respectively. In addition, the Company recognized a pretax charge of $1.4 million during the second quarter of 2009 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 4).

Cash and Cash Equivalents

     Cash and cash equivalents include cash on hand, demand deposits with banks and all highly liquid investments with original maturities of three months or less.

Restricted Cash

     At June 30, 2010 and December 31, 2009, the Company had restricted cash of $7.0 million and $3.7 million to support surety bonds primarily related to the Company’s Mexico and U.S. operations. In July 2010, the Company increased its restricted cash balance by $6.1 million as additional collateral to support surety bonds related to its Mexico and U.S. operations (See Note 13).

2. Earnings Per Share

     The Company calculates basic earnings per share by dividing net income by the weighted average number of shares outstanding. Diluted earnings per share is computed by dividing net income by the weighted average number of shares outstanding during the period as adjusted for the dilutive effect of the Company’s stock option and restricted stock awards. The effect of stock option and restricted stock awards is not included in the computation for periods in which a net loss occurs, because to do so would be anti-dilutive. Stock equivalents of 6,564,611 and 6,006,817 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 six months ended June 30, 2010, respectively. Stock equivalents of 4,826,061 and 4,343,526 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 six months ended June 30, 2009, respectively.

3. Dispositions

     In December 2009, the Company entered into an agreement to sell its retired jackups Hercules 191 and Hercules 255 for $5.0 million each. The sale of the Hercules 191 was completed in April 2010 for gross proceeds of $5.0 million, resulting in a gain of $3.1 million. The sale of the Hercules 255 is expected to close in the third quarter of 2010. In February 2010, the Company entered into an agreement to sell six of its retired barges for $3.0 million of which $2.2 million in gross proceeds was received during the first quarter of 2010 for the completion of the sale of three of the six barges resulting in a net gain of $1.8 million. The sale of the remaining three barges was completed in April 2010 for gross proceeds of $0.8 million resulting in a gain of $0.4 million. Additionally, in July 2010, the Company entered into an agreement to sell retired jackup Hercules 155 for $4.8 million (See Note 13).

     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. Hercules 100 was classified as “retired” and was stacked in Sabine Pass, Texas, and Hercules 110 was cold-stacked in Trinidad. The closing of the sale of 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 Hercules 110 to fair value less costs to sell during the second quarter of 2009 (See Note 6). The financial information for Hercules 100 has historically been reported as part of the Domestic Offshore Segment and Hercules 110 financial information has been reported as part of the International Offshore Segment.

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

4. Debt

     Debt is comprised of the following (in thousands):

		June 30, 2010				December 31, 2009
Term Loan Facility, due July 2013		$	478,849			$	482,852
10.5% Senior Secured Notes, due October 2017			292,595				292,272
3.375% Convertible Senior Notes, due June 2038			84,746				83,071
7.375% Senior Notes, due April 2018			3,512				3,512
Total Debt			859,702				861,707
Less Short-term Debt and Current Portion of Long-term Debt			4,924				4,952
Total Long-term Debt, Net of Current Portion		$	854,778			$	856,755

Senior secured credit facility

          The Company has a $653.8 million credit facility, consisting of a $478.8 million term loan facility and a $175.0 million revolving credit facility. 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. Under the credit agreement which governs the credit facility (the “Credit Agreement”), the Company must comply with the following:

•

The total leverage ratio for any test period is calculated as the ratio of consolidated indebtedness on the test date to consolidated EBITDA for the trailing twelve months, all as defined in the Credit Agreement.

		Maximum
Test Date		Total Leverage Ratio
September 30, 2010		8.00 to 1.00
December 31, 2010		7.50 to 1.00
March 31, 2011		7.00 to 1.00
June 30, 2011		6.75 to 1.00
September 30, 2011		6.00 to 1.00
December 31, 2011		5.50 to 1.00
March 31, 2012		5.25 to 1.00
June 30, 2012		5.00 to 1.00
September 30, 2012		4.75 to 1.00
December 31, 2012		4.50 to 1.00
March 31, 2013		4.25 to 1.00
June 30, 2013		4.00 to 1.00

-

At June 30, 2010, the Company’s total leverage ratio was 8.09. There is no maximum total leverage requirement for the period ended June 30, 2010.

	•		Maintain a minimum level of liquidity, measured as the amount of unrestricted cash and cash equivalents on hand and availability under the revolving credit facility, of (i) $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. As of June 30, 2010, as calculated pursuant to the Credit Agreement, the Company’s total liquidity was $256.7 million.
	•		Maintain a minimum fixed charge coverage ratio as follows:

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

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

-

The consolidated fixed charge coverage ratio for any test period is defined as the sum of consolidated EBITDA for the test period plus an amount that may be added for the purpose of calculating the ratio for such test period, not to exceed $130.0 million in total during the term of the credit facility, to consolidated fixed charges for the test period, all as defined in the Credit Agreement. As of June 30, 2010, the Company’s fixed charge coverage ratio was 1.0.

•

Mandatory prepayments of debt outstanding under the Credit Agreement with 50% of excess cash flow as defined in the Credit Agreement for the fiscal years ending December 31, 2010, 2011 and 2012, and with proceeds from:

	-		unsecured debt issuances, with the exception of refinancing;
	-		secured debt issuances;
	-		casualty events not used to repair damaged property;
	-		sales of assets in excess of $25 million annually; and
	-		unless the Company has achieved a specified leverage ratio, 50% of proceeds from equity issuances, excluding those for permitted acquisitions or to meet the minimum liquidity requirements.

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

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

     The Credit Agreement requires that the Company meet certain financial ratios and tests, which it met as of June 30, 2010. 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 facility, the 10.5% Senior Secured Notes and the 3.375% Convertible Senior Notes and in the foreclosure of liens on its assets.

     As of June 30, 2010, 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. Other than the required prepayments as outlined previously, the principal amount of the term loan amortizes in equal quarterly installments of approximately $1.2 million, with the balance due on July 11, 2013. All borrowings under the revolving credit facility mature on July 11, 2012. Interest payments on both the revolving and term loan facility are due at least on a quarterly basis and in certain instances, more frequently. As of June 30, 2010, $478.8 million was outstanding on the term loan facility and the interest rate was 6.00%. The annualized effective interest rate was 9.07% for the six months ended June 30, 2010 after giving consideration to revolver fees and derivative activity.

10.5% senior secured notes due 2017

     The notional amount of the 10.5% Senior Secured Notes, its unamortized discount and its net carrying amount was $300.0 million, $7.4 million and $292.6 million, respectively, as of June 30, 2010 and $300.0 million, $7.7 million and $292.3 million, respectively, as of December 31, 2009. The unamortized discount is being amortized to interest expense over the life of the 10.5% Senior Secured Notes which ends in October 2017. During the three months ended June 30, 2010, the Company recognized $8.0 million, $5.2 million, net of tax, in interest expense, or $0.05 per diluted share, at an effective rate of 11%, of which $7.8 million related to the coupon rate of 10.5% and $0.2 million related to discount amortization. During the six months ended June 30, 2010, the Company recognized $16.0 million, $10.4 million, net of tax, in interest expense, or $0.09 per diluted share, at an effective rate of 11%, of which $15.7 million related to the coupon rate of 10.5% and $0.3 million related to discount amortization. There was no interest expense recognized during the three or six months ended June 30, 2009 as the 10.5% Senior Secured Notes were issued in October 2009.

     The notes are guaranteed by all of the Company’s existing and future restricted subsidiaries that incur or guarantee indebtedness under a credit facility, including the Company’s existing credit facility. The notes are secured by liens on all collateral that secures the Company’s obligations under its secured credit facility, subject to limited exceptions. The liens securing the notes share on an equal

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

and ratable first priority basis with liens securing the Company’s credit facility. Under the intercreditor agreement, the collateral agent for the lenders under the Company’s secured credit facility is generally entitled to sole control of all decisions and actions.

     All the liens securing the notes may be released if the Company’s secured indebtedness, other than these notes, does not exceed the lesser of $375.0 million and 15.0% of 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 indebtedness, other than these notes, exceeds the greater of $375.0 million and 15.0% of its consolidated tangible assets, as defined in the indenture, then the collateral obligations of the Company and guarantors will be reinstated and must be complied with within 30 days of such event.

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

	•		incur additional indebtedness or issue certain preferred stock;
	•		pay dividends or make other distributions;
	•		make other restricted payments or investments;
	•		sell assets;
	•		create liens;
	•		enter into agreements that restrict dividends and other payments by restricted subsidiaries;
	•		engage in transactions with its affiliates; and
	•		consolidate, merge or transfer all or substantially all of its assets.

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

     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, as defined in the indenture, 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 a change of control, as defined, 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

     The carrying amount of the equity component of the 3.375% Convertible Senior Notes was $30.1 million at both June 30, 2010 and December 31, 2009. 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, $11.2 million and $84.7 million, respectively, as of June 30, 2010 and $95.9 million, $12.8 million and $83.1 million, respectively, as of December 31, 2009. The unamortized discount is being amortized to interest expense over the expected life of the 3.375% Convertible Senior Notes which ends June 1, 2013. During the three months ended June 30, 2010, 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 six months ended June 30, 2010, the Company recognized $3.3 million, $2.1 million, net of tax, in interest expense, or $0.02 per diluted share, at an effective rate of 7.93%, of which $1.6 million related to the coupon rate of 3.375% and $1.7

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

million related to discount amortization. During the three months ended June 30, 2009, the Company recognized $2.2 million, $1.5 million, net of tax, in interest expense, or $0.02 per diluted share, at an effective rate of 7.93%, of which $1.1 million related to the coupon rate of 3.375% and $1.1 million related to discount amortization. During the six months ended June 30, 2009, the Company recognized $4.9 million, $3.2 million, net of tax, in interest expense, or $0.04 per diluted share, at an effective rate of 7.93%, of which $2.5 million related to the coupon rate of 3.375% and $2.4 million related to discount amortization.

     The notes will be convertible under certain circumstances into shares of the Company’s common stock (“Common Stock”) at an initial conversion rate of 19.9695 shares of Common Stock per $1,000 principal amount of notes, which is equal to an initial conversion price of approximately $50.08 per share. Upon conversion of a note, a holder will receive, at the Company’s election, shares of Common Stock, cash or a combination of cash and shares of Common Stock. At June 30, 2010, the number of conversion shares potentially issuable in relation to the 3.375% Convertible Senior Notes was 1.9 million.

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

     The Company determined that upon maturity or redemption it has the intent and ability to settle the principal amount of its 3.375% Convertible Senior Notes in cash, and any additional conversion consideration spread (the excess of conversion value over face value) in shares of the Company’s Common Stock. There were no stock equivalents to exclude from the calculation of the dilutive effect of stock equivalents for the diluted earnings per share calculations for the three and six months ended June 30, 2010 and 2009 related to the assumed conversion of the 3.375% Convertible Senior Notes under the if-converted method as there was no excess of conversion value over face value in any of these periods. 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 shares of 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. In accordance with Financial Accounting Standards Board’s (“FASB”) Accounting Standards Codification (“ASC”) Topic 470-20, Debt – Debt with Conversion and Other Options, 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.

Fair value estimate

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

		June 30, 2010								December 31, 2009
		Carrying				Fair				Carrying				Fair
		Value				Value				Value				Value
						(in millions)
Term Loan Facility, due July 2013		$	478.8			$	421.4			$	482.9			$	468.4
10.5% Senior Secured Notes, due October 2017			292.6				265.9				292.3				315.8
3.375% Convertible Senior Notes, due June 2038			84.7				70.0				83.1				76.8
7.375% Senior Notes, due April 2018			3.5				2.4				3.5				3.0

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

5. 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.

     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 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 which was settled on December 31, 2009. The Company received an interest rate of three-month LIBOR and paid 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. 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 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 Credit Agreement, the Company does not believe, as of July 27, 2009 and on an ongoing basis, that the interest rate swap and collar 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 swap and collar as of July 27, 2009 and no longer applies 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 swap and collar subsequent to July 27, 2009 have been recorded in earnings and will be on a go-forward basis. As a result of discontinuing the cash flow hedging relationship, the Company recognized an increase in fair value of $0.1 million and a decrease in fair value of $0.3 million related to the hedge ineffectiveness of its collar as Interest Expense in its Consolidated Statements of Operations for the three and six months ended June 30, 2010, respectively. The Company did not recognize a gain or loss due to hedge ineffectiveness in its Consolidated Statements of Operations for the three and six months ended June 30, 2009 related to interest rate derivative instruments. The Company expects to realize all of the unrealized loss in the Consolidated Statements of Operations during 2010.

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

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

June 30, 2010						December 31, 2009
Balance Sheet		Fair				Balance Sheet		Fair
Classification		Value				Classification		Value
Derivatives(a):
Interest rate contracts:
Other		$	—			Other		$	—
Total Asset Derivatives		$	—			Total Asset Derivatives		$	—
Other Current Liabilities		$	6,976			Other Current Liabilities		$	10,312
Other Liabilities			—			Other Liabilities			—
Total Liability Derivatives		$	6,976			Total Liability Derivatives		$	10,312

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

		Three Months Ended June 30,
		2010				2009								2010				2009								2010				2009
Derivatives(a)		I.								II.				III.								IV.				V.
Interest rate contracts		$	—			$	(605	)		Interest Expense				$	(2,972	)		$	(3,989	)		Interest Expense				$	104			$	—

					Six Months Ended June 30,
		2010				2009								2010				2009								2010				2009
Derivatives(a)		I.								II.				III.								IV.				V.
Interest rate contracts		$	—			$	(3,880	)		Interest Expense				$	(6,170	)		$	(8,403	)		Interest Expense				$	(259	)		$	—

A summary of the changes in Accumulated Other Comprehensive Loss (in thousands):

Cumulative unrealized loss, net of tax of $3,108, as of December 31, 2009		$	(5,773	)
Reclassification of losses into net income, net of tax of $2,159			4,011
Cumulative unrealized loss, net of tax of $949, as of June 30, 2010		$	(1,762	)

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

6. Fair Value Measurements

     FASB ASC 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 ASC 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.

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)

     As of January 1, 2010, the Company adopted the FASB Accounting Standards Update (“ASU”) No. 2010-06, Improving Disclosures about Fair Value Measurements (“ASU 2010-06”) which requires additional disclosures about the various classes of assets and liabilities measured at fair value, the valuation techniques and inputs used, the activity in Level 3 fair value measurements and the transfers between Levels 1, 2, & 3. The requirement for disclosures about purchases, sales, issuances and settlements in the roll forward of activity in Level 3 fair value measurements are effective for interim and annual reporting periods beginning after December 15, 2010 and will be adopted by the Company on January 1, 2011 (See Note 12).

     As of June 30, 2010 the fair value of the Company’s interest rate derivative was in a liability position in the amount of $7.0 million. The fair value of the interest rate derivative was determined based on a discounted cash flow approach using market observable inputs including forward interest rates and credit spreads.

     The following table represents our derivative liabilities measured at fair value on a recurring basis as of June 30, 2010 (in thousands):

Quoted Prices in

Total

Active Markets for

Fair Value

Identical Asset or

Significant Other

Significant

Measurement

Liability

Observable Inputs

Unobservable Inputs

Valuation

June 30, 2010

(Level 1)

(Level 2)

(Level 3)

Technique

Interest Rate Contracts

$

6,976

$

—

$

6,976

$

—

A

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

     The following table represents our derivative liabilities measured at fair value on a recurring basis as of December 31, 2009 (in thousands):

Quoted Prices in

Total

Active Markets for

Fair Value

Identical Asset or

Significant Other

Significant

Measurement

Liability

Observable Inputs

Unobservable Inputs

Valuation

December 31, 2009

(Level 1)

(Level 2)

(Level 3)

Technique

Interest Rate Contracts

$

10,312

$

—

$

10,312

$

—

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 December 31, 2009 (in thousands):

Quoted Prices in

Total

Active Markets for

Fair Value

Identical Asset or

Significant Other

Significant

Measurement

Liability

Observable Inputs

Unobservable Inputs

Valuation

Total

December 31, 2009

(Level 1)

(Level 2)

(Level 3)

Technique

Gain (Loss)

Assets Held for Sale

$

—

$

—

$

—

$

—

A

$

(26,882

)

     The Company realized approximately $26.9 million ($13.1 million, net of tax) of impairment charges related to the write-down of Hercules 110 to fair value less costs to sell during the second quarter of 2009 (See Note 3). The sale of Hercules 110 was completed in August 2009 (See Note 3).

7. Stock-based Compensation

     The Company’s 2004 Long-Term Incentive Plan (the “2004 Plan”) provides for the granting of stock options, restricted stock, performance stock awards and other stock-based awards to selected employees and non-employee directors of the Company. At June 30, 2010, approximately 2.3 million shares were available for grant or award under the 2004 Plan.

     During the six months ended June 30, 2010, the Company granted 1,355,000 stock options with a weighted average exercise price of $3.77 and 782,532 restricted stock awards with a weighted average grant-date fair value per share of $3.79. The Company recognized $1.7 million and $1.8 million in stock-based compensation expense during the three and six months ended June 30, 2010, respectively, which includes a reduction of $0.3 million and $2.1 million due to a change in the Company’s estimated forfeiture rate, respectively. The Company recognized $2.1 million and $4.1 million in stock-based compensation expense during the three and six months ended June 30, 2009, respectively.

     The unrecognized compensation cost related to the Company’s unvested stock options and restricted stock grants as of June 30, 2010 was $4.0 million and $4.3 million, respectively, and is expected to be recognized over a weighted-average period of 1.8 years and 1.7 years, respectively.

8. Supplemental Cash Flow Information

     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 shares of 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 4).

		Six Months Ended June 30,
		2010				2009
		(In thousands)
Cash paid during the period for:
Interest, net of capitalized interest		$	28,628			$	14,982
Income taxes			23,603				12,038

     During the six months ended June 30, 2009, the Company capitalized interest of $0.3 million. There was no interest capitalized during the six months ended June 30, 2010.

9. Income Tax

     In connection with the July 2007 acquisition of TODCO, the Company, as successor to TODCO, and TODCO’s former parent, Transocean Ltd., are parties to a tax sharing agreement that was originally entered into in connection with TODCO’s initial public offering in 2004. The tax sharing agreement was amended and restated in November 2006 in a negotiated settlement of disputes between Transocean and TODCO over the terms of the original tax sharing agreement. The tax sharing agreement continues to require that additional payments be made to Transocean based on a portion of the expected tax benefit from the exercise of certain compensatory stock options to acquire Transocean common stock attributable to current and former TODCO employees and board members. The estimated amount of payments to Transocean related to compensatory options that remain outstanding at June 30, 2010, assuming a Transocean stock price of $46.33 per share at the time of exercise of the compensatory options (the actual price of Transocean’s common stock at June 30, 2010), is approximately $0.1 million. The Company accounts for the exercise of Transocean

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

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 tax benefit and increases additional paid-in capital by 45% of the tax benefit. 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, an income tax return for 2004 is currently under examination. The timing and effect on the Company’s consolidated financial statements of the resolution of this income tax examination 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 $0.8 million (based on the official exchange rate at June 30, 2010). 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 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. In accordance with local statutory requirements, we provided a surety bond for an amount equal to $13.2 million as of June 30, 2010, which was released in July 2010, to contest these assessments (See Notes 11 and 13). In 2008, the Mexican tax authorities commenced an audit for the 2005 tax year. During the quarter ended March 31, 2010, the Company effectively reached a compromise settlement of all issues for 2004–2007 in the amount of approximately $10.8 million, of which $5.7 million relating to 2004-2005 was paid as of June 30, 2010. The amount attributed to 2006-2007 is expected to be paid in the third quarter of 2010. This resulted in the Company reversing previously provided reserves and an associated tax benefit in the year in the amount of approximately $6.0 million. The criteria for “effective settlement” of this reserve is that the tax authority has completed all its examination procedures, the Company does not intend to appeal and the possibility is remote that the tax authority would reexamine any aspect of the tax position.

     As of June 30, 2010, the Company had Taxes Receivable of $16.9 million which is included in Other on the Consolidated Balance Sheets.

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

10. Segments

     The Company reports its business activities in six business segments: (1) Domestic Offshore, (2) International Offshore, (3) Inland, (4) Domestic Liftboats, (5) International Liftboats and (6) Delta Towing. The financial information of the Company’s discontinued operation is not included in the financial information presented for the Company’s reporting segments. The Company eliminates inter-segment revenue and expenses, if any.

     The following describes the Company’s reporting segments as of June 30, 2010:

     Domestic Offshore — includes 22 jackup rigs and three submersible rigs in the U.S. Gulf of Mexico that can drill in maximum water depths ranging from 85 to 350 feet. Twelve of the jackup rigs are either working on short-term contracts or available for contracts and ten are cold-stacked. All three submersibles are cold-stacked.

     International Offshore — includes eight jackup rigs and one platform rig outside of the U.S. Gulf of Mexico. The Company has two jackup rigs working offshore in each of India and Saudi Arabia. The Company has one jackup rig contracted offshore in Malaysia and one platform rig under contract in Mexico. In addition, the Company has one jackup rig warm-stacked in each of Bahrain and Gabon and one jackup rig contracted to a customer in Angola, however, the rig is currently on stand-by in Gabon.

     Inland — includes a fleet of 6 conventional and 11 posted barge rigs that operate inland in marshes, rivers, lakes and shallow bay or coastal waterways along the U.S. Gulf Coast. Three of the 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 or available and three are cold-stacked.

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

     Delta Towing — the Company’s Delta Towing business operates a fleet of 29 inland tugs, 12 offshore tugs, 34 crew boats, 46 deck barges, 16 shale barges and five spud barges along and in the U.S. Gulf of Mexico and from time to time along the Southeastern coast and in Mexico. Of these vessels, 21 crew boats, 12 inland tugs, five offshore tugs, one deck barge and one spud barge are cold-stacked, and the remaining are working, being repaired or available for contracts.

     The Company’s jackup rigs, submersible rigs and platform rigs are used primarily for exploration and development drilling in shallow waters. The Company’s liftboats are self-propelled, self-elevating vessels that support a broad range of offshore maintenance and construction services throughout the life of an oil or natural gas well.

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

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

		Three Months Ended June 30, 2010												Six Months Ended June 30, 2010
						Income (Loss)				Depreciation								Income (Loss)				Depreciation
						from				&								from				&
		Revenue				Operations				Amortization				Revenue				Operations				Amortization
Domestic Offshore		$	34,143			$	(20,520	)		$	17,170			$	63,105			$	(50,646	)		$	33,709
International Offshore			73,493				24,237				14,473				146,935				46,723				29,404
Inland			5,180				(7,728	)			6,239				9,931				(13,035	)			13,745
Domestic Liftboats			17,895				2,993				3,668				29,338				427				7,868
International Liftboats			27,187				6,493				4,368				53,149				11,796				9,059
Delta Towing			7,997				(282	)			1,614				14,286				(1,223	)			3,204
			165,895				5,193				47,532				316,744				(5,958	)			96,989
Corporate			—				(10,767	)			818				—				(19,960	)			1,615
Total Company		$	165,895			$	(5,574	)		$	48,350			$	316,744			$	(25,918	)		$	98,604

		Three Months Ended June 30, 2009												Six Months Ended June 30, 2009
						Income (Loss)				Depreciation								Income (Loss)				Depreciation
						from				&								from				&
		Revenue				Operations				Amortization				Revenue				Operations				Amortization
Domestic Offshore		$	36,970			$	(20,180	)		$	15,092			$	96,151			$	(32,120	)		$	30,132
International Offshore (a)			101,757				17,175				16,749				205,209				60,060				31,933
Inland			96				(17,372	)			8,283				13,009				(33,616	)			16,276
Domestic Liftboats			18,884				212				5,747				41,494				3,231				10,796
International Liftboats			20,747				8,378				2,278				39,389				15,238				4,662
Delta Towing			5,237				(3,065	)			2,142				11,930				(7,322	)			4,426
			183,691				(14,852	)			50,291				407,182				5,471				98,225
Corporate			—				(10,977	)			800				—				(22,191	)			1,712
Total Company		$	183,691			$	(25,829	)		$	51,091			$	407,182			$	(16,720	)		$	99,937

		Total Assets
		June 30,				December 31,
		2010				2009
Domestic Offshore		$	865,890			$	870,723
International Offshore			785,104				860,252
Inland			151,211				160,354
Domestic Liftboats			89,377				88,942
International Liftboats			167,141				164,221
Delta Towing			60,313				62,563
Corporate			74,188				70,421
Total Company		$	2,193,224			$	2,277,476

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

11. Commitments and Contingencies

Legal Proceedings

     The Company is involved in various claims and lawsuits in the normal course of business. As of June 30, 2010, 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. Approximately 700 questionnaires were returned and the remaining plaintiffs, who did not submit a questionnaire reply, have had their suits dismissed without prejudice. Of the respondents, approximately 100 shared periods of employment by TODCO and its former parent which could lead to claims against either company, even though many of these plaintiffs did not state in their questionnaire answers that the employment actually involved exposure to asbestos. After providing the questionnaire, each plaintiff was further required to file a separate and individual amended complaint naming only those defendants against whom they had a direct claim as identified in the questionnaire answers. Defendants not identified in the amended complaints were dismissed from the plaintiffs’ litigation. To date, three plaintiffs named TODCO as a defendant in their amended complaints. It is possible that some of the plaintiffs who have filed amended complaints and have not named TODCO as a defendant may attempt to add TODCO as a defendant in the future when case discovery begins and greater attention is given to each individual plaintiff’s employment background. The Company has not determined which entity would be responsible for such claims under the Master Separation Agreement between TODCO and its former parent. More than three years has passed since the court ordered that amended complaints be filed by each individual plaintiff, and the original complaints. No additional plaintiffs have attempted to name TODCO as a defendant and such actions may now be time-barred. The Company intends to defend vigorously and does not expect the ultimate outcome of these lawsuits to have a material adverse effect on its consolidated results of operations, financial position or cash flows.

     The Company and its subsidiaries are involved in a number of other lawsuits, all of which have arisen in the ordinary course of business. The Company does not believe that ultimate liability, if any, resulting from any such other pending litigation will have a material adverse effect on its business or consolidated financial statements.

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

Insurance

     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 April 2010, the Company completed the annual renewal of all of its key insurance policies. The Company’s primary marine package provides for hull and machinery coverage for the Company’s rigs and liftboats up to a scheduled value of each asset. The

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

total maximum amount of coverage for these assets is $2.1 billion. The marine package includes protection and indemnity and maritime employers liability coverage for marine crew personal injury and death and certain operational liabilities, with primary coverage (or self-insured retention for maritime employers liability coverage) of $5.0 million per occurrence with excess liability coverage up to $200.0 million. The marine package also provides coverage for cargo and charter’s legal liability. The marine package includes limitations for coverage for losses caused in U.S. Gulf of Mexico named windstorms, including an annual aggregate limit of liability of $100.0 million for property damage and removal of debris liability coverage. The Company also procured an additional $75.0 million excess policy for removal of debris and certain third-party liabilities incurred in U.S. Gulf of Mexico named windstorms. Deductibles for events that are not caused by a U.S. Gulf of Mexico named windstorm are 12.5% of the insured drilling rig values per occurrence, subject to a minimum of $1.0 million, and $1.0 million per occurrence for liftboats. The deductible for drilling rigs and liftboats in a U.S. Gulf of Mexico named windstorm event is $25.0 million. Vessel pollution is covered under a Water Quality Insurance Syndicate policy with a $3.0 million deductible providing limits as required by applicable law, including the Oil Pollution Act of 1990. The policies are subject to exclusions, limitations, deductibles, self-insured retention and other conditions. In addition to the marine package, the Company has separate policies providing coverage for onshore foreign and domestic general liability, employer’s liability, auto liability and non-owned aircraft liability, with customer deductibles and coverage as well as a separate primary marine package for its Delta Towing business.

     In 2010, in connection with the renewal of certain of its insurance policies, the Company entered into an agreement to finance a portion of its annual insurance premiums. Approximately $24.1 million was financed through this arrangement, and $21.7 million was outstanding at June 30, 2010. The interest rate on the note was 3.79% and it is scheduled to mature in March 2011. Additionally, there was $0.2 million outstanding on the $1.9 million note related to the 2009 insurance renewals for the Company’s Delta Towing business. The interest rate on this note is 3.75% and it is scheduled to mature in July 2010.

     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.

Surety Bonds, Bank Guarantees and Unsecured Letters of Credit

     The Company has $50.6 million outstanding related to surety bonds at June 30, 2010. The surety bonds guarantee our performance as it relates to the Company’s drilling contracts, tax and other obligations in various jurisdictions. These obligations could be called at any time prior to the expiration dates. The obligations that are the subject of the surety bonds are geographically concentrated primarily in Mexico and the U.S. In July 2010, a $13.2 million surety bond related to the Mexico tax assessment was released (See Notes 9 and 13).

     The Company had a $1.0 million unsecured bank guarantee and a $0.1 million unsecured letter of credit outstanding at June 30, 2010.

12. Accounting Pronouncements

     In January 2010, the FASB issued ASU 2010-06 which requires additional disclosures about the various classes of assets and liabilities measured at fair value, the valuation techniques and inputs used, the activity in Level 3 fair value measurements and the transfers between Levels 1, 2, & 3. The disclosures are effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements, which are effective for interim and annual reporting periods beginning after December 15, 2010. The Company adopted the required portions of ASU 2010-06 as of January 1, 2010 with no material impact to its consolidated financial statements and will adopt the remaining portions on January 1, 2011 with no expected material impact on its consolidated financial statements (See Note 6).

13. Subsequent Events

     In July 2010, the Company increased its restricted cash balance by $6.1 million as additional collateral to support surety bonds related to its Mexico and U.S. operations (See Note 1).

     In July 2010, the Company entered into an agreement to sell retired jackup Hercules 155 for $4.8 million (See Note 3).

     In July 2010, a $13.2 million surety bond related to the Mexico tax assessment was released (See Notes 9 and 11).

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 June 30, 2010 and for the three and six months ended June 30, 2010 and June 30, 2009, included elsewhere herein, and with our Annual Report on Form 10-K for the year ended December 31, 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, 2009, Item 1A of Part II of our quarterly report on Form 10-Q for the quarter ended March 31, 2010 and Item 1A of Part II of this quarterly report for a discussion of certain risks facing our company.

OVERVIEW

     We are a leading provider of shallow-water drilling and marine services to the oil and natural gas exploration and production industry globally. We provide these services to national oil and gas companies, major integrated energy companies and independent oil and natural gas operators. As of July 20, 2010, we owned a fleet of 30 jackup rigs, 17 barge rigs, three submersible rigs, one platform rig, a fleet of marine support vessels and 60 liftboat vessels. In addition, we operate five liftboat vessels owned by a third party. We own three retired jackup rigs and two retired inland barges, all located in the U.S. Gulf of Mexico, which are currently not expected to re-enter active service. Our diverse fleet is capable of providing services such as oil and gas exploration and development drilling, well service, platform inspection, maintenance and decommissioning operations in several key shallow water provinces around the world.

     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; subsequently in each of September and November 2009, we sold one retired inland barge for approximately $0.2 million and $0.4 million, respectively. In December 2009 we entered into an agreement to sell our retired jackups Hercules 191 and Hercules 255 for $5.0 million each. The sale of the Hercules 191 was completed in April 2010 for gross proceeds of $5.0 million and the sale of the Hercules 255 is expected to close in the third quarter of 2010. In February 2010, we entered into an agreement to sell six of our retired barges for $3.0 million. The sale of three of the six retired barges was completed in the quarter ended March 31, 2010 for gross proceeds of $2.2 million. The sale of the remaining three barges was completed in April 2010 for gross proceeds of $0.8 million. Additionally, in July 2010, we entered into an agreement to sell retired jackup Hercules 155 for $4.8 million.

     We report our business activities in six business segments, which, as of July 20, 2010, included the following:

     Domestic Offshore — includes 22 jackup rigs and three submersible rigs in the U.S. Gulf of Mexico that can drill in maximum water depths ranging from 85 to 350 feet. Eleven of the jackup rigs are either working on short-term contracts or available for contracts and eleven are cold-stacked. All three submersibles are cold-stacked.

     International Offshore — includes eight jackup rigs and one platform rig outside of the U.S. Gulf of Mexico. We have two jackup rigs working offshore in each of India and Saudi Arabia. We have one jackup rig contracted offshore in Malaysia and one platform rig under contract in Mexico. In addition, we have one jackup rig warm-stacked in each of Bahrain and Gabon and one jackup rig contracted to a customer in Angola, however, the rig is currently on stand-by in Gabon.

     Inland — includes a fleet of 6 conventional and 11 posted barge rigs that operate inland in marshes, rivers, lakes and shallow bay or coastal waterways along the U.S. Gulf Coast. 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 or available and three are cold-stacked.

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

     Delta Towing — our Delta Towing business operates a fleet of 29 inland tugs, 12 offshore tugs, 34 crew boats, 46 deck barges, 16 shale barges and five spud barges along and in the U.S. Gulf of Mexico and from time to time along the Southeastern coast and in Mexico. Of these vessels, 18 crew boats, 11 inland tugs, five offshore tugs, one deck barge and one spud barge are cold-stacked, and the remaining are working, being repaired or available for contracts.

     In December 2009, we entered into an agreement with First Energy Bank B.S.C. (“MENAdrill”) whereby we would market, manage and operate two Friede & Goldman Super M2 design, new-build jackup drilling rigs each with a maximum water depth of 300

feet. The rigs are currently under construction and one is scheduled to be delivered in each of the fourth quarter of 2010 and the first quarter of 2011. We are actively marketing the rigs globally on an exclusive basis.

     In January 2010, we entered into an agreement with SKDP 1 Ltd., an affiliate of Skeie Drilling & Production ASA, to market, manage and operate an ultra high specification KFELS Class N new-build jackup drilling rig with a maximum water depth of 400 feet. The agreement was limited to a specified opportunity in the Middle East and expired by its terms during the second quarter when the rig was not selected by the operator.

     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 July 20, 2010 totaled approximately $316.3 million for our executed contracts, excluding the amount related to our Angola contract. Approximately $162.0 million of this backlog is expected to be realized during the remainder of 2010. We calculate our backlog, or future contracted revenue, as the contract dayrate multiplied by the number of days remaining on the contract, assuming full utilization. Backlog excludes revenues for mobilization, demobilization, contract preparation and customer reimbursables. The amount of actual revenues earned and the actual periods during which revenues are earned will be different than the backlog disclosed or expected due to various factors. Downtime due to various operational factors, including unscheduled repairs, maintenance, weather and other factors (some of which are beyond our control), may result in lower dayrates than the full contractual operating dayrate. In some of the contracts, our customer has the right to terminate the contract without penalty and in certain instances, with little or no notice.

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

     The most significant costs for our Domestic Liftboats and International Liftboats segments are the wages paid to crews and the amortization of regulatory drydocking costs. Unlike our Domestic Offshore, International Offshore and Inland segments, a significant portion of the expenses incurred with operating each liftboat are paid for or reimbursed by the customer under contractual terms and prices. This includes catering, fuel, oil, rental equipment, crane overtime and other items. We record reimbursements from customers as revenues and the related expenses as operating costs. Our liftboats are required to undergo regulatory inspections every year and to be drydocked two times every five years; the drydocking expenses and length of time in drydock vary depending on the condition of the vessel. All costs associated with regulatory inspections, including related drydocking costs, are deferred and amortized over a period of twelve months.

RESULTS OF OPERATIONS

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

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2010				2009				2010				2009
						(Dollars in thousands)
Domestic Offshore:
Number of rigs (as of end of period)			25				23				25				23
Revenues		$	34,143			$	36,970			$	63,105			$	96,151
Operating expenses			37,229				40,746				76,381				95,159
Depreciation and amortization expense			17,170				15,092				33,709				30,132
General and administrative expenses			264				1,312				3,661				2,980
Operating loss		$	(20,520	)		$	(20,180	)		$	(50,646	)		$	(32,120	)
International Offshore:
Number of rigs (as of end of period)			9				12				9				12
Revenues		$	73,493			$	101,757			$	146,935			$	205,209
Operating expenses			32,610				39,128				67,329				83,269
Impairment of property and equipment			—				26,882				—				26,882
Depreciation and amortization expense			14,473				16,749				29,404				31,933
General and administrative expenses			2,173				1,823				3,479				3,065
Operating income		$	24,237			$	17,175			$	46,723			$	60,060
Inland:
Number of barges (as of end of period)			17				17				17				17
Revenues		$	5,180			$	96			$	9,931			$	13,009
Operating expenses			6,363				8,857				12,080				29,121
Depreciation and amortization expense			6,239				8,283				13,745				16,276
General and administrative expenses			306				328				(2,859	)			1,228
Operating loss		$	(7,728	)		$	(17,372	)		$	(13,035	)		$	(33,616	)
Domestic Liftboats:
Number of liftboats (as of end of period)			41				45				41				45
Revenues		$	17,895			$	18,884			$	29,338			$	41,494
Operating expenses			10,853				12,418				20,167				26,552
Depreciation and amortization expense			3,668				5,747				7,868				10,796
General and administrative expenses			381				507				876				915
Operating income		$	2,993			$	212			$	427			$	3,231
International Liftboats:
Number of liftboats (as of end of period)			24				20				24				20
Revenues		$	27,187			$	20,747			$	53,149			$	39,389
Operating expenses			14,897				9,113				29,359				17,220
Depreciation and amortization expense			4,368				2,278				9,059				4,662
General and administrative expenses			1,429				978				2,935				2,269
Operating income		$	6,493			$	8,378			$	11,796			$	15,238

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2010				2009				2010				2009
						(Dollars in thousands)
Delta Towing:
Revenues		$	7,997			$	5,237			$	14,286			$	11,930
Operating expenses			6,369				5,835				11,641				14,020
Depreciation and amortization expense			1,614				2,142				3,204				4,426
General and administrative expenses			296				325				664				806
Operating loss		$	(282	)		$	(3,065	)		$	(1,223	)		$	(7,322	)
Total Company:
Revenues		$	165,895			$	183,691			$	316,744			$	407,182
Operating expenses			108,321				116,097				216,957				265,341
Impairment of property and equipment			—				26,882				—				26,882
Depreciation and amortization			48,350				51,091				98,604				99,937
General and administrative			14,798				15,450				27,101				31,742
Operating loss			(5,574	)			(25,829	)			(25,918	)			(16,720	)
Interest expense			(21,259	)			(14,561	)			(42,998	)			(30,350	)
Gain on early retirement of debt, net			—				13,747				—				13,747
Other, net			3,183				3,346				3,169				2,690
Loss before income taxes			(23,650	)			(23,297	)			(65,747	)			(30,633	)
Income tax benefit			4,666				11,510				30,807				14,335
Loss from continuing operations			(18,984	)			(11,787	)			(34,940	)			(16,298	)
Loss from discontinued operation, net of taxes			—				(242	)			—				(675	)
Net loss		$	(18,984	)		$	(12,029	)		$	(34,940	)		$	(16,973	)

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

		Three Months Ended June 30, 2010
																		Average
														Average				Operating
		Operating				Available								Revenue				Expense
		Days				Days				Utilization (1)				per Day (2)				per Day (3)
Domestic Offshore			966				1,072				90.1	%		$	35,345			$	34,729
International Offshore			533				819				65.1	%			137,886				39,817
Inland			250				273				91.6	%			20,720				23,308
Domestic Liftboats			2,503				3,458				72.4	%			7,149				3,139
International Liftboats			1,224				2,154				56.8	%			22,212				6,916

		Three Months Ended June 30, 2009
																		Average
														Average				Operating
		Operating				Available								Revenue				Expense
		Days				Days				Utilization (1)				per Day (2)				per Day (3)
Domestic Offshore			706				1,136				62.1	%		$	52,365			$	35,868
International Offshore			788				910				86.6	%			129,133				42,998
Inland			—				303				0.0	%			n/a				29,231
Domestic Liftboats			2,444				3,842				63.6	%			7,727				3,232
International Liftboats			1,005				1,729				58.1	%			20,644				5,271

		Six Months Ended June 30, 2010
																		Average
														Average				Operating
		Operating				Available								Revenue				Expense
		Days				Days				Utilization (1)				per Day (2)				per Day (3)
Domestic Offshore			1,789				2,062				86.8	%		$	35,274			$	37,042
International Offshore			1,060				1,688				62.8	%			138,618				39,887
Inland			490				543				90.2	%			20,267				22,247
Domestic Liftboats			4,230				6,878				61.5	%			6,936				2,932
International Liftboats			2,398				4,314				55.6	%			22,164				6,806