Edgar Filing: HERCULES OFFSHORE, INC.

Inputs are quoted prices in active markets for identical assets or liabilities.

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.

Inputs are derived from valuation techniques in which one or more significant inputs or value drivers are unobservable.

e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended June 30, 2008


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

Commission file number: 0-51582

HERCULES OFFSHORE, INC.

(Exact name of registrant as specified in its charter)


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

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

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

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

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


Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	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 25, 2008
		87,949,582

HERCULES OFFSHORE, INC.

INDEX


	Page No.
PART I. FINANCIAL INFORMATION

Item 1. Financial Statements:
Consolidated Balance Sheets as of June 30, 2008 and December 31, 2007		3
Consolidated Statements of Operations for the three and six months ended June 30, 2008 and June 30, 2007		4
Consolidated Statements of Cash Flows for the six months ended June 30, 2008 and June 30, 2007		5
Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2008 and June 30, 2007		6
Notes to Unaudited Consolidated Financial Statements		7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		19
Item 3. Quantitative and Qualitative Disclosures about Market Risk		35
Item 4. Controls and Procedures		36

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		36
Item 1A. Risk Factors		37
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		41
Item 4. Submission of Matters to a Vote of Security Holders		41
Item 6. Exhibits		43

Signatures		44
Amended and Restated 2004 Long-Term Incentive Plan
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO & CFO Pursuant to Section 906

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,
	2008			2007
	(Unaudited)
ASSETS
Current Assets:
Cash and Cash Equivalents	$	98,026		$	212,452
Marketable Securities		—			39,300
Accounts Receivable, Net		262,501			221,663
Insurance Claims Receivable		4,209			43,342
Supplies		2,489			2,494
Prepaids		53,278			31,417
Current Deferred Tax Asset		17,551			17,551
Other		28,460			23,565

		466,514			591,784
Property and Equipment, Net		2,424,203			2,060,224
Goodwill		952,740			940,241
Other Assets, Net		47,139			50,290

	$	3,890,596		$	3,642,539

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term Debt and Current Portion of Long-term Debt	$	20,400		$	21,653
Insurance Note Payable		32,148			16,931
Accounts Payable		104,203			105,527
Accrued Liabilities		80,805			80,138
Taxes Payable		7,137			23,006
Other Current Liabilities		25,979			16,845

		270,672			264,100
Long-term Debt, Net of Current Portion		1,137,762			890,013
Other Liabilities		34,494			19,518
Deferred Income Taxes		447,776			457,475
Commitments and Contingencies
Stockholders’ Equity:

Common Stock, $0.01 Par Value; 200,000 Shares Authorized; 89,410 and 88,876 Shares Issued, Respectively; 87,938 and 88,857 Shares Outstanding, Respectively		894			889
Capital in Excess of Par Value		1,750,378			1,731,882
Treasury Stock, at Cost, 1,472 Shares and 19 Shares, Respectively		(49,879	)		(582	)
Accumulated Other Comprehensive Loss		(9,791	)		(8,117	)
Retained Earnings		308,290			287,361

		1,999,892			2,011,433

	$	3,890,596		$	3,642,539

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,
	2008			2007			2008			2007
Revenues	$	270,830		$	99,044		$	484,216		$	209,508
Costs and Expenses:
Operating Expenses		158,870			44,396			291,679			85,923
Depreciation and Amortization		47,280			12,209			90,906			23,939
General and Administrative		23,966			9,335			40,330			18,498

		230,116			65,940			422,915			128,360

Operating Income		40,714			33,104			61,301			81,148
Other Income (Expense):
Interest Expense		(14,579	)		(1,379	)		(30,539	)		(3,469	)
Loss on Early Retirement of Debt		—			(870	)		—			(870	)
Other, Net		67			1,246			2,274			2,521

Income Before Income Taxes		26,202			32,101			33,036			79,330
Income Tax Provision		(9,759	)		(8,635	)		(12,107	)		(22,473	)

Net Income	$	16,443		$	23,466		$	20,929		$	56,857

Earnings Per Share:
Basic	$	0.19		$	0.73		$	0.24		$	1.77
Diluted	$	0.18		$	0.72		$	0.23		$	1.74
Weighted Average Shares Outstanding:
Basic		88,625			32,099			88,742			32,037
Diluted		89,461			32,813			89,516			32,642

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

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

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


	Six Months Ended June 30,
	2008			2007
Cash Flows from Operating Activities:
Net Income	$	20,929		$	56,857
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Depreciation and Amortization		90,906			23,939
Stock-based Compensation Expense		7,932			2,881
Deferred Income Taxes		6,243			5,031
Amortization of Deferred Financing Fees		1,712			293
Gain on Disposal of Assets		(1,911	)		(296	)
Excess Tax Benefit from Stock-based Arrangements		(5,447	)		(1,731	)
Loss on Early Retirement of Debt		—			870
(Increase) Decrease in Operating Assets -
Accounts Receivable		(41,755	)		14,146
Insurance Claims Receivable		(142	)		(5,853	)
Prepaid Expenses and Other		14,069			2,482
Increase (Decrease) in Operating Liabilities -
Accounts Payable		(885	)		1,703
Insurance Note Payable		(21,077	)		(6,058	)
Other Current Liabilities		(4,846	)		(7,898	)
Other Liabilities		3,126			(284	)

Net Cash Provided by Operating Activities		68,854			86,082
Cash Flows from Investing Activities:
Acquisition of Assets		(320,839	)		—
Additions of Property and Equipment		(130,528	)		(38,133	)
Deferred Drydocking Expenditures		(9,151	)		(9,864	)
Investment in Marketable Securities		—			(61,500	)
Proceeds from Sale of Marketable Securities		39,300			37,600
Insurance Proceeds Received		25,332			—
Proceeds from Sale of Assets, Net		12,649			610

Net Cash Used in Investing Activities		(383,237	)		(71,287	)
Cash Flows from Financing Activities:
Short-term Debt Borrowings (Repayments), Net		1,086			—
Long-term Debt Borrowings		350,000			—
Long-term Debt Repayments		(104,470	)		(37,700	)
Share Repurchases		(49,228	)		—
Proceeds from Exercise of Stock Options		5,127			1,510
Excess Tax Benefit from Stock-based Arrangements		5,447			1,731
Payment of Debt Issuance Costs		(8,005	)		(441	)
Other		—			(46	)

Net Cash Provided by (Used in) Financing Activities		199,957			(34,946	)

Net Decrease in Cash and Cash Equivalents		(114,426	)		(20,151	)
Cash and Cash Equivalents at Beginning of Period		212,452			72,772

Cash and Cash Equivalents at End of Period	$	98,026		$	52,621

Cash Paid for Interest	$	13,538		$	4,295
Cash Paid for Taxes		32,994			27,375

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

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

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


	Three Months Ended June 30,					Six Months Ended June 30,
	2008		2007			2008			2007
Net Income	$	16,443	$	23,466		$	20,929		$	56,857
Other Comprehensive Income (Loss), Net of Tax:
Changes related to Hedge Transactions		5,352		(267	)		(1,674	)		(427	)

Comprehensive Income	$	21,795	$	23,199		$	19,255		$	56,430

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

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
UNAUDITED

1. General

Hercules Offshore, Inc. provides shallow-water drilling and marine services to the oil and gas exploration and production industry in the U.S. Gulf of Mexico and international locations through its Domestic Offshore, International Offshore, Inland, Domestic Liftboats, International Liftboats and Other segments (See Note 10). On July 11, 2007, the Company completed the acquisition of TODCO (See Note 3), a provider of contract oil and gas drilling services in the U.S. Gulf of Mexico and international locations. TODCO owned and operated 24 jackup rigs, 27 barge rigs, three submersible rigs, nine land rigs, one platform rig and a fleet of marine support vessels. During the fourth quarter of 2007, the Company sold the nine land rigs and related assets (See Note 4). At June 30, 2008, the Company owned a fleet of 35 jackup rigs, 27 barge rigs, three submersible rigs, one platform rig, a fleet of marine support vessels operated through Delta Towing, a wholly owned subsidiary, and 60 liftboat vessels and operated an additional five liftboat vessels owned by a third party. In February 2008, the Company entered into a definitive agreement to purchase three jackup drilling rigs and related equipment for $320.0 million. The Company completed the purchase of the Hercules 350 and the Hercules 261 and related equipment during March 2008, while the purchase of the Hercules 262 and related equipment was completed in May 2008. The Company currently operates in ten countries on four continents.

The consolidated financial statements of Hercules Offshore, Inc. and its majority owned subsidiaries (the “Company”) are unaudited; however, they include all adjustments of a normal recurring nature which, in the opinion of management, are necessary to present fairly the Company’s Consolidated Balance Sheet at June 30, 2008, Consolidated Statements of Operations and Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2008 and 2007, and Consolidated Statements of Cash Flows for the six months ended June 30, 2008 and 2007. Although the Company believes the disclosures in these financial statements are adequate to make the interim information presented not misleading, certain information relating to the Company’s organization and footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles have been condensed or omitted in this Form 10-Q pursuant to Securities and Exchange Commission rules and regulations. These financial statements should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2007 and the notes thereto included in the Company’s Annual Report on Form 10-K. The results of operations for the three and six months ended June 30, 2008 are not necessarily indicative of the results expected for the full year.

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, the Company evaluates its estimates, including those related to bad debts, investments, intangible assets and goodwill, property, plant and equipment, income taxes, insurance, employment benefits and contingent liabilities. The Company bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates.

Revenue Recognition

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2008		2007		2008		2007
Mobilization revenue deferred	$	4,450	$	—	$	8,277	$	—
Mobilization expense deferred		—		—		3,398		—
Mobilization revenue recognized		4,206		710		6,176		2,465
Mobilization expense recognized		2,142		411		2,956		1,582

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

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

The Company records reimbursements from customers for “out-of-pocket” expenses as revenues and the related cost as direct operating expenses. Total revenues from such reimbursements were $3.9 million and $2.3 million for the three months ended June 30, 2008 and 2007, respectively. Total revenues from such reimbursements were $6.8 million and $5.5 million for the six months ended June 30, 2008 and 2007, respectively.

Other Assets

Other assets consist of drydocking costs for marine vessels, other intangible assets, deferred costs, financing fees, derivative assets, investments, deposits and other. Drydock costs are capitalized at cost and amortized on the straight-line method over a period of 12 months. Drydocking costs, net of accumulated amortization, at June 30, 2008 and December 31, 2007 were $7.5 million and $8.2 million, respectively. Amortization expense for drydocking costs was $4.7 million and $4.4 million for the three months ended June 30, 2008 and 2007, respectively, and $9.8 million and $8.5 million for the six months ended June 30, 2008 and 2007, respectively.

Financing fees are deferred and amortized over the life of the applicable debt instrument. Unamortized deferred financing fees at June 30, 2008 and December 31, 2007 were $22.5 million and $16.2 million, respectively. The amortization expense related to the deferred financing fees is included in interest expense on the Consolidated Statements of Operations. Amortization expense for financing fees was $1.0 million and $0.1 million for the three months ended June 30, 2008 and 2007, respectively, and $1.7 million and $0.3 million for the six months ended June 30, 2008 and 2007, respectively.

Other Intangible Assets

In connection with the acquisition of TODCO (See Note 3), the Company allocated $17.6 million in value to certain international customer contracts. The estimated fair value of these acquired contracts is based on preliminary valuations and is subject to change when final valuations are obtained. These contracts are being amortized over the life of the contracts. As of June 30, 2008, the customer contracts had a carrying value of $10.7 million, net of accumulated amortization of $6.9 million, and are included in Other Assets, Net on the Consolidated Balance Sheet.

Amortization expense was $2.2 million and $4.2 million for the three and six months ended June 30, 2008, respectively. Future estimated amortization expense for the carrying amount of intangible assets as of June 30, 2008 is expected to be as follows (in thousands):


Remainder of 2008	$	3,585
2009		4,658
2010		1,691
2011		727
2012		—

Cash and Cash Equivalents and Marketable Securities

From time to time the Company may invest a portion of its available cash in marketable securities. Marketable securities are classified as available for sale and are stated at fair value on the Consolidated Balance Sheets. At June 30, 2008, the Company had no investments in marketable securities. Proceeds of $39.3 million were received from sales and maturities of marketable securities for the six months ended June 30, 2008. There were no realized or unrealized gains or losses related to these securities.

Cash and cash equivalents include cash on hand, demand deposits with banks and all highly liquid investments with original maturities of three months or less. Realized and unrealized gains and losses related to marketable securities are calculated using the specific identification method. Unrealized gains or losses, net of taxes, are included in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets until realized. Realized gains or losses are included in Other, Net in the Consolidated Statements of Operations.

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

2. Earnings Per Share

The reconciliation of the numerator and denominator used for the computation of basic and diluted earnings per share is as follows (in thousands, except per share data):


	Three Months Ended June 30,				Six Months Ended June 30,
	2008		2007		2008		2007
Numerator:
Net income	$	16,443	$	23,466	$	20,929	$	56,857
Denominator:
Weighted average basic shares		88,625		32,099		88,742		32,037
Add effect of stock equivalents		836		714		774		605

Weighted average diluted shares		89,461		32,813		89,516		32,642

Basic earnings per share	$	0.19	$	0.73	$	0.24	$	1.77
Diluted earnings per share	$	0.18	$	0.72	$	0.23	$	1.74

The Company calculates basic earnings per share by dividing net income by the weighted average number of shares outstanding. Diluted earnings per share is computed by dividing net income by the weighted average number of shares outstanding during the period as adjusted for the dilutive effect of the Company’s stock option and restricted stock awards. Stock equivalents of 176,092 and 542,748 were anti-dilutive and are excluded from the calculation of the dilutive effect of stock equivalents for the diluted earnings per share calculation for the three and six months ended June 30, 2008, respectively. Stock equivalents of 21,500 and 14,917 were anti-dilutive and are excluded from the calculation of the dilutive effect of stock equivalents for the diluted earnings per share calculation for the three and six months ended June 30, 2007, respectively.

3. Asset Acquisition and Business Combination

In February 2008, the Company entered into a definitive agreement to purchase three jackup drilling rigs and related equipment for $320.0 million. The Company completed the purchase of the Hercules 350 and the Hercules 261 and related equipment during March 2008, while the purchase of the Hercules 262 and related equipment was completed in May 2008.

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

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

4. Dispositions

During the second quarter of 2008, the Company sold Hercules 256 for gross proceeds of $8.5 million, which approximated the carrying value of this asset.

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

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

5. Debt

Debt is comprised of the following (in thousands):


	June 30, 2008		December 31, 2007
Term Loan Facility, due July 2013	$	893,250	$	895,500
3.375% Convertible Senior Notes due June 2038		250,000		—
9.5% Senior Notes, due December 2008		10,314		10,432
7.375% Senior Notes, due April 2018		3,512		3,513
6.95% Senior Notes, due April 2008		—		2,221
Foreign Line of Credit		1,086		—

Total Debt		1,158,162		911,666
Less Short-term Debt and Current Portion of Long-term Debt		20,400		21,653

Total Long-term Debt, Net of Current Portion	$	1,137,762	$	890,013

Senior secured credit agreement

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

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

No amounts were outstanding and $28.5 million in standby letters of credit had been issued under the revolving credit facility as of June 30, 2008. The remaining availability under this revolving credit facility was $221.5 million at June 30, 2008.

As of June 30, 2008, $893.3 million was outstanding on the term loan facility and the interest rate was 4.45%. The annualized effective rate of interest was 6.41% for the six months ended June 30, 2008 after giving consideration to derivative activities.

The credit agreement contains financial covenants that are tested quarterly relating to leverage and fixed charge coverage. Other covenants contained in the credit agreement restrict, among other things, asset dispositions, mergers and acquisitions, dividends, stock repurchases and redemptions, other restricted payments, debt, liens, investments and affiliate transactions. The credit agreement contains customary events of default. The Company was in compliance with these covenants at June 30, 2008.

Senior notes and other debt

On June 3, 2008, the Company completed an offering of $250.0 million convertible senior notes at a coupon rate of 3.375% (“3.375% Convertible Senior Notes”) with a maturity in June 2038. The interest on the notes is payable in cash semi-annually in arrears, on June 1 and December 1 of each year until June 1, 2013, after which the principal will accrete at an annual yield to maturity of 3.375% per year. The Company will also pay contingent interest during any six-month interest period commencing June 1, 2013, for which the trading price of these notes for a specified period of time equals or exceeds 120% of their accreted principal amount. The notes will be convertible under certain circumstances into shares of the Company’s common stock at an initial conversion rate of 19.9695 shares of common stock per $1,000 principal amount of notes, which is equal to an initial conversion price of approximately $50.08 per share. Upon conversion of a note, a holder will receive, at the Company’s election, shares of common stock, cash or a combination of cash and shares of common stock. The Company may redeem the notes at its option beginning June 6, 2013, and holders of the notes will have the right to require the Company to repurchase the notes on certain dates or on the occurrence of a fundamental change. Net proceeds of $243.5 million were used to purchase approximately 1.45 million shares, or $49.2 million, of the Company’s common stock, to repay outstanding borrowings under its senior secured revolving credit facility which totaled $100.0 million at the time of the offering and for other general corporate purposes.

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

In connection with the TODCO acquisition in July 2007, the Company assumed senior notes and an unsecured line of credit with a bank in Venezuela. The senior notes included 6.95% Senior Notes due in April 2008, 7.375% Senior Notes due in April 2018, and 9.5% Senior Notes due in December 2008 (collectively, “Senior Notes”). The 6.95% Senior Notes were repaid in April 2008. The fair

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

market value of the 7.375% Senior Notes and 9.5% Senior Notes at June 30, 2008 was approximately $3.5 million and $10.2 million, respectively, based on the most recent market valuations. The line of credit is designed to manage local currency liquidity in Venezuela and the maximum amount available to be drawn was increased to 9.0 million Bolivares Fuertes from 6.0 million Bolivares Fuertes in July 2008. The maximum amount available to be drawn at June 30, 2008 was 6.0 million Bolivares Fuertes ($2.8 million at the exchange rate at June 30, 2008), and there were 2.3 million Bolivares Fuertes ($1.1 million at the exchange rate at June 30, 2008) outstanding at June 30, 2008.

6. Derivative Instruments and Hedging

The Company periodically uses derivative instruments to manage its exposure to interest rate risk, including interest rate swap agreements to effectively fix the interest rate on variable rate debt and interest rate caps to cap the interest rate on variable rate debt.

In May 2008 and July 2007, the Company entered into derivative instruments with the purpose of hedging future interest payments on its term loan facility. In May 2008, the Company entered into a floating to fixed interest rate swap with varying notional amounts beginning with $100.0 million with a settlement date of October 1, 2008 and ending with $75.0 million with a settlement date of December 31, 2009. The Company receives an interest rate of three-month LIBOR and pays a fixed coupon of 2.980% over six quarters. The terms and settlement dates of the swap match those of the term loan. In July 2007, the Company entered into a floating to fixed interest rate swap with decreasing notional amounts beginning with $400.0 million with a settlement date of December 31, 2007 and ending with $50.0 million with a settlement date of April 1, 2009. The Company will receive a payment equal to the product of three-month LIBOR and the notional amount and will pay a fixed coupon of 5.307% on the notional amount over six quarters. The terms and settlement dates of the swap match those of the term loan. In July 2007, the Company also entered into a zero cost LIBOR collar on $300.0 million of term loan principal over three years, with a ceiling of 5.75% and a floor of 4.99%. The counterparty is obligated to pay the Company in any quarter that actual LIBOR resets above 5.75% and the Company pays the counterparty in any quarter that actual LIBOR resets below 4.99%. The terms and settlement dates of the collar match those of the term loan.

The following table provides the schedule of notional amounts related to the May 2008 interest rate swap (in thousands):


July 1, 2008-September 30, 2008	$	100,000
October 1, 2008-December 30, 2008		325,000
December 31, 2008-March 31, 2009		325,000
April 1, 2009-June 30, 2009		250,000
July 1, 2009-September 30, 2009		175,000
October 1, 2009-December 30, 2009		75,000

The following table provides the scheduled reduction in notional amounts related to the July 2007 interest rate swap (in thousands):


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

These hedge transactions are being accounted for as cash flow hedges under Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities (an amendment of FASB Statement No. 133), and SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. The fair value of these hedging instruments is included in Other Assets, Net and Other Liabilities and the cumulative unrealized loss, net of tax, is included in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets. The Company did not recognize a gain or loss due to hedge ineffectiveness in the Consolidated Statements of Operations for the three and six months ended June 30, 2008 and 2007 related to these hedging instruments.

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


	June 30,			December 31,
	2008			2007
Fair value included in Other Assets, Net	$	1,186		$	322
Fair value included in Other Liabilities		16,250			12,809
Cumulative unrealized loss, net of tax of $5,272 and $4,371, respectively included in Accumulated Other Comprehensive Loss		(9,791	)		(8,117	)

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


	Recognized Gain (Loss) in					Recognized Gain (Loss) in
	Consolidated Statements of					Consolidated Statements of
	Operations for the Three Months					Operations for the Six Months
	Ended June 30,					Ended June 30,
	2008			2007		2008			2007
Realized Gains (Losses) included in Interest Expense	$	(3,717	)	$	109	$	(4,267	)	$	316

Fair value measurements are generally based upon observable and unobservable inputs. Observable inputs reflect market data obtained from independent sources, while unobservable inputs reflect our view of market assumptions in the absence of observable market information. The Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. SFAS No. 157 includes a fair value hierarchy that is intended to increase consistency and comparability in fair value measurements and related disclosures. The fair value hierarchy consists of the following three levels:

The valuation techniques that may be used to measure fair value are as follows:

	(A)		Market approach — Uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities

	(B)		Income approach — Uses valuation techniques to convert future amounts to a single present amount based on current market expectations about those future amounts, including present value techniques, option-pricing models and excess earnings method

	(C)		Cost approach — Based on the amount that currently would be required to replace the service capacity of an asset (replacement cost)

The following table represents our derivative assets and liabilities measured at fair value on a recurring basis as of June 30, 2008 (in thousands):

Quoted Prices in

Total

Active Markets for

Fair Value

Identical Asset or

Significant Other

Significant

Measurement

Liability

Observable Inputs

Unobservable Inputs

Valuation

June 30, 2008

(Level 1)

(Level 2)

(Level 3)

Technique

Derivative Assets

1,186

—

1,186

—

Derivative Liabilities

16,250

—

16,250

—

7. Stock-based Compensation

The Company’s 2004 Long-Term Incentive Plan (the “2004 Plan”) provides for the granting of stock options, restricted stock, performance stock awards and other stock-based awards to selected employees and non-employee directors of the Company. In July 2007, the Company’s stockholders approved an increase in the shares available for grant or award under the 2004 Plan by an additional 6.8 million shares to a total of 10.3 million shares. On February 15, 2008, the Company filed a registration statement to register the additional 6.8 million shares issuable under the 2004 plan. At June 30, 2008, approximately 6.5 million shares were available for grant or award under the 2004 Plan.

During the six months ended June 30, 2008, the Company granted 401,300 stock options with a weighted average exercise price of $26.55 and 407,805 restricted stock awards with a weighted average grant-date fair value per share of $26.41.

The Company recognized $5.5 million and $7.9 million in stock-based compensation expense during the three and six months ended June 30, 2008, respectively and $1.7 million and $2.9 million during the three and six months ended June 30, 2007, respectively. The excess income tax benefit, the tax deduction that is in excess of the tax benefit recognized in the consolidated

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

financial statements related to stock-based compensation, recognized for the three and six months ended June 30, 2008 was $5.1 million and $5.4 million, respectively, and $1.0 million and $1.7 million for the three and six months ended June 30, 2007, respectively.

The unrecognized compensation cost related to the Company’s unvested stock options and restricted share grants as of June 30, 2008 was $5.5 million and $13.0 million, respectively, and is expected to be recognized over a weighted-average period of 1.6 years and 1.9 years, respectively.

Cash received from stock option exercises during the six months ended June 30, 2008 was $5.1 million.

8. Supplemental Cash Flow Information

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


	Six Months Ended June 30,
	2008		2007
Decrease in fair value of derivative instruments	$	1,674	$	427

9. Income Tax

The Company, as successor to TODCO, and TODCO’s former parent Transocean Holdings Inc. (“Transocean”) 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. The tax sharing agreement required the Company to make an acceleration payment to Transocean upon completion of the TODCO acquisition. Subsequent to the completion of the TODCO acquisition, the Company paid $116.0 million to Transocean in the second half of 2007 in satisfaction of the obligation to pay the acceleration payment, however the basis of determination for the payment has been disputed by Transocean, and Transocean has publicly disclosed that it believes the Company owes an additional $11 million as a result of the acquisition of TODCO. In May of 2008, Transocean initiated the dispute resolution procedure set forth in the tax sharing agreement, and in June of 2008, Transocean delivered a demand for arbitration to the Company.

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, 2008, assuming a Transocean stock price of $152.39 per share at the time of exercise of the compensatory options (the actual price of Transocean’s common stock at June 30, 2008), is approximately $25.1 million. There is no certainty that the Company will realize future economic benefits from TODCO’s tax benefits equal to the amount of the payments required under the tax sharing agreement.

In the first quarter of 2008, the Nigerian Federal Inland Revenue Service (“FIRS”) commenced an audit of the 2006 tax return for one of the Company’s subsidiaries. The audit is currently underway and the Company has not yet received an assessment.

In March 2007, a subsidiary of the Company received an assessment from the Mexican tax authorities related to its operations for the 2004 tax year. This assessment contests the Company’s right to certain deductions and also claims it did not remit withholding tax due on other deductions. The Company intends to vigorously contest the assessment. The Mexican tax authorities have also commenced a preliminary review of the subsidiary’s financial statements for 2005, however a formal tax audit has not yet commenced. The timing and effect on the Company’s consolidated financial statements of the resolution of these income tax examinations is highly uncertain due to various underlying factors. These factors include, among other things, the amount and nature of additional taxes potentially asserted by local tax authorities; the willingness of local tax authorities to negotiate a reasonable and appropriate settlement through an administrative process; and the impartiality of the local courts. The amounts ultimately paid, if any, upon the resolution of the issues raised by the tax authorities in any audit may differ materially from the amounts accrued for each year. While it is possible that some of these examinations may be resolved in the next 12 months, the Company cannot predict or provide assurance as to the ultimate outcome of existing or future tax assessments.

In December 2002, TODCO received an assessment for corporate income taxes from SENIAT, the national Venezuelan tax authority, of approximately $20.7 million (based on the current exchange rates at the time of the assessment and inclusive of penalties) relating to calendar years 1998 through 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

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

(based on the current exchange rates at the time of the assessment and inclusive of penalties). Thereafter, TODCO filed an administrative tax appeal with SENIAT and the tax authority rendered a decision that reduced the tax assessment to $8.1 million (based on the current exchange rates at the time of the decision). TODCO then initiated a judicial tax court appeal with the Venezuelan Tax Court to set aside the $8.1 million administrative tax assessment. We do not expect the ultimate resolution of this assessment to have a material impact on our consolidated results of operations, financial condition or cash flows. In January 2008, SENIAT commenced an audit for the 2003 calendar year, which has since been suspended by SENIAT. The Company expects that SENIAT will resume the audit in the near future. The Company has not yet received any proposed adjustments from SENIAT

10. Segments

The Company reports its business activities in six business segments: (1) Domestic Offshore, (2) International Offshore, (3) Inland, (4) Domestic Liftboats, (5) International Liftboats and (6) Other. Our Other segment includes Delta Towing and the wind down costs associated with our land rigs sold in December 2007 (See Note 4). The Company eliminates inter-segment revenue and expenses, if any. The following describes the Company’s reporting segments as of June 30, 2008:

Domestic Offshore – includes 24 jackup rigs and three submersible rigs in the U.S. Gulf of Mexico that can drill in maximum water depths ranging from 85 to 350 feet.

International Offshore – includes 11 jackup rigs and one platform rig outside of the U.S. Gulf of Mexico. The Company has one jackup rig working offshore in each of the following international locations: Qatar, Angola and Gabon. The Company has two jackup rigs working offshore in India and two jackup rigs and one platform rig operating in Mexico. In addition, the Company has one jackup rig undergoing reactivation in Southeast Asia, one jackup rig undergoing contract preparation work in the Middle East and one jackup rig in transit to the Middle East where upon arrival, it will undergo contract preparation work. The Company has one jackup rig warm-stacked in Trinidad.

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

Domestic Liftboats – includes 45 liftboats in the U.S. Gulf of Mexico.

International Liftboats – includes 20 liftboats. Eighteen are operating offshore West Africa, including five liftboats owned by a third party. One liftboat is in transit to the Middle East and one liftboat is currently undergoing refurbishment in the Middle East.

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

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

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

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


	Three Months Ended June 30, 2008							Six Months Ended June 30, 2008
						Depreciation							Depreciation
			Income (Loss)			&				Income (Loss)			&
	Revenue		from Operations			Amortization		Revenue		from Operations			Amortization
Domestic Offshore	$	97,438	$	23,577		$	16,204	$	159,885	$	21,687		$	31,539
International Offshore		74,187		27,424			9,310		139,530		61,774			16,896
Inland		40,262		(2,914	)		10,520		80,530		(4,854	)		20,180
Domestic Liftboats		22,269		2,973			5,382		38,213		(1,578	)		11,334
International Liftboats		20,305		6,752			2,368		38,596		14,900			4,352
Other		16,369		2,315			2,712		27,462		1,046			5,287

		270,830		60,127			46,496		484,216		92,975			89,588
Corporate		—		(19,413	)		784		—		(31,674	)		1,318

Total Company	$	270,830	$	40,714		$	47,280	$	484,216	$	61,301		$	90,906


	Three Months Ended June 30, 2007							Six Months Ended June 30,2007
						Depreciation							Depreciation
			Income from			&				Income from			&
	Revenue		Operations			Amortization		Revenue		Operations			Amortization
Domestic Offshore	$	28,325	$	10,124		$	2,691	$	71,156	$	34,889		$	5,252
International Offshore		19,640		9,927			1,363		40,516		21,522			2,731
Inland		—		—			—		—		—			—
Domestic Liftboats		37,195		14,825			6,192		69,898		27,280			12,262
International Liftboats		13,884		3,541			1,938		27,938		8,000			3,642
Other		—		—			—		—		—			—

		99,044		38,417			12,184		209,508		91,691			23,887
Corporate		—		(5,313	)		25		—		(10,543	)		52

Total Company	$	99,044	$	33,104		$	12,209	$	209,508	$	81,148		$	23,939


	Total Assets
	June 30, 2008		December 31, 2007
Domestic Offshore	$	1,663,762	$	1,504,548
International Offshore		963,842		681,742
Inland		660,835		646,120
Domestic Liftboats		151,172		186,568
International Liftboats		145,326		149,813
Other		140,193		229,979
Corporate		165,466		243,769

Total Company	$	3,890,596	$	3,642,539

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

11. Commitments and Contingencies

Legal Proceedings

The Company is involved in various claims and lawsuits in the normal course of business. As of June 30, 2008, management did not believe any accruals were necessary in accordance with SFAS No. 5, Accounting for Contingencies.

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

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

Robert E. Aaron et al. vs. Phillips 66 Company et al. Circuit Court, Second Judicial District, Jones County, Mississippi. This is the case name used to refer to several cases that have been filed in the Circuit Courts of the State of Mississippi involving 768 persons that allege personal injury or whose heirs claim their deaths arose out of asbestos exposure in the course of their employment by the defendants between 1965 and 2002. The complaints name as defendants, among others, certain of TODCO’s subsidiaries and certain subsidiaries of TODCO’s former parent to whom TODCO may owe indemnity, and other unaffiliated defendant companies, including companies that allegedly manufactured drilling-related products containing asbestos that are the subject of the complaints. The number of unaffiliated defendant companies involved in each complaint ranges from approximately 20 to 70. The complaints allege that the defendant drilling contractors used asbestos-containing products in offshore drilling operations, land based drilling operations and in drilling structures, drilling rigs, vessels and other equipment and assert claims based on, among other things, negligence and strict liability, and claims authorized under the Jones Act. The plaintiffs seek, among other things, awards of unspecified compensatory and punitive damages. All of these cases were assigned to a special master who has approved a form of questionnaire to be completed by plaintiffs so that claims made would be properly served against specific defendants. As of the date of this report, approximately 700 questionnaires were returned and the remaining plaintiffs, who did not submit a questionnaire reply, have had their suits dismissed without prejudice. Of the respondents, approximately 100 shared periods of employment by TODCO and its former parent which could lead to claims against either company, even though many of these plaintiffs did not state in their questionnaire answers that the employment actually involved exposure to asbestos. After providing the questionnaire, each plaintiff was further required to file a separate and individual amended complaint naming only those defendants against whom they had a direct claim as identified in the questionnaire answers. Defendants not identified in the amended complaints were dismissed from the plaintiffs’ litigation. To date, three plaintiffs named TODCO as a defendant in their amended complaints. It is possible that some of the plaintiffs who have filed amended complaints and have not named TODCO as a defendant may attempt to add TODCO as a defendant in the future when case discovery begins and greater attention is given to each individual plaintiff’s employment background. The Company continues to monitor a small group of these other cases. The Company has not determined which entity would be responsible for such claims under the Master Separation Agreement between TODCO and its former parent. The Company intends to defend vigorously and, based on the limited information available at this time, does not expect the ultimate outcome of these lawsuits to have a material adverse effect on its consolidated results of operations, financial position or cash flows.

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

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

Insurance

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

The Company maintains insurance coverage that includes coverage for physical damage, third party liability, workers’

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

compensation and employers’ liability, general liability, vessel pollution and other coverages.

In May 2008, the Company completed the renewal of all of its key insurance policies. The Company’s primary marine package provides for hull and machinery coverage for the Company’s rigs and liftboats up to a scheduled value for each asset. The maximum coverage for these assets is $2.9 billion; however, coverage for U.S. Gulf of Mexico named windstorm damage is subject to an annual aggregate limit on liability of $200.0 million. The policies are subject to deductibles, self-insured retention and other conditions. Deductibles for events that are not U.S. Gulf of Mexico named windstorm events are 10% of insured values per occurrence for drilling rigs, and range from $0.3 million to $1.0 million per occurrence for liftboats, depending on the insured value of the particular vessel. The deductibles for drilling rigs and liftboats in a U.S. Gulf of Mexico named windstorm event are the greater of $10.0 million or the operational deductible for each U.S. Gulf of Mexico named windstorm. The Company is self-insured for 10% above the deductibles for removal of wreck, sue and labor, collision, protection and indemnity general liability and hull and physical damage policies. The protection and indemnity coverage under the primary marine package has a $5.0 million limit per occurrence with excess liability coverage up to $200.0 million. The primary marine package also provides coverage for cargo and charterer’s legal liability. Vessel pollution is covered under a Water Quality Insurance Syndicate policy. In addition to the marine package, the Company has separate policies providing coverage for onshore general liability, employer’s liability, auto liability and non-owned aircraft liability, with customary deductibles and coverage.

In May 2008, in connection with the renewal of certain of its insurance policies, the Company entered into agreements to finance a portion of its annual insurance premiums. Approximately $32.1 million was financed through these arrangements of which $32.1 million was outstanding at June 30, 2008. The interest rate on these notes is 4.42% and the note matures in April 2009. There was $16.9 million outstanding in insurance note payable at December 31, 2007 at an interest rate of 5.75%.

Surety Bonds and Unsecured Letters of Credit

In connection with the TODCO acquisition in July 2007 (See Note 3), the Company assumed certain surety bonds. There was $58.1 million outstanding related to surety bonds at June 30, 2008. The surety bonds guarantee our performance as it relates to the Company’s drilling contracts, insurance, tax and other obligations in various jurisdictions. These obligations could be called at any time prior to the expiration dates. The obligations that are the subject of the surety bonds are geographically concentrated primarily in Mexico.

The Company had $0.1 million in unsecured letters of credit outstanding at June 30, 2008.

Insurance Claims

The Company acquired several jackup rigs that were damaged by Hurricanes Rita and Katrina and one jackup rig that was damaged in a collision. During the six months ended June 30, 2008, the Company received $25.3 million in proceeds related primarily to the settlement of claims for damage incurred during Hurricanes Rita and Katrina. At June 30, 2008, $4.2 million was outstanding for insurance claims receivable primarily related to Hercules 205 which was damaged in a collision.

12. Accounting Pronouncements

In May 2008, the Financial Accounting Standards Board (“FASB”) issued Staff Position No. APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement) (“the FSP”), which clarifies the accounting for convertible debt instruments that may be settled in cash (including partial cash settlement) upon conversion. The FSP requires issuers to account separately for the liability and equity components of certain convertible debt instruments in a manner that reflects the issuer’s nonconvertible debt (unsecured debt) borrowing rate when interest cost is recognized. The FSP requires bifurcation of a component of the debt, classification of that component in equity and the accretion of the resulting discount on the debt to be recognized as part of interest expense in the Company’s consolidated statement of operations. The FSP requires retrospective application to the terms of instruments as they existed for all periods presented. The FSP is effective as of January 1, 2009 and early adoption is not permitted. The adoption of this FSP will affect the accounting for the Company’s 3.375% Convertible Senior Notes due June 2038. The Company is currently evaluating the earnings impact the adoption of FSP APB 14-1 will have on its consolidated financial statements; however the Company expects the adoption to significantly reduce reported earnings.

In March 2008, FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities (“SFAS 161”). SFAS 161 amends SFAS 133 requiring enhanced disclosures about an entity’s derivative and hedging activities thereby improving the transparency of financial reporting. SFAS 161’s disclosures provide additional information on how and why derivative instruments are being used. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. We are currently evaluating the impact of adopting SFAS 161 on our consolidated financial statements.

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

In December 2007, the FASB issued SFAS No. 141R, Business Combinations (“SFAS No. 141R”). SFAS No. 141R replaces SFAS No. 141, Business Combinations, and applies to all transactions and other events in which one entity obtains control over one or more other businesses. SFAS No. 141R requires an acquirer, upon initially obtaining control of another entity, to recognize the assets, liabilities and any non-controlling interest in the acquiree at fair value as of the acquisition date. Contingent consideration is required to be recognized and measured at fair value on the date of acquisition rather than at a later date when the amount of that consideration may be determinable beyond a reasonable doubt. This fair value approach replaces the cost-allocation process required under SFAS No. 141 whereby the cost of an acquisition was allocated to the individual assets acquired and liabilities assumed based on their estimated fair value. SFAS No. 141R requires acquirers to expense acquisition-related costs as incurred rather than allocating such costs to the assets acquired and liabilities assumed, as was previously the case under SFAS No. 141. Under SFAS No. 141R, the requirements of SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities would have to be met in order to accrue for a restructuring plan in purchase accounting. Pre-acquisition contingencies are to be recognized at fair value, unless it is a non-contractual contingency that is not likely to materialize, in which case, nothing should be recognized in purchase accounting and, instead, that contingency would be subject to the probable and estimable recognition criteria of SFAS No. 5, Accounting for Contingencies. SFAS No. 141R may have a significant impact on the Company’s accounting for business combinations closing on or after January 1, 2009.

The Company adopted, without material impact to its consolidated financial statements, the provisions of SFAS No.157, Fair Value Measurements (“SFAS No. 157”) related to financial assets and liabilities and to nonfinancial assets and liabilities measured at fair value on a recurring basis on January 1, 2008. SFAS No. 157 defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements, rather, its application is made pursuant to other accounting pronouncements that require or permit fair value measurements. In February 2008, the FASB issued FASB Staff Position (FSP) SFAS 157-2, Effective Date of FASB Statement No. 157, which defers the effective date of SFAS No. 157 for one year for certain nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. The Company will adopt the provision for nonfinancial assets and liabilities that are not required or permitted to be measured at fair value on a recurring basis, which include those measured at fair value in impairment testing and those initially measured at fair value in a business combination. The Company does not expect the provisions of SFAS No. 157 related to these items to have a material impact on its consolidated financial statements.

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

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, 2008 and for the three and six months ended June 30, 2008 and June 30, 2007, included elsewhere herein, and with our annual report on Form 10-K for the year ended December 31, 2007. The following information contains forward-looking statements. Please read “Forward-Looking Statements” below for a discussion of certain limitations inherent in such statements. Please also read “Risk Factors” in Item 1A of our annual report for a discussion of certain risks facing our company.

OVERVIEW

We provide shallow-water drilling and marine services to the oil and natural gas exploration and production industry in the U.S. Gulf of Mexico and internationally. We provide these services to major integrated energy companies, independent oil and natural gas operators and national oil companies.

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

In the first quarter of 2008, we purchased two jackup drilling rigs and related equipment for $220.0 million with cash on hand. In addition, during the second quarter of 2008, we purchased a third jackup rig and related equipment for $100.0 million.

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

Domestic Offshore – operates 24 jackup rigs and three submersible rigs in the U.S. Gulf of Mexico that can drill in maximum water depths ranging from 85 to 350 feet.

International Offshore – operates 11 jackup rigs and one platform rig outside of the U.S. Gulf of Mexico. We have one jackup rig working offshore in each of the following international locations: Qatar, Angola and Gabon. We have two jackup rigs working offshore in India and two jackup rigs and one platform rig operating in Mexico. In addition, we have one jackup rig undergoing reactivation in Southeast Asia, one jackup rig undergoing contract preparation work in the Middle East and one jackup rig in transit to the Middle East where upon arrival, it will undergo contract preparation work. We have one jackup rig cold stacked in Trinidad.

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

Domestic Liftboats – operates 45 liftboats in the U.S. Gulf of Mexico.

International Liftboats – operates 20 liftboats. Eighteen are operating offshore West Africa, including five liftboats owned by a third party. One liftboat is in transit to the Middle East and one liftboat is currently undergoing refurbishment in the Middle East.

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

Our jackup and submersible rigs and our barge rigs are used primarily for exploration and development drilling in shallow waters. Under most of our contracts, we are paid a fixed daily rental rate called a “dayrate,” and we are required to pay all costs associated with our own crews as well as the upkeep and insurance of the rig and equipment.

Our liftboats are self-propelled, self-elevating vessels that support a broad range of offshore support services, including platform maintenance, platform construction, well intervention and decommissioning services throughout the life of an oil or natural gas well. Under most of our liftboat contracts, we are paid a fixed dayrate for the rental of the vessel, which typically includes the costs of a small crew of four to eight employees, and we also receive a variable rate for reimbursement of other operating costs such as catering, fuel, rental equipment and other items.

Our revenues are affected primarily by dayrates, fleet utilization, 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 21, 2008 totaled approximately $1,061.3 million for our executed contracts. Approximately $296.3 million of this backlog is expected to be realized during the remainder of 2008. We calculate our backlog, or future contracted revenue, as the contract dayrate multiplied by the number of days remaining on the contract, assuming full utilization. Backlog excludes revenues for mobilization, demobilization, contract preparation and customer reimbursables. The amount of actual revenues earned and the actual periods during which revenues are earned will be different than the amount disclosed or expected due to various factors. Downtime due to various 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, as well as the ability of our customers to terminate contracts under certain circumstances.

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

On July 11, 2007, we completed the acquisition of TODCO for total consideration of approximately $2,397.8 million, consisting of $925.8 million in cash and 56.6 million shares of common stock. Our results for the three and six months ended June 30, 2008 include activity from this acquired business. The acquisition significantly impacts the comparability of the 2008 periods with the corresponding 2007 periods. We are unable to provide certain information regarding our current period results excluding the impact of the TODCO acquisition due to the integration of this acquisition into our operations.

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


	Three Months Ended June 30,					Six Months Ended June 30,
	2008			2007		2008			2007
	(Dollars in thousands)
Domestic Offshore:
Number of rigs (as of end of period)		27			6		27			6
Revenues	$	97,438		$	28,325	$	159,885		$	71,156
Operating expenses		56,275			13,899		104,047			27,462
Depreciation and amortization expense		16,204			2,691		31,539			5,252
General and administrative expenses		1,382			1,611		2,612			3,553

Operating income	$	23,577		$	10,124	$	21,687		$	34,889

International Offshore:
Number of rigs (as of end of period)		12			3		12			3
Revenues	$	74,187		$	19,640	$	139,530		$	40,516
Operating expenses		37,308			7,335		60,100			14,718
Depreciation and amortization expense		9,310			1,363		16,896			2,731
General and administrative expenses		145			1,015		760			1,545

Operating income	$	27,424		$	9,927	$	61,774		$	21,522

Inland:
Number of barges (as of end of period)		27			—		27			—
Revenues	$	40,262		$	—	$	80,530		$	—
Operating expenses		31,306			—		63,232			—
Depreciation and amortization expense		10,520			—		20,180			—
General and administrative expenses		1,350			—		1,972			—

Operating loss	$	(2,914	)	$	—	$	(4,854	)	$	—

Domestic Liftboats:
Number of liftboats (as of end of period)		45			47		45			47
Revenues	$	22,269		$	37,195	$	38,213		$	69,898
Operating expenses		13,446			15,639		27,340			29,279
Depreciation and amortization expense		5,382			6,192		11,334			12,262
General and administrative expenses		468			539		1,117			1,077

Operating income (loss)	$	2,973		$	14,825	$	(1,578	)	$	27,280

International Liftboats:
Number of liftboats (as of end of period)		20			18		20			18
Revenues	$	20,305		$	13,884	$	38,596		$	27,938
Operating expenses		9,896			7,523		17,116			14,464
Depreciation and amortization expense		2,368			1,938		4,352			3,642
General and administrative expenses		1,289			882		2,228			1,832

Operating income	$	6,752		$	3,541	$	14,900		$	8,000


	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
Other:
Revenues	$	16,369		$	—		$	27,462		$	—
Operating expenses		10,639			—			19,844			—
Depreciation and amortization expense		2,712			—			5,287			—
General and administrative expenses		703			—			1,285			—

Operating income	$	2,315		$	—		$	1,046		$	—

Total Company:
Revenues	$	270,830		$	99,044		$	484,216		$	209,508
Operating expenses		158,870			44,396			291,679			85,923
Depreciation and amortization expense		47,280			12,209			90,906			23,939
General and administrative expenses		23,966			9,335			40,330			18,498

Operating income		40,714			33,104			61,301			81,148
Interest expense		(14,579	)		(1,379	)		(30,539	)		(3,469	)
Loss on early retirement of debt		—			(870	)		—			(870	)
Other, net		67			1,246			2,274			2,521

Income before income taxes		26,202			32,101			33,036			79,330
Income tax provision		(9,759	)		(8,635	)		(12,107	)		(22,473	)

Net income	$	16,443		$	23,466		$	20,929		$	56,857

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


	Three Months Ended June 30, 2008
										Average
								Average		Operating
	Operating		Available					Revenue		Expense per
	Days		Days		Utilization (1)			per Day (2)		Day (3)
Domestic Offshore		1,612		2,024		79.6	%	$	60,445	$	27,804
International Offshore		642		732		87.7	%		115,556		50,967
Inland		1,017		1,486		68.4	%		39,589		21,067
Domestic Liftboats		2,466		3,871		63.7	%		9,030		3,474
International Liftboats		1,331		1,590		83.7	%		15,255		6,224


	Three Months Ended June 30, 2007
										Average
								Average		Operating
	Operating		Available					Revenue		Expense
	Days		Days		Utilization (1)			per Day (2)		per Day (3)
Domestic Offshore		375		546		68.7	%	$	75,531	$	25,455
International Offshore		179		182		98.4	%		109,719		40,305
Inland		—		—		—			—		—
Domestic Liftboats		2,980		4,186		71.2	%		12,482		3,736
International Liftboats		1,252		1,547		80.9	%		11,090		4,862


	Six Months Ended June 30, 2008
										Average
								Average		Operating
	Operating		Available					Revenue		Expense
	Days		Days		Utilization (1)			per Day (2)		per Day (3)
Domestic Offshore		2,710		4,026		67.3	%	$	58,998	$	25,844
International Offshore		1,296		1,441		89.9	%		107,662		41,707
Inland		1,955		3,033		64.5	%		41,192		20,848
Domestic Liftboats		4,066		8,057		50.5	%		9,398		3,393
International Liftboats		2,548		3,137		81.2	%		15,148		5,456


	Six Months Ended June 30, 2007
										Average
								Average		Operating
	Operating		Available					Revenue		Expense
	Days		Days		Utilization (1)			per Day (2)		per Day (3)
Domestic Offshore		849		1,086		78.2	%	$	83,812	$	25,287
International Offshore		359		362		99.2	%		112,857		40,659
Inland		—		—		—			—		—
Domestic Liftboats		5,647		8,285		68.2	%		12,378		3,534
International Liftboats		2,414		3,021		79.9	%		11,573		4,788

(1)		Utilization is defined as the total number of days our rigs or liftboats, as applicable, were under contract, known as operating days, in the period as a percentage of the total number of available days in the period. Days during which our rigs and liftboats were undergoing major refurbishments, upgrades or construction, and days during which our rigs and liftboats are cold-stacked, are not counted as available days. Days during which our liftboats are in the shipyard undergoing drydocking or inspection are considered available days for the purposes of calculating utilization.

(2)		Average revenue per rig or liftboat per day is defined as revenue earned by our rigs or liftboats, as applicable, in the period divided by the total number of operating days for our rigs or liftboats, as applicable, in the period. Included in Domestic Offshore revenue is a total of $0.1 million related to amortization of contract specific capital expenditures reimbursed by the customer for the three and six months ended June 30, 2007. There was no such revenue in the three and six months ended June 30, 2008. Included in International Offshore revenue is a total of $4.2 million and $6.2 million related to amortization of deferred mobilization revenue and contract specific capital expenditures reimbursed by the customer for the three and six months ended June 30, 2008, respectively, and $0.7 million and $2.5 million for the three and six months ended June 30, 2007, respectively.

(3)		Average operating expense per rig or liftboat per day is defined as operating expenses, excluding depreciation and amortization, incurred by our rigs or liftboats, as applicable, in the period divided by the total number of available days in the period. We use available days to calculate average operating expense per rig or liftboat per day rather than operating days, which are used to calculate average revenue per rig or liftboat per day, because we incur operating expenses on our rigs and liftboats even when they are not under contract and earning a dayrate. In addition, the operating expenses we incur on our rigs and liftboats per day when they are not under contract are typically lower than the per-day expenses we incur when they are under contract. Included in International Offshore operating expense is a total of $2.1 million and $3.0 million related to amortization of deferred mobilization expenses for the three and six months ended June 30, 2008, respectively, and $0.4 million and $1.6 million for the three and six months ended June 30, 2007, respectively.

For the Three Months Ended June 30, 2008 and 2007

Revenues

Consolidated. Total revenues for the three-month period ended June 30, 2008 (the “Current Quarter”) were $270.8 million compared with $99.0 million for the three-month period ended June 30, 2007 (the “Comparable Quarter”), an increase of $171.8 million, or 173%. This increase resulted primarily from revenues generated from assets acquired from TODCO (“Acquired Assets”) in July 2007. Total revenues included $3.9 million in reimbursements from our customers for expenses paid by us in the Current Quarter compared with $2.3 million in the Comparable Quarter.

Domestic Offshore. Revenues for our Domestic Offshore segment were $97.4 million for the Current Quarter compared with $28.3 million for the Comparable Quarter, an increase of $69.1 million, or 244%. Revenues for the Current Quarter include

approximately $69.2 million from the Acquired Assets. Excluding the revenue from the Acquired Assets, revenue was in line with the Comparable Quarter. Average utilization was 79.6% in the Current Quarter compared with 68.7% in the Comparable Quarter. Average revenue per rig per day was $60,445 in the Current Quarter compared with $75,531 in the Comparable Quarter. Lower revenue per day reflects our customers’ lower drilling activity. Revenues for our Domestic Offshore segment include $0.3 million and $0.1 million in reimbursements from our customers for expenses paid by us in the Current Quarter and Comparable Quarter, respectively.

International Offshore. Revenues for our International Offshore segment were $74.2 million for the Current Quarter compared with $19.6 million for the Comparable Quarter, an increase of $54.5 million, or 278%. Revenues for the Current Quarter include approximately $49.4 million from the Acquired Assets. Excluding the impact of the Acquired Assets, revenue increased by $5.1 million, of which $4.4 million was due to higher average dayrates in the current period and $0.7 million was due to increased operating days. Average utilization was 87.7% in the Current Quarter compared with 98.4% in the Comparable Quarter. Average revenue per rig per day was $115,556 in the Current Quarter compared with $109,719 in the Comparable Quarter. Included in our Revenues for the International Offshore segment is a total of $4.2 million and $0.7 million related to amortization of deferred mobilization revenue and contract specific capital expenditures reimbursed by the customer for the Current Quarter and Comparable Quarter, respectively.

Inland. Revenues for our Inland segment were $40.3 million in the Current Quarter, with 1,017 operating days and average revenue per rig per day of $39,589. Revenues for our Inland segment included $0.5 million in reimbursements from our customers for expenses paid by us in the Current Quarter. Prior to our acquisition of TODCO in July 2007, we did not have an Inland segment.

Domestic Liftboats. Revenues for our Domestic Liftboats segment were $22.3 million for the Current Quarter compared with $37.2 million in the Comparable Quarter, a decrease of $14.9 million, or 40%. This decrease resulted primarily from lower average dayrates, which contributed $10.3 million of the decrease, and fewer operating days, which contributed $4.6 million of the decrease. Operating days decreased to 2,466 in the Current Quarter from 2,980 in the Comparable Quarter due primarily to lower customer activity in the Gulf of Mexico in the Current Quarter as compared to the Comparable Quarter. Average utilization also declined to 63.7% in the Current Quarter from 71.2% in the Comparable Quarter. Average revenue per vessel per day was $9,030 in the Current Quarter compared with $12,482 in the Comparable Quarter, a decrease of $3,452. Approximately $647 of the decrease in average revenue per vessel per day was due to mix of vessel class and approximately $2,805 was due to lower dayrates. Revenues for our Domestic Liftboats segment included $1.3 million in reimbursements from our customers for expenses paid by us in the Current Quarter compared with $1.5 million in the Comparable Quarter.

International Liftboats. Revenues for our International Liftboats segment were $20.3 million for the Current Quarter compared with $13.8 million in the Comparable Quarter, an increase of $6.4 million, or 46%. This increase resulted primarily from higher average dayrates, which contributed $5.2 million of the increase, and increased operating days, which contributed $1.2 million of the increase. Operating days increased to 1,331 days in the Current Quarter from 1,252 days in the Comparable Quarter. Average revenue per liftboat per day was $15,255 in the Current Quarter compared with $11,090 in the Comparable Quarter, with average utilization of 83.7% in the Current Quarter compared with 80.9% in the Comparable Quarter. Revenues for our International Liftboats segment included $1.6 million and $0.7 million in reimbursements from our customers for expenses paid by us in the Current Quarter and Comparable Quarter, respectively.

Other. Revenues for our Other segment were $16.4 million in the Current Quarter and included $0.1 million in reimbursements from our customers for expenses paid by us in the Current Quarter. Prior to our acquisition of TODCO in July 2007, we did not have an Other segment.

Operating Expenses

Consolidated. Total operating expenses for the Current Quarter were $158.9 million compared with $44.4 million in the Comparable Quarter, an increase of $114.5 million, or 258%. This increase is further described below.

Domestic Offshore. Operating expenses for our Domestic Offshore segment were $56.3 million in the Current Quarter compared with $13.9 million in the Comparable Quarter, an increase of $42.4 million, or 305%. Operating expenses for the Current Quarter include approximately $35.8 million associated with the Acquired Assets. Available days increased to 2,024 in the Current Quarter from 546 in the Comparable Quarter. Average operating expenses per rig per day were $27,804 in the Current Quarter compared with $25,455 in the Comparable Quarter. The increase was driven primarily by higher labor, workers compensation, repairs and maintenance, fuel and other costs, partially offset by lower insurance costs.

International Offshore. Operating expenses for our International Offshore segment were $37.3 million in the Current Quarter compared with $7.3 million in the Comparable Quarter, an increase of $30.0 million, or 409%. Operating expenses for the Current Quarter include approximately $20.8 million associated with the Acquired Assets. Available days increased to 732 in the Current Quarter from 182 in the Comparable Quarter. Average operating expenses per rig per day were $50,967 in the Current Quarter

compared with $40,305 in the Comparable Quarter. The increase resulted primarily from higher rentals, contract labor, amortization of deferred mobilization and contract preparation expenses, partially offset by lower labor and insurance costs. Included in operating expense is $2.1 million in amortization of deferred mobilization expense in the Current Quarter compared with $0.4 million in the Comparable Quarter.

Inland. Operating expenses for our Inland segment were $31.3 million in the Current Quarter, with 1,486 available days and average operating expenses per rig per day of $21,067. Prior to our acquisition of TODCO in July 2007, we did not have an Inland segment.

Domestic Liftboats. Operating expenses for our Domestic Liftboats segment were $13.4 million in the Current Quarter compared with $15.6 million in the Comparable Quarter, a decrease of $2.2 million, or 14%. Available days decreased to 3,871 in the Current Quarter from 4,186 in the Comparable Quarter. Average operating expenses per vessel per day were $3,474 in the Current Quarter compared with $3,736 in the Comparable Quarter. This decrease is primarily due to lower repairs and maintenance and insurance costs, partially offset by higher fuel purchases due to lower utilization.

International Liftboats. Operating expenses for our International Liftboats segment were $9.9 million for the Current Quarter compared with $7.5 million in the Comparable Quarter, an increase of $2.4 million, or 32%. Average operating expenses per liftboat per day were $6,224 in the Current Quarter compared with $4,862 in the Comparable Quarter. This increase was driven primarily by costs accrued for a payment to a former owner, as well as increased labor and insurance costs.

Other. Operating expenses for our Other segment were $10.6 million in the Current Quarter. Prior to our acquisition of TODCO in July 2007, we did not have an Other segment.

Depreciation and Amortization

Depreciation and amortization expense in the Current Quarter was $47.3 million compared with $12.2 million in the Comparable Quarter, an increase of $35.1 million, or 287%. This increase resulted primarily from additional depreciation of approximately $33.7 million related to the Acquired Assets.

General and Administrative Expenses

General and administrative expenses in the Current Quarter were $24.0 million compared with $9.3 million in the Comparable Quarter, an increase of $14.6 million, or 157%. The increase is primarily related to incremental general and administrative costs associated with the Acquired Assets as well as $5.5 million in executive severance related costs.

Interest Expense

Interest expense increased $13.2 million, or 957%. The increase was primarily due to interest on our borrowings under our 2007 senior secured term loan.

Other Income

Other income in the Current Quarter was $0.1 million compared with $1.2 million in the Comparable Quarter, a decrease of $1.1 million. This decrease is primarily due to lower interest income due to decreased cash balances in the Current Quarter as well as the Comparable Quarter including a gain of $0.3 million related to the settlement of an interest rate swap.

Income Tax Provision

Income tax expense was $9.8 million on pre-tax income of $26.2 million during the Current Quarter, compared to $8.6 million on pre-tax income of $32.1 million for the Comparable Quarter. The effective tax rate increased to 37.2% in the Current Quarter from 26.9% in the Comparable Quarter. The increase in the effective tax rate reflects the impact of higher non-creditable foreign taxes and the impact of taxes on certain foreign earnings which management expects to repatriate in the future.

For the Six Months Ended June 30, 2008 and 2007

Revenues

Consolidated. Total revenues for the six-month period ended June 30, 2008 (the “Current Period”) were $484.2 million compared with $209.5 million for the six-month period ended June 30, 2007 (the “Comparable Period”), an increase of $274.7 million, or 131%. This increase resulted primarily from revenues generated from the Acquired Assets. Total revenues included $6.8 million in reimbursements from our customers for expenses paid by us in the Current Period compared with $5.5 million in the Comparable Period.

Domestic Offshore. Revenues for our Domestic Offshore segment were $159.9 million for the Current Period compared with $71.2 million for the Comparable Period, an increase of $88.7 million, or 125%. Revenues for the Current Period include approximately $112.4 million from the Acquired Assets. Excluding the revenue from the Acquired Assets, revenue decreased by approximately $23.7 million, of which $21.3 million was due to lower average dayrates and $2.4 million was due to fewer operating days for our fleet. Average utilization was 67.3% in the Current Period compared with 78.2% in the Comparable Period primarily due to the stacking of rigs in the second half of 2007 and our customers’ lower drilling activity. Average revenue per rig per day was $58,998 in the Current Period compared with $83,812 in the Comparable Period. Lower revenue per day also reflects our customers’ lower drilling activity. Revenues for our Domestic Offshore segment include $0.7 million and $0.6 million in reimbursements from our customers for expenses paid by us in the Current Period and Comparable Period, respectively.

International Offshore. Revenues for our International Offshore segment were $139.5 million for the Current Period compared with $40.5 million for the Comparable Period, an increase of $99.0 million, or 244%. Revenues for the Current Period include approximately $97.9 million from the Acquired Assets. Excluding the impact of the Acquired Assets, revenue increased by $1.1 million, of which $2.6 million was due to higher average dayrates in the Current Period, partially offset by a decrease of $1.5 million due to fewer operating days. Average utilization was 89.9% in the Current Period compared with 99.2% in the Comparable Period. Average revenue per rig per day was $107,662 in the Current Period compared with $112,857 in the Comparable Period. Included in our Revenues for the International Offshore segment is a total of $6.2 million and $2.5 million related to amortization of deferred mobilization revenue and contract specific capital expenditures reimbursed by the customer for the Current Period and Comparable Period, respectively. In addition, revenues for our International Offshore segment included $0.4 million and $0.3 million in reimbursements from our customers for expenses paid by us in the Current Period and Comparable Period, respectively.

Inland. Revenues for our Inland segment were $80.5 million in the Current Period, with 1,955 operating days and average revenue per rig per day of $41,192. Revenues for our Inland segment included $0.8 million in reimbursements from our customers for expenses paid by us in the Current Period. Prior to our acquisition of TODCO in July 2007, we did not have an Inland segment.

Domestic Liftboats. Revenues for our Domestic Liftboats segment were $38.2 million for the Current Period compared with $69.9 million in the Comparable Period, a decrease of $31.7 million, or 45.3%. This decrease resulted primarily from lower average dayrates, which contributed $16.8 million of the decrease, and fewer operating days, which contributed $14.9 million of the decrease. Operating days decreased to 4,066 in the Current Period from 5,647 in the Comparable Period due primarily to lower customer activity in the Gulf of Mexico in the Current Period as compared to the Comparable Period. Average utilization also declined to 50.5% in the Current Quarter from 68.2% in the Comparable Period. Average revenue per vessel per day was $9,398 in the Current Period compared with $12,378 in the Comparable Period, a decrease of $2,980. Approximately $915 of the decrease in average revenue per vessel per day was due to mix of vessel class and approximately $2,065 was due to lower dayrates. Revenues for our Domestic Liftboats segment included $2.0 million in reimbursements from our customers for expenses paid by us in the Current Period compared with $2.8 million in the Comparable Period.

International Liftboats. Revenues for our International Liftboats segment were $38.6 million for the Current Period compared with $27.9 million in the Comparable Period, an increase of $10.7 million, or 38%. The increase resulted primarily from higher average dayrates, which contributed $8.6 million of the increase, and additional operating days, which contributed $2.0 million of the increase. Operating days increased from 2,414 days in the Comparable Period to 2,548 days in the Current Period. Average revenue per liftboat per day was $15,148 in the Current Period compared with $11,573 in the Comparable Period, with average utilization of 81.2% in the Current Period compared with 79.9% in the Comparable Period. Revenues for our International Liftboats segment included $2.8 million and $1.9 million in reimbursements from our customers for expenses paid by us in the Current Period and Comparable Period.

Other. Revenues for our Other segment were $27.5 million in the Current Period and included $0.2 million in reimbursements from our customers for expenses paid by us in the Current Period. Prior to our acquisition of TODCO in July 2007, we did not have an Other segment.

Operating Expenses

Consolidated. Total operating expenses for the Current Period were $291.7 million compared with $85.9 million in the Comparable Quarter, an increase of $205.8 million, or 239%. This increase is further described below.

Domestic Offshore. Operating expenses for our Domestic Offshore segment were $104.0 million in the Current Period compared with $27.5 million in the Comparable Period, an increase of $76.6 million, or 279%. Operating expenses for the Current Period include approximately $67.3 million associated with the Acquired Assets. Available days increased to 4,026 in the Current Period from 1,086 in the Comparable Period. Average operating expenses per rig per day were $25,844 in the Current Period compared with $25,287 in the Comparable Period. The increase was driven primarily by higher labor, workers compensation, fuel, repairs and maintenance and other costs partially offset by lower insurance costs.

International Offshore. Operating expenses for our International Offshore segment were $60.1 million in the Current Period compared with $14.7 million in the Comparable Period, an increase of $45.4 million, or 308%. Operating expenses for the Current Period include approximately $37.1 million associated with the Acquired Assets. Available days increased to 1,441 in the Current Period from 362 in the Comparable Period. Average operating expenses per rig per day were $41,707 in the Current Period compared with $40,659 in the Comparable Period. Included in operating expense is $3.0 million in amortization of deferred mobilization expense in the Current Period compared with $1.6 million in the Comparable Period.

Inland. Operating expenses for our Inland segment were $63.2 million in the Current Period, with 3,033 available days and average operating expenses per rig per day of $20,848. Prior to our acquisition of TODCO in July 2007, we did not have an Inland segment.

Domestic Liftboats. Operating expenses for our Domestic Liftboats segment were $27.3 million in the Current Period compared with $29.3 million in the Comparable Period, a decrease of $1.9 million, or 7%. Available days decreased to 8,057 in the Current Quarter from 8,285 in the Comparable Period. Average operating expenses per vessel per day were $3,393 in the Current Period compared with $3,534 in the Comparable Period. The decrease was primarily due to lower repairs and maintenance and insurance costs, partially offset by higher labor and fuel costs.

International Liftboats. Operating expenses for our International Liftboats segment were $17.1 million for the Current Period compared with $14.5 million in the Comparable Period, an increase of $2.7 million, or 18%. Average operating expenses per liftboat per day were $5,456 in the Current Period compared with $4,788 in the Comparable Period. This increase was driven primarily by costs accrued, for a payment to a former owner, as well as increased insurance and labor costs.

Other. Operating expenses for our Other segment were $19.8 million in the Current Period. Prior to our acquisition of TODCO in July 2007, we did not have an Other segment.

Depreciation and Amortization

Depreciation and amortization expense in the Current Period was $90.9 million compared with $23.9 million in the Comparable Period, an increase of $67.0 million, or 280%. This increase resulted primarily from additional depreciation of approximately $65.6 million related to the Acquired Assets.

General and Administrative Expenses

General and administrative expenses in the Current Period were $40.3 million compared with $18.5 million in the Comparable Period, an increase of $21.8 million, or 118%. The increase is primarily related to incremental general and administrative costs associated with the Acquired Assets as well as $5.5 million in executive severance related costs.

Interest Expense

Interest expense increased $27.1 million, or 780%. The increase was primarily due to interest on our borrowings under our 2007 senior secured term loan.

Other Income

Other income in the Current Period was $2.3 million compared with $2.5 million in the Comparable Period, a decrease of $0.2 million or 10%. This decrease is primarily due to higher interest income, partially offset by a gain in the Comparable period related to the settlement of an interest rate swap.

Income Tax Provision

Income tax expense was $12.1 million on pre-tax income of $33.0 million during the Current Period, compared to $22.5 million on pre-tax income of $79.3 million for the Comparable Period. The effective tax rate increased to 36.6% in the Current Period from 28.3% in the Comparable Period. The increase in the effective tax rate reflects the impact of higher non-creditable foreign taxes and the impact of taxes on certain foreign earnings which management expects to repatriate in the future.

CRITICAL ACCOUNTING POLICIES

Critical accounting policies are those that are important to our results of operations, financial condition and cash flows and require management’s most difficult, subjective or complex judgments. Different amounts would be reported under alternative assumptions. We have evaluated the accounting policies used in the preparation of the unaudited consolidated financial statements and related notes appearing elsewhere in this quarterly report. We apply those accounting policies that we believe best reflect the underlying business and economic events, consistent with accounting principles generally accepted in the United States. We believe that our policies are generally consistent with those used by other companies in our industry.

We periodically update the estimates used in the preparation of the financial statements based on our latest assessment of the current and projected business and general economic environment. We believe that our more critical accounting policies include those related to property and equipment, revenue recognition, income tax, allowance for doubtful accounts, deferred charges, stock-based compensation, cash and cash equivalents and marketable securities, goodwill and intangible assets. Inherent in such policies are certain key assumptions and estimates. For additional information regarding our critical accounting policies, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies” in Item 7 of our annual report on Form 10-K for the year ended December 31, 2007.

OUTLOOK

Offshore

In general, demand for our drilling rigs is a function of our customers’ capital spending plans, which are largely driven by their cash flow generated from commodity production and their expectations of future commodity prices. Demand in the U.S. Gulf of Mexico is particularly driven by natural gas prices, with demand internationally typically driven by oil prices. Both natural gas and oil prices are higher than historical levels and are generally supportive of increased capital spending for exploration and production activities.

As of June 30, 2008, the spot price for Henry Hub natural gas was $13.18 per MMBtu and the twelve month strip, or the average of the next twelve month’s futures contract, was $13.13 per MMBtu. Declining reservoir sizes and increasing initial decline rates in North America have been supportive of natural gas prices, somewhat offset by increased onshore drilling activity, growing deepwater production and potential liquefied natural gas deliveries. These factors, together with weather and industrial demand, will likely remain key drivers in the natural gas market for the foreseeable future.

Oil prices have remained at high levels relative to historical prices for the past several years with the spot price for West Texas intermediate crude ranging from $50.48 to $145.29 per bbl since the beginning of 2006. As of June 30, 2008, the price of WTI was $140.00 with a twelve month strip of $141.14. Stronger oil prices have largely been driven by extremely robust demand growth in China and India and the ongoing weakness in the U.S. dollar.

Global demand for jackup rigs has increased significantly over the last several years with international regions such as the Middle East, India and Mexico being particularly strong. Demand for jackups worldwide, excluding the U.S. Gulf of Mexico, increased from 200 in 2001 to 394 in July 2008. This international demand has drawn available rigs from the U.S. Gulf of Mexico. As a result, the supply of jackup rigs in the U.S. Gulf of Mexico has declined considerably over the last several years from a high of 157 jackups in 2001 to only 79 currently, according to published industry sources. With several of these rigs either in the shipyard or cold stacked, the marketed supply of jackups in the U.S. Gulf of Mexico is currently approximately 66.

U.S. Gulf of Mexico demand of 63 jackups as of July 7, 2008 was an improvement over the December 31, 2007 demand of 56 jackups. However, this recent level of demand is considerably lower than two and a half years ago when demand was 88 jackups in January 2006. A combination of factors has resulted in this decline from the levels experienced over the previous several years, including declining target reservoir sizes, increasing finding, development and lifting costs and the significant amount of property transfers. We believe that the further reduction in supply in the U.S. Gulf of Mexico due to rigs mobilizing to international locations could mitigate the impact of recent reduced drilling demand.

In addition to spurring migration of rigs out of the U.S., strong global demand for jackups over the past few years has encouraged newbuilds. According to ODS-Petrodata, as of July 7, 2008, 85 jackup rigs have been ordered by industry participants,

national oil companies and financial investors for delivery through 2011. We anticipate that these rigs will compete directly with our fleet in international regions. As a result of higher dayrates, longer duration contracts and lower insurance costs, which are prevalent internationally, among other factors, we believe the vast majority of the new build jackup rigs will target international regions and not the U.S. Gulf of Mexico. Our ability to expand our international drilling fleet may be limited, however, by the increased supply of newbuild jackup rigs. Additionally, the migration of jackup rigs from the U.S. Gulf of Mexico to international markets will likely slow due to the newbuild deliveries.

The offshore drilling market remains highly competitive and cyclical, and it has historically been difficult to forecast future market conditions. While future commodity price expectations have historically been a key driver for demand for drilling rigs, other factors also affect our customers’ drilling programs, including the quality of drilling prospects, exploration success, relative production costs, availability of insurance and political and regulatory environments. Additionally, the offshore drilling business has historically been cyclical, marked by periods of low demand, excess rig supply and low dayrates, followed by periods of high demand, short rig supply and increasing dayrates. These cycles have been volatile and are subject to rapid change.

Inland

The market for inland barge drilling in the U.S. generally follows the same drivers as drilling in the U.S. Gulf of Mexico with demand following operators’ expectations of prices for natural gas and, to a lesser degree, crude oil. However, barge rig drilling activity historically lags activity in the U.S. Gulf of Mexico due to a number of factors such as the lengthy permitting process that operators must go through prior to drilling a well in Louisiana, where the majority of our inland drilling takes place, and the predominance of smaller independent operators active in inland waters.

Inland barge drilling activity has slowed over the past year and dayrates have softened as a result of the number of the key operators have curtailed or ceased their activity in the inland market for various reasons including lack of funding, lack of drilling success and re-allocation of capital to other onshore basins.

Despite softness we have experienced in recent months in the inland market, we remain optimistic about deeper targets in the inland barge area, and we believe that longer-term growth opportunities may result from deeper drilling in shallow water.

Liftboats

Demand for liftboats is typically a function of our customer’s demand for platform inspection and maintenance, well maintenance, offshore construction, well plugging and abandonment and other related activities. Although activity levels for liftboats are not as closely correlated to movement in commodity prices as for offshore drilling rigs, commodity prices are still a key driver of demand. Despite the production maintenance related nature of the majority of the work, some of the work may be deferred from time to time.

Following the active 2005 hurricane season, which caused tremendous damage to the infrastructure in the US Gulf of Mexico, liftboat demand in the region was stronger than historical levels for approximately two years. Activity levels now appear to have returned to normal. Furthermore, as approximately 15 new liftboats have been delivered over the past two years, dayrates have softened. As of July 17, 2008, we believe that there were another 10 liftboats under construction or on order in the U.S., with anticipated delivery dates during 2008 and 2009. Once delivered, these liftboats may further impact the demand and utilization of our domestic liftboat fleet.

Our customers’ growth in international capital spending, coupled with an aging infrastructure and significant increases in the cost of alternatives for servicing this infrastructure, has generally resulted in strong demand for our liftboats in West Africa. We anticipate that demand for liftboats will likely increase in West Africa and other international locations as these markets mature and the focus shifts from exploration to development and new platforms and other infrastructure is installed. We anticipate that there will be longer term contract opportunities in international locations for liftboats currently working in the U.S. Gulf of Mexico and for newly constructed liftboats. While we believe that international demand for liftboats will continue to increase, the political instability in certain regions may negatively impact our customers’ capital spending plans. We recently mobilized two of our liftboats to the Middle East from the U.S. Gulf of Mexico and are actively marketing the vessels for use on projects with long-term contract opportunities.

Labor Markets

We require highly skilled personnel to operate our rigs, barges and liftboats and to support our business. Competition for skilled rig personnel could intensify as 85 new offshore rigs are under construction and 60 are scheduled to enter the global fleet during the remainder of 2008 and 2009. If competition for personnel intensifies, our labor costs will likewise increase, although we do not believe at this time that our operations will be limited. We respond to competition though increases in base compensation and retention payments including bonuses tied to retention and operational goals.

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

LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses of Cash

Sources and uses of cash for the six-month period ended June 30, 2008 are as follows (in millions):


Net Cash Provided by Operating Activities	$	68.9
Net Cash Used in Investing Activities
Acquisition of Assets		(320.8	)
Additions of Property and Equipment		(130.5	)
Deferred Drydocking Expenditures		(9.2	)
Sale of Marketable Securities		39.3
Insurance Proceeds Received		25.3
Proceeds from Sale of Assets, Net		12.7

Total		(383.2	)
Net Cash Provided by (Used in) Financing Activities
Short-term Debt Borrowings (Repayments), Net		1.1
Long-term Debt Borrowings		350.0
Long-term Debt Repayments		(104.5	)
Share Repurchases		(49.2	)
Proceeds from Exercise of Stock Options		5.1
Excess Tax Benefit from Stock-Based Arrangements		5.4
Payment of Debt Issuance Costs		(8.0	)

Total		199.9

Net Decrease in Cash and Cash Equivalents	$	(114.4	)

During the six months ended June 30, 2008, we received $25.3 million in proceeds related primarily to the settlement of insurance claims for damage incurred to rigs from Hurricanes Rita and Katrina.

Sources of Liquidity and Financing Arrangements

Our sources of liquidity include current cash and cash equivalent balances, marketable securities, cash generated from operations and committed availability under our revolving credit facility. We also maintain a shelf registration statement covering the future issuance of various types of securities, including debt and equity; however, our senior secured credit facility restricts issuance of additional debt. We believe our cash and cash equivalents, net cash provided by operating activities, available capacity under our revolving credit facility and access to other financing sources will be adequate to meet our anticipated short-term and long-term liquidity requirements, including capital expenditures and scheduled debt repayments. Additional capital in either the form of debt or equity may be required if we generate less than expected cash due to a deterioration of market conditions or other factors beyond our control, or if other acquisitions necessitate additional liquidity.

From time to time we evaluate the possibility of selling certain of our assets, groups of assets and/or operations. We are currently evaluating various strategic options related to our Delta Towing business.

Cash Requirements and Contractual Obligations

Asset Acquisition

In February 2008, we entered into a definitive agreement to purchase three jackup drilling rigs and related equipment for approximately $320.0 million. The purchase of two of the jackup drilling rigs for $220.0 million was completed in the first quarter. In addition, in the second quarter of 2008 we purchased the third jackup rig for $100.0 million. We funded the purchase of the first two rigs with cash on hand and funded the acquisition of the third jackup rig with cash on hand and a portion from borrowings under our revolving credit facility. The $100.0 million borrowed under the revolving credit facility was repaid with a portion of the proceeds received from the issuance of the 3.375% Convertible Senior Notes.

Debt

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

In July 2007, we terminated all prior facilities and we entered into a new $1,050.0 million credit facility, consisting of a $900.0 million term loan and a $150.0 million revolving credit facility. On April 28, 2008, we entered into an agreement with the revolving lenders under our existing credit facility and certain new lenders to increase the maximum amount of our revolving credit facility from $150.0 million to $250.0 million. The increased availability under the facility is to be used for working capital, capital expenditures and other general corporate purposes. All borrowings under the revolving credit facility mature on July 11, 2012, and the revolving credit facility requires interest-only payments on a quarterly basis until the maturity date. No amounts were outstanding and $28.5 million in stand-by letters of credit had been issued under the revolving credit facility as of June 30, 2008. The remaining availability under this revolving credit facility was $221.5 million at June 30, 2008.

As of June 30, 2008, $893.3 million was outstanding on the term loan facility and the interest rate was 4.45%. The annualized effective interest rate was 6.41% for the six months ended June 30, 2008 after giving consideration to derivative activity.

The credit agreement contains financial covenants that are tested quarterly relating to leverage and fixed charge coverage. Other covenants contained in the credit agreement restrict, among other things, asset dispositions, mergers and acquisitions, dividends, stock repurchases and redemptions, other restricted payments, debt, liens, investments and affiliate transactions. The credit agreement contains customary events of default. We were in compliance with these covenants at June 30, 2008.

In July 2007 and May 2008, we entered into derivative instruments with the purpose of hedging future interest payments on our term loan facility. We entered into a floating to fixed interest rate swap with varying notional amounts beginning with $100.0 million with a settlement date of October 1, 2008 and ending with $75.0 million with a settlement date of December 31, 2009. We receive an interest rate of three-month LIBOR and pay a fixed coupon of 2.980% over six quarters. The terms and settlement dates of the swap match those of the term loan. We entered into a floating to fixed interest rate swap with decreasing notional amounts beginning with $400.0 million with a settlement date of December 31, 2007 and ending with $50.0 million with a settlement date of April 1, 2009. We receive an interest rate of three-month LIBOR and pay a fixed coupon of 5.307% over six quarters. The terms and settlement dates of the swap match those of the term loan. We also entered into a zero cost LIBOR collar on $300.0 million of term loan principal over three years, with a ceiling of 5.75% and a floor of 4.99%. The counterparty is obligated to pay us in any quarter that actual LIBOR resets above 5.75% and we pay the counterparty in any quarter that actual LIBOR resets below 4.99%. The terms and settlement dates of the collar match those of the term loan. The change in the fair value of these hedging instruments resulted in an increase in a derivative asset of $0.8 million and an increase in a derivative liability of $3.4 million during the six months ended June 30, 2008. This resulted in unrealized gains of $5.4 million, net of tax of $2.9 million for the three months ended June 30, 2008 and losses on hedge transactions of $1.7 million, net of tax of $0.9 million for the six months ended June 30, 2008. We did not recognize a gain or loss due to hedge ineffectiveness in the Consolidated Statements of Operations for the three and six months ended June 30, 2008 related to these hedging instruments. In addition, our interest expense was increased by $3.7 million and $4.3 million during the three and six months ended June 30, 2008 as a result of our interest rate derivative instruments.

On June 3, 2008, we completed an offering of $250.0 million convertible senior notes at a coupon rate of 3.375% (“3.375% Convertible Senior Notes”) with a maturity in June 2038. The interest on the notes is payable in cash semi-annually in arrears, on June 1 and December 1 of each year until June 1, 2013, after which the principal will accrete at an annual yield to maturity of 3.375% per year. We will also pay contingent interest during any six-month interest period commencing June 1, 2013, for which the trading price of these notes for a specified period of time equals or exceeds 120% of their accreted principal amount. The notes will be convertible under certain circumstances into shares of our common stock at an initial conversion rate of 19.9695 shares of common stock per $1,000 principal amount of notes, which is equal to an initial conversion price of approximately $50.08 per share. Upon conversion of a note, a holder will receive, at our election, shares of common stock, cash or a combination of cash and shares of common stock. We may redeem the notes at our option beginning June 6, 2013, and holders of the notes will have the right to require us to repurchase the notes on certain dates or on the occurrence of a fundamental change. Net proceeds of $243.5 million were used to purchase approximately 1.45 million shares, or $49.2 million, of our common stock, to repay outstanding borrowings

under its senior secured revolving credit facility which totaled $100.0 million at the time of the offering and for other general corporate purposes.

In connection with the TODCO acquisition in July 2007, we assumed senior notes and an unsecured line of credit with a bank in Venezuela. The senior notes included 6.95% Senior Notes due in April 2008, 7.375% Senior Notes due in April 2018, and 9.5% Senior Notes due in December 2008 (collectively, “Senior Notes”). The 6.95% Senior Notes were repaid in April 2008. The fair market value of the 7.375% Senior Notes and 9.5% Senior Notes at June 30, 2008 was approximately $3.5 million and $10.2 million, respectively, based on the most recent market valuations. The line of credit is designed to manage local currency liquidity in Venezuela and the maximum amount available to be drawn was increased to 9.0 million Bolivares Fuertes from 6.0 million Bolivares Fuertes in July of 2008. The maximum amount available to be drawn at June 30, 2008 is 6.0 million Bolivares Fuertes ($2.8 million at the exchange rate at June 30, 2008), and there was 2.3 million Bolivares Fuertes ($1.1 million at the exchange rate at June 30, 2008) outstanding at June 30, 2008.

In May 2008, in connection with the renewal of certain of our insurance policies, we entered into an agreement to finance a portion of our annual insurance premiums. Approximately $32.1 million was financed through this arrangement, and $32.1 million was outstanding at June 30, 2008. The interest rate on these notes is 4.42% and the note matures in April 2009.

Capital Expenditures

We expect to spend a total of $140 million on capital expenditures excluding asset acquisitions during the remainder of 2008. Planned capital expenditures include refurbishment and upgrade of our rigs and liftboats, including amounts allocated to Hercules 208, Hercules 261 and Hercules 262. In addition, included in our planned capital expenditures are amounts for contract preparation and planned equipment standardization for top-drives and cranes.

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

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

The timing and amounts we actually spend in connection with our plans to upgrade and refurbish other selected rigs and liftboats are subject to our discretion and will depend on our view of market conditions and our cash flows. From time to time, we may review possible acquisitions of rigs, liftboats or businesses, joint ventures, mergers or other business combinations, and we may have outstanding from time to time bids to acquire certain assets from other companies. We may not, however, be successful in our acquisition efforts. If we do complete any such acquisitions, we may make significant capital commitments for such purposes. Any such transactions could involve the payment by us of a substantial amount of cash. We would likely fund the cash portion of such transactions, if any, through cash balances on hand, the incurrence of additional debt, or sales of assets, equity interests or other securities or a combination thereof. If we acquire additional assets, we would expect that the ongoing capital expenditures for our company as a whole would increase in order to maintain our equipment in a competitive condition.

Our ability to fund capital expenditures would be adversely affected if conditions deteriorate in our business, we experience poor results in our operations or we fail to meet covenants under our term loan facility.

Contractual Obligations

Our contractual obligations and commitments principally include obligations associated with our outstanding indebtedness, surety bonds, letters of credit, future minimum operating lease obligations, purchase commitments and management compensation obligations. During the first six months of 2008, there were no material changes outside the ordinary course of business in the specified contractual obligations, other than in connection with the acquisition of rigs from Transocean and the issuance of the $250.0 million of 3.375% Convertible Senior Notes.

For additional information about our contractual obligations as of December 31, 2007, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources— Contractual Obligations” in Item 7 of our annual report on Form 10-K for the year ended December 31, 2007.

Off-Balance Sheet Arrangements

Guarantees

Our obligations under the credit facility are secured by liens on several of our vessels and substantially all of our other personal property. Substantially all of our domestic subsidiaries guarantee the obligations under the credit agreement and have granted similar liens on several of their vessels and substantially all of their other personal property.

Letters of Credit and Surety Bonds

We execute letters of credit and surety bonds in the normal course of business. While these obligations are not normally called, these obligations could be called by the beneficiaries at any time before the expiration date should we breach certain contractual or payment obligations. As of June 30, 2008, we had $86.7 million of letters of credit and surety bonds outstanding, consisting of $0.1 million in unsecured outstanding letters of credit, $28.5 million letters of credit outstanding under our revolver and $58.1 million outstanding in surety bonds that guarantee our performance as it relates to our drilling contracts, insurance, tax and other obligations in various jurisdictions. If the beneficiaries called these letters of credit and surety bonds, the called amount would become an on-balance sheet liability, and our available liquidity would be reduced by the amount called.

Accounting Pronouncements

See Note 12 to our condensed consolidated financial statements included elsewhere in this report.

FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical fact, included in this quarterly report that address outlook, activities, events or developments that we expect, project, believe or anticipate will or may occur in the future are forward-looking statements. These include such matters as:

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

	•		the correlation between demand for our rigs and our liftboats and our earnings and customers’ expectations of energy prices;

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

	•		expected completion times for our refurbishment and upgrade projects;

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

	•		our plans regarding increased international operations;

	•		expected useful lives of our rigs and liftboats;

	•		liabilities under laws and regulations protecting the environment;

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

	•		expectations regarding improvements in offshore drilling activity and dayrates, continuation of current market conditions, demand for our rigs and liftboats, operating revenues, operating and maintenance expense, insurance expense and deductibles, interest expense, debt levels and other matters with regard to outlook.

We have based these statements on our assumptions and analyses in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. Forward-looking statements by their nature involve substantial risks and uncertainties that could significantly affect expected results, and actual future results could differ materially from those described in such statements. Although it is not possible to identify all factors, we continue to face many risks and uncertainties. Among the factors that could cause actual future results to differ materially are the risks and uncertainties described under “Risk Factors” in Item 1A of our annual report on Form 10-K for the year ended December 31, 2007 and the following:

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

	•		demand for offshore jackup rigs and liftboats;

	•		our ability to enter into and the terms of future contracts;

	•		the worldwide military and political environment, uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or other crises in the Middle East and other oil and natural gas producing regions, or further acts of terrorism in the United States, or elsewhere;

	•		the impact of governmental laws and regulations;

	•		the adequacy of sources of liquidity;

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

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

	•		the availability of skilled personnel;

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

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

	•		the effect of litigation and contingencies; and

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

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Interest Rate Exposure

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

As of June 30, 2008, the long-term borrowings that were outstanding subject to fixed interest rate risk consisted of the 7.375% Senior Notes due April 2018 and the 3.375% Convertible Senior Notes due June 2038. Both the carrying amount and fair value of the 7.375% Senior Notes was $3.5 million. The carrying amount and fair value of the 3.375% Convertible Senior Notes was $250.0 million and $261.0 million, respectively.

As of June 30, 2008, the interest rate for the $893.3 million outstanding under the term loan was 4.45%. If the interest rate averaged 1% more for 2008 than the rates as of June 30, 2008, annual interest expense would increase by approximately $8.9 million. This sensitivity analysis assumes there are no changes in our financial structure.

We believe our other debt instruments, which are short-term in nature, totaling $11.4 million as of June 30, 2008, approximate fair value.

Interest Rate Swaps and Derivatives

We manage our debt portfolio to achieve an overall desired position of fixed and floating rates and may employ hedge transactions such as interest rate swaps and zero cost LIBOR collars as tools to achieve that goal. The major risks from interest rate derivatives include changes in the interest rates affecting the fair value of such instruments, potential increases in interest expense due to market decreases in floating interest rates and the creditworthiness of the counterparties in such transactions. The counterparties to our interest rate swaps and zero cost LIBOR collar are creditworthy multinational commercial banks. We believe that the risk of counterparty nonperformance is not currently material. Our interest expense was increased by $3.7 million and $4.3 million for the three and six months ended June 30, 2008, as a result of our interest rate derivative transactions. (See the information set forth under the caption “Debt” in Part 1, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations- Liquidity and Capital Resources.)

In connection with the credit facility, in July 2007, we entered into hedge transactions with the purpose of fixing the interest rate on decreasing notional amounts beginning with $400.0 million with a settlement date of December 31, 2007 and ending with $50.0 million with a settlement date of April 1, 2009. We also entered into a zero cost LIBOR collar on $300.0 million of term loan principal over three years, with a ceiling of 5.75% and a floor of 4.99%. The table below provides the scheduled reduction in notional amounts related to the interest rate swap (in thousands):


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

In addition, as it relates to our credit facility, in May 2008 we entered into a floating to fixed interest rate swap with the purpose of fixing the interest rate on varying notional amounts beginning with $100.0 million with a settlement date of October 1, 2008 and ending with $75.0 million with a settlement date of December 31, 2009. The table below provides the schedule of notional amounts related to the interest rate swap (in thousands):


July 1, 2008-September 30, 2008	$	100,000
October 1, 2008-December 30, 2008		325,000
December 31, 2008-March 31, 2009		325,000
April 1, 2009-June 30, 2009		250,000
July 1, 2009-September 30, 2009		175,000
October 1, 2009-December 30, 2009		75,000

ITEM 4. CONTROLS AND PROCEDURES

We carried out an evaluation, under the supervision and with the participation of our management, including John T. Rynd, our President and Chief Executive Officer, and Lisa W. Rodriguez, our Senior Vice President and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 as of the end of the period covered by this quarterly report. Based upon that evaluation, Mr. Rynd and Ms. Rodriguez, acting in their capacities as our principal executive officer and our principal financial officer, concluded that, as of June 30, 2008, our disclosure controls and procedures were effective, in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the SEC’s rules and forms, of information required to be disclosed by us in the reports that we file or submit under the Exchange Act.

During the six months ended June 30, 2008, we converted our domestic and one international location’s operational and financial functions to the Oracle enterprise resource planning (“ERP”) software system. The new ERP system affects every aspect of our operations, including procurement, finance and accounting, engineering, human resources and benefits and asset maintenance. We will continue the upgrade of our legacy financial systems to the Oracle ERP system internationally, and expect the upgrade to be completed in the third quarter of 2008. We expect this upgrade will have a positive impact on our overall control environment.

Other than as discussed above, there were no changes in our internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The information set forth under the caption “Legal Proceedings” in Note 11 of the Notes to Unaudited Consolidated Financial Statements in Item 1 of Part 1 of this report is incorporated by reference in response to this item.

ITEM 1A. RISK FACTORS

Except for the additional and updated disclosures set forth below, for additional information about our risk factors, see Item 1A of our annual report on Form 10-K for the year ended December 31, 2007.

The offshore service industry is highly cyclical, and certain of our contracts, primarily in the U.S. Gulf of Mexico, are short-term contracts. The volatility of the industry, coupled with our short-term contracts, could result in sharp declines in our profitability.

Historically, the offshore service industry has been highly cyclical, with periods of high demand and high dayrates often followed by periods of low demand and low dayrates. Periods of low demand intensify the competition in the industry and often result in rigs or liftboats being idle for long periods of time. We may be required to idle rigs or liftboats or enter into lower dayrate contracts in response to market conditions in the future. In the U.S. Gulf of Mexico, contracts are generally short term, and oil and natural gas companies tend to respond quickly to upward or downward changes in prices. Due to the short-term nature of most of our contracts, including for our rigs and liftboats in the U.S. Gulf of Mexico and for some of our international liftboats, changes in market conditions can quickly affect our business. In addition, customers generally have the right to terminate our contracts with little or no notice, and without penalty. As a result of the cyclicality of our industry, we expect our results of operations to be volatile.

A significant portion of our business is conducted in the shallow-water U.S. Gulf of Mexico. The mature nature of this region could result in less drilling activity in the area, thereby reducing demand for our services.

The U.S. Gulf of Mexico, and in particular the shallow-water region of the U.S. Gulf of Mexico, is a mature oil and natural gas production region that has experienced substantial seismic survey and exploration activity for many years. Because a large number of oil and natural gas prospects in this region have already been drilled, additional prospects of sufficient size and quality could be more difficult to identify. According to the U.S. Energy Information Administration, the average size of the U.S. Gulf of Mexico discoveries has declined significantly since the early 1990s. In addition, the amount of natural gas production in the shallow-water U.S. Gulf of Mexico has declined over the last decade. Moreover, oil and natural gas companies may be unable to obtain financing necessary to drill prospects in this region. The decrease in the size of oil and natural gas prospects, the decrease in production or the failure to obtain such financing may result in reduced drilling activity in the U.S. Gulf of Mexico and reduced demand for our services. Our industry is highly competitive, with intense price competition. Our inability to compete successfully may reduce our profitability.

Acquisitions are an important component of our business strategy. Our acquisition strategy may be unsuccessful if we are unable to identify and complete future acquisitions, fail to successfully integrate acquired assets or businesses we acquire, are unable to obtain financing for acquisitions on acceptable terms or incorrectly predict operating results.

The acquisition of assets or businesses that are complementary to our drilling and liftboat operations is an important component of our business strategy. We believe that acquisition opportunities may arise from time to time, and any such acquisition could be significant. At any given time, discussions with one or more potential sellers may be at different stages. However, any such discussions may or may not result in the consummation of an acquisition transaction, and we may not be able to identify or complete any acquisitions. Any such transactions could involve the payment by us of a substantial amount of cash, the incurrence of a substantial amount of debt or the issuance of a substantial amount of equity. We cannot predict the effect, if any, that any announcement or consummation of an acquisition would have on the trading price of our common stock.

Any future acquisitions could present a number of risks, including:

	•		the risk of incorrect assumptions regarding the future results of acquired operations or assets or expected cost reductions or other synergies expected to be realized as a result of acquiring operations or assets;

	•		the risk of failing to integrate the operations or management of any acquired operations or assets successfully and timely; and

	•		the risk of diversion of management’s attention from existing operations or other priorities.

In addition, we may not be able to obtain, on terms we find acceptable, sufficient financing that may be required for any such acquisition or investment.

If we are unsuccessful in completing acquisitions of other operations or assets, our financial condition could be adversely affected and we may be unable to implement an important component of our business strategy successfully. In addition, if we are unsuccessful in integrating our acquisitions in a timely and cost-effective manner, our financial condition and results of operations could be adversely affected.

Our international operations are subject to additional political, economic, and other uncertainties not generally associated with domestic operations.

An element of our business strategy is to continue to expand into international oil and natural gas producing areas such as West Africa, the Middle East and the Asia-Pacific region. We operate liftboats in West Africa, including Nigeria. In addition, we have one liftboat undergoing regulatory and other modifications and repairs in the Middle East and one liftboat in transit to the Middle East where upon arrival, it will undergo regulatory and modification work. We also operate drilling rigs in India, Angola, Qatar, Mexico and Cameroon. We have one jackup rig undergoing reactivation in Southeast Asia, one jackup rig undergoing contract preparation work in the Middle East and one jackup rig in transit to the Middle East where upon arrival, it will undergo contract preparation work. Our international operations are subject to a number of risks inherent in any business operating in foreign countries, including:

	•		political, social and economic instability, war and acts of terrorism;

	•		potential seizure, expropriation or nationalization of assets;

	•		damage to our equipment or violence directed at our employees, including kidnappings;

	•		piracy;

	•		increased operating costs;

	•		complications associated with repairing and replacing equipment in remote locations;

	•		repudiation, modification or renegotiation of contracts;

	•		limitations on insurance coverage, such as war risk coverage in certain areas;

	•		import-export quotas;

	•		confiscatory taxation;

	•		work stoppages or strikes, particularly in the Nigerian and Mexican labor environment;

	•		unexpected changes in regulatory requirements;

	•		wage and price controls;

	•		imposition of trade barriers;

	•		imposition or changes in enforcement of local content laws;

	•		restrictions on currency or capital repatriations;

	•		currency fluctuations and devaluations; and

	•		other forms of government regulation and economic conditions that are beyond our control.

As a result of our international expansion, including our acquisition of jack-ups and a platform rig in the acquisition of TODCO, the exposure to these risks will increase. Our financial condition and results of operations could be susceptible to adverse events beyond our control that may occur in the particular country or region in which we are active.

Many governments favor or effectively require that liftboat or drilling contracts be awarded to local contractors or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These practices may result in inefficiencies or put us at a disadvantage when bidding for contracts against local competitors.

Our non-U.S. contract drilling and liftboat operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to the equipment and operation of drilling rigs and liftboats, currency conversions and repatriation, oil and natural gas exploration and development, taxation of offshore earnings and earnings of expatriate personnel, the use of local employees and suppliers by foreign contractors and duties on the importation and exportation of units and other equipment. Governments in some foreign countries have become increasingly active in regulating and controlling the ownership of concessions and companies holding concessions, the exploration for oil and natural gas and other aspects of the oil and natural gas industries in their countries. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by major oil and natural gas companies and may continue to do so. Operations in less developed countries can be subject to legal systems which are not as mature or predictable as those in more developed countries, which can lead to greater uncertainty in legal matters and proceedings.

Due to our international operations, we may experience currency exchange losses where revenues are received and expenses are paid in nonconvertible currencies or where we do not hedge an exposure to a foreign currency. We may also incur losses as a result of an inability to collect revenues because of a shortage of convertible currency available to the country of operation, controls over currency exchange or controls over the repatriation of income or capital.

Upgrade, refurbishment and repair projects are subject to risks, including delays and cost overruns, which could have an adverse impact on our available cash resources and results of operations.

We make upgrade, refurbishment and repair expenditures for our fleet from time to time, including when we acquire units or when repairs or upgrades are required by law, in response to an inspection by a governmental authority or when a unit is damaged. We

also regularly make certain upgrades or modifications to our drilling rigs to meet customer or contract specific requirements. We are currently upgrading and refurbishing Hercules 208 and Hercules 261 and will shortly commence upgrading Hercules 262 upon the completion of its mobilization to a shipyard in Saudi Arabia.

Upgrade, refurbishment and repair projects are subject to the risks of delay or cost overruns inherent in any large construction project, including costs or delays resulting from the following:

	•		unexpectedly long delivery times for, or shortages of, key equipment, parts and materials;

	•		shortages of skilled labor and other shipyard personnel necessary to perform the work;

	•		unforeseen increases in the cost of equipment, labor and raw materials, particularly steel;

	•		unforeseen design and engineering problems;

	•		unanticipated actual or purported change orders;

	•		work stoppages;

	•		latent damages or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions;

	•		failure or delay of third-party service providers and labor disputes;

	•		disputes with shipyards and suppliers;

	•		delays and unexpected costs of incorporating parts and materials needed for the completion of projects;

	•		failure or delay in obtaining acceptance of the rig from our customer;

	•		financial or other difficulties at shipyards;

	•		adverse weather conditions; and

	•		inability to obtain required permits or approvals.

Significant cost overruns or delays would adversely affect our financial condition and results of operations. Additionally, capital expenditures for rig upgrade and refurbishment projects could exceed our planned capital expenditures. Failure to complete an upgrade, refurbishment or repair project on time may, in some circumstances, result in the delay, renegotiation or cancellation of a drilling or liftboat contract and could put at risk our planned arrangements to commence operations on schedule. We also could be exposed to penalties for failure to complete an upgrade, refurbishment or repair project and commence operations in a timely manner. Our rigs and liftboats undergoing upgrade, refurbishment or repair may not earn a dayrate during the period they are out of service.

TODCO’s tax sharing agreement with Transocean may require continuing substantial payments.

We, as successor to TODCO, and TODCO’s former parent Transocean Holdings Inc. are parties to a tax sharing agreement that was originally entered into in connection with TODCO’s initial public offering in 2004. The tax sharing agreement was amended and restated in November 2006. The tax sharing agreement required us to make an acceleration payment to Transocean upon completion of the TODCO acquisition. Subsequent to the completion of the TODCO acquisition, we paid $116.0 million to Transocean in the second half of 2007 in satisfaction of the obligation to pay the acceleration payment, however the basis of determination for the payment has been disputed by Transocean, and Transocean has publicly disclosed that it believes we owe an additional $11 million as a result of the acquisition of TODCO. In May of 2008, Transocean initiated the dispute resolution procedure set forth in the tax sharing agreement, and in June of 2008, Transocean delivered a demand for arbitration to the Company.

Additionally, 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, 2008, assuming a Transocean stock price of $152.39 per share at the time of exercise of the compensatory options (the actual price of Transocean’s common stock at June 30, 2008), is approximately $25.1 million. There is no certainty that we will realize future economic benefits from TODCO’s tax benefits equal to the amount of the payments required under the tax sharing agreement.

Our debt could adversely affect our ability to operate our business and make it difficult to meet our debt service obligations.

As of June 30, 2008, we had total outstanding debt of approximately $1.2 billion. This debt represented approximately 37% of our total capitalization. After giving effect to the April 2008 increase of $100 million of available capacity under our revolving credit facility, as of June 30, 2008, we had up to $250 million of available capacity under that facility, of which $28.5 million was committed related to issued standby letters of credit. We may continue to borrow to fund working capital or other needs in the near term up to the remaining availability. Our debt and the limitations imposed on us by our existing or future debt agreements could have significant consequences on our business and future prospects, including the following:

•

we may not be able to obtain necessary financing in the future for working capital, capital expenditures, acquisitions, debt service requirements or other purposes;

	•		we may be exposed to risks inherent in interest rate fluctuations because our borrowings generally are at variable rates of interest, which would result in higher interest expense to the extent we have not hedged such risk in the event of increases in interest rates; and

	•		we could be more vulnerable in the event of a downturn in our business that would leave us less able to take advantage of significant business opportunities and to react to changes in our business and in market or industry conditions.

Our ability to make payments on and to refinance our indebtedness, including the convertible notes issued by us on June 3, 2008, and to fund planned capital expenditures will depend on our ability to generate cash in the future, which is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. Our future cash flows may be insufficient to meet all of our debt obligations and commitments, and any insufficiency could negatively impact our business. To the extent we are unable to repay our indebtedness as it becomes due or at maturity with cash on hand or from other sources, we will need to refinance our debt, sell assets or repay the debt with the proceeds from equity offerings. Additional indebtedness or equity financing may not be available to us in the future for the refinancing or repayment of existing indebtedness, and we may not be able to complete asset sales in a timely manner sufficient to make such repayments.

We are a holding company, and we are dependent upon cash flow from subsidiaries to meet our obligations.

We currently conduct our operations through, and most of our assets are owned by, both U.S. and foreign subsidiaries, and our operating income and cash flow are generated by our subsidiaries. As a result, cash we obtain from our subsidiaries is the principal source of funds necessary to meet our debt service obligations. Contractual provisions or laws, as well as our subsidiaries’ financial condition and operating requirements, may limit our ability to obtain cash from our subsidiaries that we require to pay our debt service obligations, including payments on the convertible notes. Applicable tax laws may also subject such payments to us by our subsidiaries to further taxation.

The inability to transfer cash from our subsidiaries to us may mean that, even though we may have sufficient resources on a consolidated basis to meet our obligations, we may not be permitted to make the necessary transfers from subsidiaries to the parent company in order to provide funds for the payment of the parent company’s obligations.

We limit foreign ownership of our company, which may restrict investment in our common stock and could reduce the price of our common stock.

Our certificate of incorporation limits the percentage of outstanding common stock and other classes of capital stock that can be owned by non-United States citizens within the meaning of statutes relating to the ownership of U.S.-flagged vessels. Applying the statutory requirements applicable today, our certificate of incorporation provides that no more than 20% of our outstanding common stock may be owned by non-United States citizens and establishes mechanisms to maintain compliance with these requirements. These restrictions may have an adverse impact on the liquidity or market value of our common stock because holders may be unable to transfer our common stock to non-United States citizens. Any attempted or purported transfer of our common stock in violation of these restrictions will be ineffective to transfer such common stock or any voting, dividend or other rights in respect of such common stock.

Our certificate of incorporation also provides that any transfer, or attempted or purported transfer, of any shares of our capital stock that would result in the ownership or control of in excess of 20% of our outstanding capital stock by one or more persons who are not United States citizens for purposes of U.S. coastwise shipping will be void and ineffective as against us. In addition, if at any time persons other than United States citizens own shares of our capital stock or possess voting power over any shares of our capital stock in excess of 20%, we may withhold payment of dividends, suspend the voting rights attributable to such shares and redeem such shares.

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

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


	Total Number
	of Shares		Average Price
Period	Purchased (1)		Share Paid per
April 1 – 30, 2008		662	$	27.57
May 1 – 31, 2008		265		35.75
June 1 – 30, 2008		—		—

Total		927		29.91


(1)		Represents the surrender of shares of common stock to satisfy tax withholding obligations in connection with the vesting of restricted stock issued to employees under our stockholder-approved long-term incentive plan.

On June 3, 2008, we completed an offering of $250.0 million aggregate original principal amount of our 3.375% Convertible Senior Notes due 2038. We sold the Notes to the Initial Purchasers in reliance on the exemption from registration provided by Section 4(2) of the Securities Act of 1933, and we were advised by the Initial Purchasers that the Initial Purchasers resold the Notes only to qualified institutional buyers in reliance on Rule 144A under the Securities Act. The Company used $49.2 million of the net proceeds to repurchase, concurrently with the issuance of the Notes, approximately 1,450,000 shares of Common Stock in privately negotiated transactions at a purchase price of $33.95 per share. For additional information regarding the 3.375% Convertible Senior Notes and the terms of conversion, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Debt” and the Company’s Form 8-K filed June 3, 2008.

Total Number of

Maximum Number of

Total Number

Shares Purchased as

Shares That May Yet Be

of Shares

Average Price

Part of a Publicly

Purchased Under

Period

Purchased

Paid per Share

Announced Plan (2)

Plan (2)

April 1 – 30, 2008

—

N/A

May 1 – 31, 2008

—

N/A

June 1 – 30, 2008

1,450,000

33.95

1,450,000

—

Total

1,450,000

33.95

1,450,000

—


(2)		As announced on May 28, 2008, concurrently with the offering of the 3.375% Convertible Senior Notes, we repurchased shares of our outstanding common stock in privately negotiated transactions as approved by our Board of Directors who authorized the repurchase of up to $50 million of our common stock. We do not intend to make further purchases pursuant to this board authorization.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Our annual meeting of stockholders was held in Houston, Texas on April 23, 2008 for the purpose of voting on the proposals described below. Proxies for the meeting were solicited pursuant to Section 14(a) of the Securities Exchange Act of 1934 and there was no solicitation in opposition to management’s solicitation.

Stockholders elected two directors to the class of directors whose term will expire at the 2011 annual meeting of stockholders by the following votes:


Name	For		Withheld
John T. Reynolds		76,168,768		250,598
F. Gardner Parker		71,596,824		4,822,542

The terms of office of directors Thomas M. Amonett, Suzanne V. Baer, Thomas R. Bates, Jr., Thomas M Hamilton, Thomas J. Madonna, Thierry Pilenko, Randall D. Stilley, and Steven A. Webster continued beyond the meeting date.

Stockholders approved the adoption of an Employee Stock Purchase Plan by the following vote:


For			60,165,885
Against			1,042,346
Abstain			156,946
Broker Non-Vote			15,054,193

Stockholders ratified the appointment of Ernst & Young LLP as our independent registered public accounting firm for the year ending December 31, 2008 by the following vote:


For			75,728,421
Against			140,187
Abstain			550,646
Broker Non-Vote			116

Hercules solicited proxies with respect to a proposal to adjourn the annual meeting, if necessary or appropriate, in order to allow for the solicitation of additional proxies. The proposal was not voted on at the meeting, but the proxies returned indicated the following vote:


For			51,746,876
Against			24,274,674
Abstain			397,696
Broker Non-Vote			124

ITEM 6. EXHIBITS


4.1		Indenture, dates as of June 3, 2008, by and between the Company and the Trustee (incorporated by reference to Exhibit 4.1 to Hercules’ Current Report on Form 8-K dated June 3, 2008 (File No.-0-51582)).

4.2		Form of Note (included in Exhibit 4.1).

10.1		Purchase Agreement, dated May 28, 2008, by and between the Company and Goldman, Sachs & Co., Banc of America Securities LLC and UBS Securities LLC, as representatives of the Initial Purchasers (incorporated by reference to Exhibit 10.1 to Hercules’ Current Report on Form 8-K dated June 3, 2008 (File No.-0-51582)).

10.2		Separation Agreement dated as of June 20, 2008, between Hercules Offshore, Inc. and Randall D. Stilley (incorporated by reference to Exhibit 10.1 to Hercules’ Current Report on Form 8-K dated June 23, 2008 (File No.-0-51582)).

10.3		Executive Employment Agreement dated as of June 20, 2008, between Hercules Offshore, Inc. and John T. Rynd (incorporated by reference to Exhibit 10.2 to Hercules’ Current Report on Form 8-K dated June 23, 2008 (File No.-0-51582)).

10.4*		First Amendment to Hercules Offshore Inc. Amended and Restated 2004 Long-Term Incentive Plan.

31.1*		Certification of Chief Executive Officer of Hercules pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Chief Financial Officer of Hercules pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*		Certification of the Chief Executive Officer and the Chief Financial Officer of Hercules pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*		Filed herewith

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


		HERCULES OFFSHORE, INC.

		By:		/s/ John T. Rynd

				John T. Rynd
				President and Chief Executive Officer
				(Principal Executive Officer)

		By:		/s/ Lisa W. Rodriguez

				Lisa W. Rodriguez
				Senior Vice President and Chief Financial Officer
				(Principal Financial Officer)

		By:		/s/ Troy L. Carson

				Troy L. Carson
				Vice President and Corporate Controller
				(Principal Accounting Officer)

Date: July 30, 2008

Exhibit Index


4.1		Indenture, dates as of June 3, 2008, by and between the Company and the Trustee (incorporated by reference to Exhibit 4.1 to Hercules’ Current Report on Form 8-K dated June 3, 2008 (File No.-0-51582)).

4.2		Form of Note (included in Exhibit 4.1).

10.1		Purchase Agreement, dated May 28, 2008, by and between the Company and Goldman, Sachs & Co., Banc of America Securities LLC and UBS Securities LLC, as representatives of the Initial Purchasers (incorporated by reference to Exhibit 10.1 to Hercules’ Current Report on Form 8-K dated June 3, 2008 (File No.-0-51582)).

10.2		Separation Agreement dated as of June 20, 2008, between Hercules Offshore, Inc. and Randall D. Stilley (incorporated by reference to Exhibit 10.1 to Hercules’ Current Report on Form 8-K dated June 23, 2008 (File No.-0-51582)).

10.3		Executive Employment Agreement dated as of June 20, 2008, between Hercules Offshore, Inc. and John T. Rynd (incorporated by reference to Exhibit 10.2 to Hercules’ Current Report on Form 8-K dated June 23, 2008 (File No.-0-51582)).

10.4*		First Amendment to Hercules Offshore Inc. Amended and Restated 2004 Long-Term Incentive Plan.

31.1*		Certification of Chief Executive Officer of Hercules pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Chief Financial Officer of Hercules pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*		Certification of the Chief Executive Officer and the Chief Financial Officer of Hercules pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*		Filed herewith