Edgar Filing: HERCULES OFFSHORE, INC.

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2007

¨ 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 incorporation or organization)		(I.R.S. Employer Identification No.)

11 Greenway Plaza, Suite 2950 Houston, Texas		77046
(Address of principal executive offices)		(Zip Code)

(713) 979-9300

(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 x NO ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES ¨ NO x

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 August 2, 2007
		89,055,551

HERCULES OFFSHORE, INC.

INDEX


		Page No.
PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements

Consolidated Balance Sheets as of June 30, 2007 and December 31, 2006		2
Consolidated Statements of Operations for the three months and six months ended June 30, 2007 and June 30, 2006		3
Consolidated Statements of Cash Flows for the six months ended June 30, 2007 and June 30, 2006		4
Consolidated Statements of Comprehensive Income for the three months and six months ended June 30, 2007 and June 30, 2006		5
Notes to Unaudited Consolidated Financial Statements		6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	34
Item 4.	Controls and Procedures	34

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	34
Item 1A.	Risk Factors	36
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39
Item 5.	Other Information	39
Item 6.	Exhibits	40
Signatures		41

PART I. FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except par value)


	June 30, 2007			December 31, 2006
	(Unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	52,621		$	72,772
Restricted cash		250			250
Marketable securities		23,900			—
Accounts receivable		74,976			89,136
Insurance claims receivable		5,853			—
Prepaid expenses and other		11,626			18,065

Total current assets		169,226			180,223
PROPERTY AND EQUIPMENT, net		438,270			415,864
OTHER ASSETS, net		13,424			9,494

Total assets	$	620,920		$	605,581

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Current portion of long-term debt	$	55,550		$	1,400
Insurance note payable		—			6,058
Accounts payable		30,826			29,123
Accrued liabilities		14,574			16,262
Taxes payable		3,080			8,745
Interest payable		1,305			2,105
Other current liabilities		4,218			5,633

Total current liabilities		109,553			69,326
LONG-TERM DEBT, net of current portion		—			91,850
OTHER LIABILITIES		6,416			6,700
DEFERRED INCOME TAXES		47,656			42,854
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS’ EQUITY
Common stock, par value $0.01 per share; 200,000 shares authorized; 32,237 and 32,008 shares issued; 32,229 and 32,002 shares outstanding		322			320
Additional paid-in capital		249,231			243,157
Treasury stock, at cost, 8 shares and 6 shares		(282	)		(220	)
Accumulated other comprehensive income		328			755
Retained earnings		207,696			150,839

Total stockholders’ equity		457,295			394,851

Total liabilities and stockholders’ equity	$	620,920		$	605,581

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,
	2007			2006			2007			2006
REVENUES
Contract drilling services	$	47,965		$	42,567		$	111,672		$	69,564
Marine services		51,079			33,730			97,836			62,866

		99,044			76,297			209,508			132,430
COSTS AND EXPENSES
Operating expenses for contract drilling services, excluding depreciation and amortization		21,234			13,822			42,180			24,929
Operating expenses for marine services, excluding depreciation and amortization		23,162			12,438			43,743			23,267
Depreciation and amortization		12,209			7,551			23,939			13,485
General and administrative, excluding depreciation and amortization		9,335			6,601			18,498			13,187

		65,940			40,412			128,360			74,868

OPERATING INCOME		33,104			35,885			81,148			57,562
OTHER INCOME (EXPENSE)
Interest expense		(1,379	)		(2,163	)		(3,469	)		(4,249	)
Gain on disposal of assets		—			—			—			29,580
Loss on early retirement of debt		(870	)		—			(870	)		—
Other, net		1,246			1,520			2,521			1,823

INCOME BEFORE INCOME TAXES		32,101			35,242			79,330			84,716
INCOME TAX PROVISION		(8,635	)		(12,309	)		(22,473	)		(30,871	)

NET INCOME	$	23,466		$	22,933		$	56,857		$	53,845

EARNINGS PER SHARE:
Basic	$	0.73		$	0.73		$	1.77		$	1.75
Diluted	$	0.72		$	0.71		$	1.74		$	1.70
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic		32,099			31,480			32,037			30,826
Diluted		32,813			32,367			32,642			31,666

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,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	56,857		$	53,845
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		23,939			13,485
Stock-based compensation expense		2,881			1,461
Deferred income taxes		5,031			17,379
Amortization of deferred financing fees		293			327
Excess tax benefit from stock-based arrangements		(1,731	)		—
Loss on early retirement of debt		870			—
Gain on disposal of assets		(296	)		(29,580	)
(Increase) decrease in operating assets—
Accounts receivable		14,146			(20,773	)
Insurance claims receivable		(5,853	)		(8,892	)
Prepaid expenses and other		2,482			1,437
Increase (decrease) in operating liabilities—
Accounts payable		1,703			7,876
Insurance note payable		(6,058	)		(2,401	)
Other current liabilities		(7,898	)		8,230
Other liabilities		(284	)		625

Net cash provided by operating activities		86,082			43,019

CASH FLOWS FROM INVESTING ACTIVITIES
Investment in marketable securities		(61,500	)		—
Proceeds from sale of marketable securities		37,600			—
Purchase of property and equipment		(38,133	)		(118,936	)
Deferred drydocking expenditures		(9,864	)		(6,534	)
Insurance proceeds received		—			50,090
Proceeds from sale of assets, net of commissions		610			—

Net cash used in investing activities		(71,287	)		(75,380	)

CASH FLOWS FROM FINANCING ACTIVITIES
Payment of debt		(37,700	)		(700	)
Proceeds from issuance of common stock		—			54,199
Proceeds from exercise of stock options		1,510			221
Excess tax benefit from stock-based arrangements		1,731			—
Payment of debt issuance costs		(441	)		(632	)
Distributions to members		—			(3,732	)
Other		(46	)		—

Net cash provided by (used in) financing activities		(34,946	)		49,356


NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(20,151	)		16,995

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		72,772			47,575

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	52,621		$	64,570

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,
	2007			2006		2007			2006
NET INCOME	$	23,466		$	22,933	$	56,857		$	53,845
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Unrealized gains (losses) on hedge transactions		(267	)		386		(427	)		798

COMPREHENSIVE INCOME	$	23,199		$	23,319	$	56,430		$	54,643

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

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – NATURE OF BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES

Organization

Hercules Offshore, LLC was formed in July 2004 as a Delaware limited liability company. On November 1, 2005 in connection with its initial public offering, Hercules Offshore, LLC was converted to a Delaware corporation named Hercules Offshore, Inc. (the “Conversion”). Unless the context indicates otherwise, references to the “Company” are to Hercules Offshore, LLC for periods prior to the Conversion and to Hercules Offshore, Inc. for periods after the Conversion.

The Company provides shallow-water drilling and liftboat services to the oil and gas exploration and production industry in the U.S. Gulf of Mexico and international locations through its Domestic Contract Drilling Services, International Contract Drilling Services, Domestic Marine Services and International Marine Services segments. At June 30, 2007, the Company owned nine jackup drilling rigs and 60 liftboat vessels and operated an additional five liftboat vessels owned by third parties.

In July 2007, the Company completed the previously announced acquisition of TODCO (see NOTE 3). Including the assets acquired in the TODCO transaction, the Company will operate a fleet of 33 jackup rigs, 27 barge rigs, 65 liftboats, three submersible rigs, nine land rigs, one platform rig and a fleet of marine support vessels, operated through Delta Towing, a wholly owned subsidiary, and will have operations in ten different countries on five continents.

Basis of Presentation

The accompanying consolidated financial statements have been prepared in accordance with the rules of the Securities and Exchange Commission for interim financial statements and do not include all annual disclosures required by accounting principles generally accepted in the United States. The consolidated interim financial statements have not been audited. However, in the opinion of management, all adjustments necessary for a fair presentation of the consolidated financial position of the Company as of June 30, 2007, the results of its operations and comprehensive income for the three and six months ended June 30, 2007 and June 30, 2006 and its cash flows for the six months ended June 30, 2007 and June 30, 2006 have been reflected. The consolidated results of operations for the three months and six months ended June 30, 2007 are not necessarily indicative of the results that may be expected for the full year. The accompanying consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto contained in the Company’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2006.

Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All intercompany account balances and transactions have been eliminated.

Use of Estimates

In preparing financial statements in conformity with accounting principles generally accepted in the United States, management makes 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. Actual results could differ from those estimates.

Cash and Cash Equivalents and Marketable Securities

Cash and cash equivalents include cash on hand, demand deposits with banks and all highly liquid investments with original maturities of three months or less. Marketable securities are classified as available for sale and are stated

at fair value on the Consolidated Balance Sheets. Realized and unrealized gains and losses related to these marketable securities are calculated using the specific identification method. Unrealized gains or losses, net of taxes, are included in Accumulated Other Comprehensive Income on the Consolidated Balance Sheets until realized. Realized gains or losses are included in Other, Net in the Consolidated Statements of Operations.

Revenue Recognition

Revenues generated from our Contract Drilling Services and Marine Services contracts are recognized as services are performed. For certain Contract Drilling Services 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. The Company recognized $0.7 million and $0.4 million of revenue and expense, respectively, related to mobilization in the three months ended June 30, 2007 and $0.1 million and $19,031 of revenue and expense, respectively, in the three months ended June 30, 2006. The Company recognized $2.5 million and $1.6 million of revenue and expense, respectively, related to mobilization in the six months ended June 30, 2007 and $0.1 million and $19,031 of revenue and expense, respectively, in the six months ended June 30, 2006.

For certain Contract Drilling Services 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 drilling contract. The Company capitalizes such capital improvements and depreciates them over the useful life of the asset. The Company deferred $0.3 million related to such fees in the three and six months ended June 30, 2007. The Company recognized $0.1 million and $0.2 million of revenue related to such fees in the three and six months ended June 30, 2007, respectively. The Company had no revenue related to such fees for the three and six months ended June 30, 2006.

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 $2.3 million and $1.3 million for the three months ended June 30, 2007 and June 30, 2006, respectively. Total revenues from such reimbursements were $5.5 million and $2.5 million for the six months ended June 30, 2007 and June 30, 2006, respectively.

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. On July 11, 2007, the Company’s stockholders approved an increase in the shares available for grant or award under the 2004 Plan by an additional 6,800,000 shares to a total of 10,250,000, bringing the total amount available for grant as of that date to 7,716,644 shares.

During the six months ended June 30, 2007, the Company granted 444,600 stock options with a weighted average exercise price of $25.86 and 143,490 restricted stock awards with a weighted average grant-date fair value per share of $25.70.

The Company recognized $1.7 million and $2.9 million in stock-based compensation expense during the three and six months ended June 30, 2007, respectively, and $0.8 million and $1.5 million during the three and six months ended June 30, 2006, respectively. The excess income tax benefit, the tax deduction that is in excess of the tax benefit recognized in the consolidated financial statements related to stock-based compensation, recognized for the three and six months ended June 30, 2007, was $1.0 million and $1.7 million, respectively. No such tax benefit was recognized for the three and six months ended June 30, 2006.

The unrecognized compensation cost related to the Company’s unvested stock options and restricted share grants as of June 30, 2007 was $7.3 million and $4.2 million, respectively, and is expected to be recognized over a weighted-average period of 1.8 years and 2.9 years, respectively.

Cash received from stock option exercises was $1.5 million during the six months ended June 30, 2007.

Other Assets

Other assets consist of drydocking costs for liftboats, financing fees, unrealized gain on hedge transactions and other. Drydock costs are capitalized at cost and amortized on the straight-line method over a period of 12 to 24 months. Drydocking costs, net of accumulated amortization, at June 30, 2007 and June 30, 2006 were $7.1 million and $5.1 million, respectively. Amortization expense for drydocking costs was $4.4 million and $2.9 million for the three months ended June 30, 2007 and June 30, 2006, respectively, and $8.5 million and $5.3 million for the six months ended June 30, 2007 and June 30, 2006, respectively.

Fair Value of Financial Instruments

The carrying amounts of the Company’s financial instruments, which include cash and cash equivalents, marketable securities, accounts receivable, accounts payable and accrued liabilities, approximate fair value because of the short-term nature of the instruments. The carrying amount of long-term debt is equal to the fair market value because the debt bears interest at market rates.

Accounting Pronouncements

In June 2006, the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109 (“FIN 48”). The Company adopted FIN 48 and its adoption did not have a material impact on the Company’s Consolidated Balance Sheet, Statement of Operations or Statement of Cash Flow. The Company did not derecognize any tax benefits, nor recognize any interest expense or penalties on unrecognized tax benefits as of the date of adoption. The Company currently does not anticipate a significant increase in unrecognized tax benefits during the next 12 months. With respect to the acquisition of TODCO, the Company is evaluating TODCO’s tax positions in the context of its evaluation of the liabilities assumed in the acquisition and which will be accounted for under Statement of Financial Accounting Standards (“SFAS”) No. 141, Business Combinations. At this time, the Company cannot estimate the change during the next 12 months in unrecognized tax benefits related to TODCO.

The Company or one of its subsidiaries files income tax returns in the United States, and various state and foreign jurisdictions. The Company’s tax returns for 2004 through 2006 remain open for examination by the taxing authorities in the respective jurisdictions where those returns were filed.

FIN 48 requires that interest expense and penalties related to unrecognized tax benefits be recognized in the Company’s Consolidated Statement of Operations. FIN 48 allows recognized interest and penalties to be classified as either income tax expense or another appropriate expense classification. If the Company recognizes interest expense or penalties on future unrecognized tax benefits, it will classify such interest and penalties as income tax expense.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS No. 157”). 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 will be made pursuant to other accounting pronouncements that require or permit fair value measurements. SFAS No.157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. The provisions of SFAS No. 157 are to be applied prospectively upon adoption, except for limited specified exceptions. The Company is evaluating the requirements of SFAS No. 157 and does not expect the adoption to have a material impact on its financial position, results of operations and cash flows.

In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS No. 159”). SFAS No. 159 permits companies to choose to measure certain financial instruments and certain other items at fair value. The standard requires that unrealized gains and losses on items for which the fair value option has been elected be reported in earnings. SFAS No. 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company is evaluating the impact, if any, that SFAS No. 159 will have on its financial position, results of operations and cash flows.

NOTE 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,
	2007		2006		2007		2006
Numerator:
Net income	$	23,466	$	22,933	$	56,857	$	53,845

Denominator:
Weighted average basic shares		32,099		31,480		32,037		30,826
Add effect of stock equivalents		714		887		605		840

Weighted average diluted shares		32,813		32,367		32,642		31,666

Basic earnings per share	$	0.73	$	0.73	$	1.77	$	1.75
Diluted earnings per share	$	0.72	$	0.71	$	1.74	$	1.70

The Company calculates 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 plans. Options to purchase 21,500 shares with an exercise price in excess of the average market price of the Company’s shares are excluded from the calculation of the dilutive effect of stock options for the diluted earnings per share calculation for the three months and six months ended June 30, 2007. No options were excluded from the calculation of the dilutive effect of stock options for the diluted earnings per share calculation for the three and six months ended June 30, 2006.

NOTE 3 – ACQUISITIONS

In June 2007, the Company purchased a liftboat vessel for $7.4 million. The vessel is expected to undergo refurbishment and upgrades and be marketed in West Africa.

On July 11, 2007, the Company completed its acquisition of TODCO, for total consideration of approximately $2,398.0 million consisting of $925.8 million in cash and 56.6 million Hercules common shares. 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. TODCO, a provider of contract oil and gas drilling 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.

NOTE 4 – MARKETABLE SECURITIES

Beginning in March 2007, the Company began investing 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, 2007, the Company had marketable securities with a fair value and cost basis of $23.9 million. Proceeds of $37.6 million were received from sales and maturities of marketable securities for the three and six months ended June 30, 2007. There were no realized or unrealized gains or losses related to these securities.

NOTE 5 – LONG-TERM DEBT, NET OF CURRENT PORTION

Long-term debt is comprised of the following (in thousands):


	June 30, 2007		December 31, 2006
Senior secured term loan due June 2010	$	55,550	$	93,250

Total debt		55,550		93,250
Less debt due within one year		55,550		1,400

Total long-term debt	$	—	$	91,850

Senior secured credit agreement

The Company had a senior secured credit agreement with a syndicate of financial institutions that, as amended, provided for a $140.0 million term loan and a $75.0 million revolving credit facility. As of June 30, 2007, $55.6 million of the principal amount of the term loan was outstanding, and the interest rate was 8.60%. No amounts were outstanding and no letters of credit had been issued under the revolving credit facility. In addition to the repayments discussed below, during 2007 the Company made $0.7 million of scheduled principal payments.

In April 2007, the Company repaid $37.0 million of the outstanding amount under the term loan. Additionally, the Company cancelled an interest rate swap on $35.0 million of the term loan principal. The Company recognized a pretax charge of $0.9 million related to the write off of deferred financing fees in connection with this debt repayment.

In July 2007, the Company repaid the remaining $55.6 million outstanding under the term loan together with accrued interest of $1.2 million. Additionally the Company cancelled all derivative instruments related to the term loan, which included an interest rate swap on $35.0 million of the term loan principal and two interest rate caps on a total of $20.0 million of the term loan principal. The entire debt balance has been classified in Current Portion of Long Term Debt in the accompanying Consolidated Balance Sheets.

On July 11, 2007, 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 of the borrowings will be used, together with cash on hand, as necessary, to finance the cash portion of the Company’s acquisition of TODCO, to repay amounts under the Company’s and TODCO’s existing senior secured credit facilities 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.

Amounts outstanding under the revolving credit facility bear interest at either the eurodollar rate or the base prime rate plus a margin that is initially 1.75% for revolving loans bearing interest at the eurodollar rate and 0.75% for revolving loans bearing interest at the base prime rate. After the Company delivers to the lenders under the credit facility its financial statements for the fiscal year ending December 31, 2007, the applicable margin under the revolving credit facility will vary depending on its leverage ratio, with the applicable margin for revolving loans bearing interest at the eurodollar rate ranging between 1.25% and 1.75% per annum and the applicable margin for revolving loans bearing interest at the base prime rate ranging between 0.25% and 0.75% per annum. The Company pays a commitment fee on the unused portion of the revolving credit facility, which ranges between 0.25% and 0.375% depending on its leverage ratio. The Company pays a letter of credit fee of between 1.25% and 1.75% per annum with respect to the undrawn amount of each letter of credit issued under the revolving credit facility.

The principal amount of the term loan under the term loan facility amortizes in equal quarterly installments of $2.25 million, with the balance due on July 11, 2013. In addition, the Company is required to prepay the term loans with:

•

the net proceeds from sales of certain assets to the extent that the Company does not reinvest the proceeds in its business within one year;

•

the net proceeds from casualties or condemnations of assets to the extent that the Company does not reinvest the proceeds in its business within one year;

•

the net proceeds of debt that the Company incurs to the extent that such debt is not permitted by the credit agreement;

•

50% of the net proceeds that the Company receives from any issuance of preferred stock; and

•

commencing with the fiscal year ending December 31, 2008, 50% of the Company’s excess cash flow until the outstanding principal balance of the term loans is less than $550.0 million.

Other than the quarterly payments referred to above and these mandatory prepayments, the term loan facility requires interest-only payments on a quarterly basis until maturity. The Company is permitted to prepay amounts outstanding under the term loan facility at any time without penalty. Amounts outstanding under the term loan facility bear interest at either the eurodollar rate or the base prime rate plus a margin that is initially 1.75% for term loans bearing interest at the eurodollar rate and 0.75% for term loans bearing interest at the base prime rate. After the Company delivers to the lenders under the credit agreement its financial statements for the fiscal year ending December 31, 2007, the applicable margin under the term loan facility will vary depending on the Company’s leverage ratio, with the applicable margin for term loans bearing interest at the eurodollar rate ranging between 1.50% and 1.75% per annum and the applicable margin for term loans bearing interest at the base prime rate ranging between 0.50% and 0.75% per annum.

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

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.

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 outstanding totaled $16.3 million net of unamortized discounts and premiums at June 30, 2007. The notes bear interest at rates ranging from 6.95% to 9.50%, with maturities between April 2008 and April 2018. The line of credit is designed to manage local currency liquidity in Venezuela. The maximum amount available to be drawn is 6.0 billion Bolivars ($2.8 million at the current exchange rate at June 30, 2007), and there was 3.0 billion Bolivars ($1.4 million at the current exchange rate at June 30, 2007) outstanding at June 30, 2007.

NOTE 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. At June 30, 2007, the Company had an interest rate swap outstanding on a total of $35.0 million of the term loan principal and two purchased interest rate caps on a total of $20.0 million of the term loan principal. The Company cancelled an interest rate swap on $35.0 million of the term loan principal in conjunction with a debt repayment in April 2007 and received proceeds and recognized a gain of $0.3 million. In July 2007, the Company cancelled the outstanding interest rate swap on $35.0 million of the term loan principal and two interest rate caps on a total of $20.0 million of the term loan principal and received proceeds of $0.4 million.

These hedge transactions are being accounted for as cash flow hedges under 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 and the cumulative unrealized gain, net of tax, is included in other accumulated comprehensive income 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 or six months ended June 30, 2007 and June 30, 2006 related to these hedging instruments.

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


	June 30, 2007		December 31, 2006
Fair value	$	506	$	1,162
Cumulative unrealized gain, net of tax	$	328	$	755


	Three Months Ended June 30,				Six Months Ended June 30,
	2007		2006		2007		2006
Realized gains	$	109	$	170	$	316	$	130

In July 2007, the Company entered into derivative instruments with the purpose of hedging future interest payments on our new term loan facility. 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 payment dates of the swap match those of the term loan. 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 payment dates of the collar match those of the term loan.

NOTE 7 – SEGMENTS

The Company’s operations are aggregated into four reportable segments: (i) Domestic Contract Drilling Services, (ii) International Contract Drilling Services, (iii) Domestic Marine Services and (iv) International Marine Services. The Contract Drilling Services segments consist of jackup rigs used in support of offshore drilling activities. The Domestic Contract Drilling Services segment consists of jackup rigs operated in the U.S. Gulf of Mexico, while the International Contract Drilling Services segment consists of jackup rigs operated outside of the U.S. Gulf of Mexico (which currently consists of one jackup rig operating offshore Qatar, one jackup rig operating offshore India and one jackup rig currently undergoing refurbishment and upgrade). The Marine Services segments consist of liftboats used in offshore support services. The Domestic Marine Services segment consists of liftboats operated in the U.S. Gulf of Mexico, while the International Marine Services Segment consists of liftboats operated outside of the U.S. Gulf of Mexico (which currently consists of the Company’s liftboats operating in West Africa). The Company eliminates intersegment revenue and expenses, if any.

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


Three Months Ended June 30, 2007

	Domestic Contract Drilling Services		International Contract Drilling Services		Domestic Marine Services		International Marine Services		Corporate and Other			Total
Revenues	$	28,325	$	19,640	$	37,195	$	13,884	$	—		$	99,044
Operating expenses, excluding depreciation and amortization		13,899		7,335		15,639		7,523		—			44,396
Depreciation and amortization		2,691		1,363		6,192		1,938		25			12,209
General and administrative, excluding depreciation and amortization		1,611		1,015		539		882		5,288			9,335

Operating income (loss)		10,124		9,927		14,825		3,541		(5,313	)		33,104
Total assets (at end of period)	$	161,769	$	107,969	$	191,142	$	107,467	$	52,573		$	620,920


Three Months Ended June 30, 2006

	Domestic Contract Drilling Services		International Contract Drilling Services		Domestic Marine Services		International Marine Services		Corporate and Other			Total
Revenues	$	38,291	$	4,276	$	30,163	$	3,567	$	—		$	76,297
Operating expenses, excluding depreciation and amortization		12,219		1,603		10,857		1,581		—			26,260
Depreciation and amortization		2,089		251		4,910		274		27			7,551
General and administrative, excluding depreciation and amortization		1,587		472		417		593		3,532			6,601

Operating income (loss)		22,396		1,950		13,979		1,119		(3,559	)		35,885
Total assets (at end of period)	$	138,512	$	83,335	$	188,497	$	21,168	$	60,792		$	492,304


Six Months Ended June 30, 2007

	Domestic Contract Drilling Services		International Contract Drilling Services		Domestic Marine Services		International Marine Services		Corporate and Other			Total
Revenues	$	71,156	$	40,516	$	69,898	$	27,938	$	—		$	209,508
Operating expenses, excluding depreciation and amortization		27,462		14,718		29,279		14,464		—			85,923
Depreciation and amortization		5,252		2,731		12,262		3,642		52			23,939
General and administrative, excluding depreciation and amortization		3,553		1,545		1,077		1,832		10,491			18,498

Operating income (loss)		34,889		21,522		27,280		8,000		(10,543	)		81,148


Six Months Ended June 30, 2006

	Domestic Contract Drilling Services		International Contract Drilling Services		Domestic Marine Services		International Marine Services		Corporate and Other			Total
Revenues	$	65,288	$	4,276	$	55,760	$	7,106	$	—		$	132,430
Operating expenses, excluding depreciation and amortization		23,326		1,603		20,050		3,217		—			48,196
Depreciation and amortization		3,741		251		8,888		553		52			13,485
General and administrative, excluding depreciation and amortization		3,373		507		1,162		1,354		6,791			13,187

Operating income (loss)		34,848		1,915		25,660		1,982		(6,843	)		57,562

NOTE 8 – COMMITMENTS AND CONTINGENCIES

Legal Proceedings

The Company is involved in various claims and lawsuits in the normal course of business. As of June 30, 2007, management did not believe any accruals were necessary in accordance with SFAS No. 5, “Accounting for Contingencies”.

On March 19 and 20, 2007, two TODCO stockholder lawsuits were filed in the District Court of Harris County, Texas, both alleging that the TODCO board of directors (which includes three of our current directors) breached their fiduciary duties in approving the proposed merger among TODCO, Hercules and Merger Sub. The first lawsuit, pending in the 269th Judicial District Court of Harris County, Texas, Cause No. 2007-16357, is a purported stockholder class action suit against the TODCO directors and contains claims for breach of fiduciary duty. The second lawsuit, pending in the 333rd Judicial District Court of Harris County, Texas, Cause No. 2007-16397, is a stockholder derivative action purportedly filed on behalf of TODCO against the TODCO directors (which includes three of our current directors) and Hercules, and contains claims for breach of fiduciary duties of loyalty, due care, candor, good faith and/or fair dealing; corporate waste; unlawful self dealing; and claims that the defendants conspired, aided and abetted and/or assisted one another in a common plan to breach these fiduciary duties. Both lawsuits allege, among other things, that the TODCO directors engaged in self-dealing in approving the proposed merger with Hercules by advancing their own personal interests or those of TODCO’s senior management at the expense of the TODCO stockholders, utilized a defective sales process not designed to maximize TODCO stockholder value, and failed to consider any value maximizing alternatives, thus causing TODCO stockholders to receive an unfair price for their shares of TODCO common stock. The second lawsuit also alleges that Hercules conspired, aided and abetted or assisted in these violations. In addition, the second suit alleges that TODCO’s directors breached their fiduciary duties by allegedly improperly awarding stock options to certain officers at a time when they allegedly knew the merger was “imminent” and the stock options would vest immediately upon consummation of the merger. The second suit also names the officers who received these stock option awards as defendants and alleges three causes of action against them: (1) a breach of fiduciary duty claim for having received allegedly improperly awarded stock options, (2) an unjust enrichment claim seeking a constructive trust, and (3) rescission of the stock option awards.

Both lawsuits seek, among other things, rescission of the merger, imposition of a constructive trust in favor of plaintiffs upon any benefits improperly received by the defendants, attorneys’ fees and expenses associated with the lawsuits and any other equitable relief the courts deem just and proper. The Company, the TODCO directors, and the officers named as defendants believe the asserted claims are without merit, and each intends to defend them vigorously.

In connection with its merger with TODCO, the Company also assumed certain other material legal proceedings from TODCO and its subsidiaries (see NOTE 9).

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.

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

As of June 30, 2007, the Company’s primary marine package provided 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 was $580.0 million; however, coverage for U.S. Gulf of Mexico named windstorm damage was subject to an annual aggregate limit on liability of $75.0 million. The policies were subject to deductibles and other conditions. Deductibles for events that are not U.S. Gulf of Mexico named windstorm events were $1.5 million per occurrence for drilling rigs, and ranged 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 in a U.S. Gulf of Mexico named windstorm event were $1.5 million per rig for each occurrence plus an additional $5.0 million for each U.S. Gulf of Mexico named windstorm. The protection and indemnity coverage under the primary marine package had a $5.0 million limit per occurrence with excess liability coverage up to $100.0 million. The primary marine package also provided coverage for cargo and charterer’s legal liability. Vessel pollution was covered under a Water Quality Insurance Syndicate policy. In addition to the marine package, the Company had separate policies providing coverage for general domestic liability, employer’s liability, domestic auto liability and non-owned aircraft liability, with customary deductibles and coverage.

In July 2007, the Company completed the renewal of all its key insurance policies (see NOTE 9).

Surety Bonds

In connection with the TODCO acquisition in July 2007, the Company assumed certain surety bonds totaling $54.2 million at June 30, 2007. The surety bonds guarantee our performance as it relates to TODCO’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 and Venezuela.

NOTE 9 – SUBSEQUENT EVENTS

In July 2007, the Company completed the acquisition of TODCO (see NOTE 3). In connection with the acquisition, the Company entered into a $1,050.0 million credit facility (see NOTE 5) and certain related hedging instruments (see NOTE 6). In connection with the acquisition, the Company also assumed Senior Notes, an unsecured line of credit with a bank in Venezuela and surety bonds (see NOTES 5 and 8).

In July 2007, the Company repaid $55.6 million of outstanding debt (see NOTE 5) and cancelled all outstanding derivative instruments relating to the debt (see NOTE 6).

In July 2007, the Company’s stockholders approved an increase in the shares available for grant or award under the 2004 Plan (see NOTE 1).

Insurance

In July 2007, the Company completed the renewal of all 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 $2.6 billion; however, coverage for U.S. Gulf of Mexico named windstorm damage is subject to an annual aggregate limit on liability of $150.0 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 $0.250 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 general liability, employer’s liability, auto liability and non-owned aircraft liability, with customary deductibles and coverage. In connection with the renewal, the Company entered into an agreement to finance a portion of its annual insurance premiums. The interest rate is 5.75% and the note matures in June 2008.

Legal Proceedings

In connection with its merger with TODCO, the Company also assumed certain other 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 (and now of the Company) as a potentially responsible party 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 its designation as a potentially responsible party and does not expect that the ultimate outcome of this case will have a material adverse effect on its consolidated results of operations, financial position or cash flows. The Company continues to monitor this matter.

Robert E. Aaron et al. vs. Phillips 66 Company et al. Circuit Court, Second Judicial District, Jones County, Mississippi. This is the case name used to refer to several cases that have been filed in the Circuit Courts of the State of Mississippi involving 768 persons that allege personal injury or whose heirs claim their deaths arose out of asbestos exposure in the course of their employment by the defendants between 1965 and 2002. The complaints name as defendants, among others, certain of TODCO’s subsidiaries and certain of Transocean’s subsidiaries to whom TODCO (and now the Company) 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 699 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 103 shared periods of employment by TODCO and Transocean 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 Transocean and TODCO. The Company has not yet had an opportunity to conduct any additional discovery to verify the number of plaintiffs, if any, that were employed by TODCO’s subsidiaries or Transocean’s subsidiaries or otherwise have any connection with TODCO’s or Transocean’s drilling operations. The Company intends to defend itself 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.

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 2000. In March 2003, TODCO paid approximately $2.6 million of the assessment, plus approximately $0.3 million in interest, and the Company is contesting the remainder of the assessment. After TODCO made the partial assessment payment, it received a revised assessment in September 2003 of approximately $16.7 million (based on the current exchange rates at the time of the assessment and inclusive of penalties). Thereafter, TODCO filed an administrative tax appeal with SENIAT and the tax authority rendered a decision that reduced the tax assessment to $8.1 million (based on the current exchange rates at the time of the decision). TODCO then initiated a judicial tax court appeal with the Venezuelan Tax Court to set aside the $8.1 million administrative tax assessment. The Company does not expect the ultimate resolution of this assessment to have a material impact on its consolidated results of operations, financial condition or cash flows. Under a master separation agreement entered into in connection with the IPO, Transocean has agreed to indemnify the Company for any losses it incurs as a result of these legal proceedings.

The Company and its subsidiaries are involved in a number of other lawsuits, all of which have arisen in the ordinary course of the Company’s 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 such 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.

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, 2007 and for the three months and six months ended June 30, 2007 and June 30, 2006, included elsewhere herein, and with our annual report on Form 10-K, as amended, for the year ended December 31, 2006. 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, as amended, and in Item 1A of Part II of this quarterly report for a discussion of certain risks facing our company.

OVERVIEW

We provide shallow-water drilling and liftboat 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 and independent oil and natural gas operators. We report our business activities in four business segments, Domestic Contract Drilling Services, International Contract Drilling Services, Domestic Marine Services and International Marine Services. Prior to the second quarter of 2006, during which we commenced work with Rig 16 under our first international drilling contract, we did not report an International Contract Drilling Services segment.

In July 2007, we completed the acquisition of TODCO. See “Recent Developments” for information regarding the transaction and on the fleet acquired from TODCO.

Contract Drilling Services. We own a fleet of nine jackup rigs that can drill in maximum water depths ranging from 85 to 250 feet. Our Domestic Contract Drilling Services segment includes six jackup rigs operating in the U.S. Gulf of Mexico, and our International Contract Drilling Services segment includes one jackup rig working offshore Qatar, one jackup rig working offshore India and one jackup rig currently undergoing refurbishment and upgrade. Under most of our contract drilling service agreements, 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.

Marine Services. We own a fleet of 60 liftboats in our Domestic and International Marine Services segments, and we operate an additional five liftboats in our International Marine Services segment. Our Domestic Marine Services segment includes 47 liftboats operating in the U.S. Gulf of Mexico, and our International Marine Services segment includes 18 liftboats operating offshore West Africa, including five liftboats owned by a third party and one undergoing refurbishment. Our liftboats are used to provide a wide range of offshore support services, including platform maintenance, platform construction, well intervention and decommissioning services, and can be moved from location to location within a short period of time. 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 and the number and type of units in our fleet. 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. Some of our international drilling contracts and some of our liftboat contracts in West Africa are longer term in nature.

Our operating costs are primarily a function of fleet configuration and utilization levels. The most significant direct operating costs for our Contract Drilling Services segments are wages paid to crews, maintenance and repairs to the rigs, and marine 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” 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, particularly if the rig has been cold-stacked for a long period of time.

The most significant costs for our Marine Services segments are the wages paid to crews and the amortization of regulatory drydocking costs. Unlike our Contract Drilling Services 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 time of 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 12 to 24 months.

RECENT DEVELOPMENTS

In July 2007, we completed our previously announced acquisition of TODCO for total consideration of approximately $2,398.0 million, consisting of $925.8 million in cash and 56.6 million Hercules common shares. 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 our stock for a period before and after the date of the merger agreement between us and TODCO. The fleet acquired from TODCO consists of: 18 jackup and three submersible rigs in the shallow water U.S. Gulf of Mexico; 12 conventional and 15 posted barge rigs that operate inland in marshes, rivers, lakes and shallow bay or costal waterways along the U.S. Gulf Coast; two jackups and one platform rig in Mexico, one jackup rig in Angola; one jackup rig in Brazil; one jackup rig and one land rig in Trinidad; two land rigs in the United States; six land rigs in Venezuela; and an additional jackup rig currently undergoing reactivation in Southeast Asia. Delta Towing, a wholly owned subsidiary, operates a fleet of 42 inland tugs, 18 offshore tugs, 36 crew boats, 39 deck barges, 17 shale barges, four spud barges, and one offshore barge along and in the U.S. Gulf of Mexico. In connection with the acquisition, we assumed Senior Notes, an unsecured line of credit with a bank in Venezuela and surety bonds.

In July 2007, we 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 of the borrowings will be used, together with cash on hand, as necessary, to finance the cash portion of our acquisition of TODCO, to repay amounts under our and TODCO’s existing senior secured credit facilities outstanding at the closing of the facility and to make certain other payments in connection with our acquisition of TODCO.

In July 2007, we completed the renewal of our key insurance policies. See NOTE 9 in “Notes to Unaudited Consolidated Financial Statements”.

RESULTS OF OPERATIONS

The following table sets forth our operating days, average utilization rates, average revenue and expenses per day, revenues and operating expenses by operating segment and other selected information for the periods indicated:


	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
	(Dollars in thousands, except per day amounts)
Domestic Contract Drilling Services Segment:
Number of rigs (as of end of period)		6			7			6			7
Operating days		375			494			849			876
Available days		546			524			1,086			974
Utilization (1)		68.7	%		94.3	%		78.2	%		89.9	%
Average revenue per rig per day (2)	$	75,531		$	77,513		$	83,812		$	74,530
Average operating expense per rig per day (3)	$	25,455		$	23,318		$	25,287		$	23,949
Revenues	$	28,325		$	38,291		$	71,156		$	65,288
Operating expenses, excluding depreciation and amortization	$	13,899		$	12,219		$	27,462		$	23,326
Depreciation and amortization expense	$	2,691		$	2,089		$	5,252		$	3,741
General and administrative expenses, excluding depreciation and amortization	$	1,611		$	1,587		$	3,553		$	3,373
Operating income	$	10,124		$	22,396		$	34,889		$	34,848

International Contract Drilling Services Segment:
Number of rigs (as of end of period)		3			2			3			2
Operating days		179			33			359			33
Available days		182			37			362			37
Utilization (1)		98.4	%		89.2	%		99.2	%		89.2	%
Average revenue per rig per day (2)	$	109,719		$	129,577		$	112,857		$	129,577
Average operating expense per rig per day (3)	$	40,305		$	43,320		$	40,659		$	43,320
Revenues	$	19,640		$	4,276		$	40,516		$	4,276
Operating expenses, excluding depreciation and amortization	$	7,335		$	1,603		$	14,718		$	1,603
Depreciation and amortization expense	$	1,363		$	251		$	2,731		$	251
General and administrative expenses, excluding depreciation and amortization	$	1,015		$	472		$	1,545		$	507
Operating income	$	9,927		$	1,950		$	21,522		$	1,915

Domestic Marine Services Segment:
Number of liftboats (as of end of period)		47			47			47			47
Operating days		2,980			2,802			5,647			5,652
Available days		4,186			3,699			8,285			7,157
Utilization (1)		71.2	%		75.8	%		68.2	%		79.0	%
Average revenue per liftboat per day (2)	$	12,482		$	10,765		$	12,378		$	9,865
Average operating expense per liftboat per day (3)	$	3,736		$	2,935		$	3,534		$	2,801
Revenues	$	37,195		$	30,163		$	69,898		$	55,760
Operating expenses, excluding depreciation and amortization	$	15,639		$	10,857		$	29,279		$	20,050
Depreciation and amortization expense	$	6,192		$	4,910		$	12,262		$	8,888
General and administrative expenses, excluding depreciation and amortization	$	539		$	417		$	1,077		$	1,162
Operating income	$	14,825		$	13,979		$	27,280		$	25,660


	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
	(Dollars in thousands, except per day amounts)
International Marine Services Segment:
Number of liftboats (as of end of period)		18			4			18			4
Operating days		1,252			355			2,414			712
Available days		1,547			364			3,021			724
Utilization (1)		80.9	%		98.0	%		79.9	%		98.0	%
Average revenue per liftboat per day (2)	$	11,090		$	10,047		$	11,573		$	9,980
Average operating expense per liftboat per day (3)	$	4,862		$	4,346		$	4,788		$	4,445
Revenues	$	13,884		$	3,567		$	27,938		$	7,106
Operating expenses, excluding depreciation and amortization	$	7,523		$	1,581		$	14,464		$	3,217
Depreciation and amortization expense	$	1,938		$	274		$	3,642		$	553
General and administrative expenses, excluding depreciation and amortization	$	882		$	593		$	1,832		$	1,354
Operating income	$	3,541		$	1,119		$	8,000		$	1,982

Total Company:
Revenues	$	99,044		$	76,297		$	209,508		$	132,430
Operating expenses, excluding depreciation and amortization	$	44,396		$	26,260		$	85,923		$	48,196
Depreciation and amortization expense	$	12,209		$	7,551		$	23,939		$	13,485
General and administrative expenses, excluding depreciation and amortization	$	9,335		$	6,601		$	18,498		$	13,187
Operating income	$	33,104		$	35,885		$	81,148		$	57,562
Interest expense	$	(1,379	)	$	(2,163	)	$	(3,469	)	$	(4,249	)
Gain on disposal of assets	$	—		$	—		$	—		$	29,580
Loss on early retirement of debt	$	(870	)	$	—		$	(870	)	$	—
Other income	$	1,246		$	1,520		$	2,521		$	1,823
Income before income taxes	$	32,101		$	35,242		$	79,330		$	84,716
Income tax provision	$	(8,635	)	$	(12,309	)	$	(22,473	)	$	(30,871	)
Net income	$	23,466		$	22,933		$	56,857		$	53,845

(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 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 Contract Drilling Services 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, 2007. Included in International Contract Drilling Services revenue is a total of $0.7 million and $2.5 million related to amortization of deferred mobilization revenue and contract specific capital expenditures reimbursed by the customer for the three months and six months ended June 30, 2007, respectively, and $0.1 million for both the three and six months ended June 30, 2006.

(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 Contract Drilling Services operating expense is a total of $0.4 million and $1.6 million related to amortization of deferred mobilization expenses for the three and six months ended June 30, 2007, respectively.

For the Three Months Ended June 30, 2007 and 2006

Revenues

Consolidated. Total revenues for the three-month period ended June 30, 2007 (the “Current Quarter”) were $99.0 million compared with $76.3 million for the three-month period ended June 30, 2006 (the “Comparable Quarter”), an increase of $22.7 million, or 30%. This increase resulted primarily from higher average dayrates in our Domestic Marine Services segment, additional operating days in our International Marine Services segment and the commencement of operations in our International Contract Drilling Services segment partially offset by fewer operating days in our Domestic Contract Drilling Services segment. Total revenues included $2.3 million in reimbursements from our customers for expenses paid by us in the Current Quarter compared with $1.3 million in the Comparable Quarter.

Domestic Contract Drilling Services Segment. Revenues for our Domestic Contract Drilling Services segment were $28.3 million for the Current Quarter compared with $38.3 million for the Comparable Quarter, a decrease of $10.0 million, or 26%. This decrease resulted primarily from fewer operating days, which accounted for $9.0 million of the decrease, and lower average dayrates for our fleet, which accounted for $1.0 million of the decrease. Operating days decreased to 375 in the Current Quarter from 494 in the Comparable Quarter due to 171 days of downtime during the Current Quarter on three of our rigs as compared to 30 days of downtime in the Comparable Quarter on two of our rigs. Average utilization was 68.7% in the Current Quarter compared with 94.3% in the Comparable Quarter. Average revenue per rig per day was $75,531 in the Current Quarter compared with $77,513 in the Comparable Quarter. Revenues for our Domestic Contract Drilling Services segment included $0.1 million in reimbursements from our customers for expenses paid by us in the Current Quarter compared with $0.2 million in the Comparable Quarter.

International Contract Drilling Services Segment. We have two jackups currently working offshore in Qatar and India which commenced operations in the second and third quarters of 2006, respectively. Revenues for our International Contract Drilling Services segment were $19.6 million for the Current Quarter compared with $4.3 million for the Comparable Quarter, an increase of $15.3 million or 356%. Operating days increased to 179 in the Current Quarter from 33 in the Comparable Quarter. Average revenue per rig per day was $109,719 in the Current Quarter compared with $129,577 in the Comparable Quarter, with average utilization of 98.4% in the Current Quarter compared with 89.2% in the Comparable Quarter. Included in revenue for the Prior Quarter is $2.0 million related to a timely departure of Rig 16 from the shipyard. Included in revenue for the Current Quarter is $0.7 million related to amortization of deferred mobilization revenue and contract specific capital expenditures reimbursed by the customer compared to $0.1 in the Comparable Quarter. Revenues in our International Contract Drilling Services segment include reimbursements from our customers of $0.1 million for expenses paid by us in the Current Quarter. There was no reimbursable revenue in the Comparable Quarter.

Domestic Marine Services Segment. Revenues for our Domestic Marine Services segment were $37.2 million for the Current Quarter compared with $30.2 million in the Comparable Quarter, an increase of $7.0 million, or 23%. This increase resulted primarily from higher average dayrates, which contributed $4.8 million of the increase, and additional operating days, which contributed $2.2 million of the increase. Operating days in the Current Quarter were 2,980 compared with 2,802 operating days in the Comparable Quarter. Operating days increased due to the acquisition of six liftboats in the Prior Quarter. Average revenue per liftboat per day was $12,482 in the Current Quarter compared with $10,765 in the Comparable Quarter, with average utilization of 71.2% in the Current Quarter compared with 75.8% in the Comparable Quarter. Revenues for our Domestic Marine Services segment included $1.5 million in reimbursements from our customers for expenses paid by us in the Current Quarter compared with $1.1 million in the Comparable Quarter.

International Marine Services Segment. Revenues for our International Marine Services segment were $13.8 million for Current Quarter compared with $3.6 million in Comparable Quarter, an increase of $10.3 million, or 286%. This increase is due to acquisition activity which resulted in an increase in operating days from 355 days in the Comparable Quarter to 1,252 days in the Current Quarter . Average revenue per liftboat per day was $11,090 in the Current Quarter compared with $10,047 in the Comparable Quarter, with average utilization of 80.9% in the Current Quarter compared with 98.0% in the Comparable Quarter. During the Current Quarter, nine of our liftboats in West Africa were evacuated due to political unrest and earned 75% dayrate during that time, totaling 374 days. The

decrease in utilization is due to additional days in drydock for our fleet, which is larger in the Current Quarter due to acquisition activity. Revenues for our International Marine Services segment included $0.7 million in reimbursements from our customers for expenses paid by us in the Current Quarter. There was no reimbursable revenue in the Comparable Quarter.

Operating Expenses

Consolidated. Total operating expenses, excluding depreciation and amortization, for the Current Quarter were $44.4 million compared with $26.3 million in the Comparable Quarter, an increase of $18.1 million, or 69%. This increase resulted primarily from the increase in rig and liftboat operating expenses described below and the commencement of operations in our International Contract Drilling Services segment.

Domestic Contract Drilling Services Segment. Operating expenses, excluding depreciation and amortization, for our Domestic Contract Drilling Services segment were $13.9 million in the Current Quarter compared with $12.2 million in the Comparable Quarter, an increase of $1.7 million, or 14%. Available days increased to 546 in the Current Quarter from 524 in the Comparable Quarter. Average operating expenses per rig per day were $25,455 in the Current Quarter compared with $23,318 in the Comparable Quarter. The Comparable Quarter included operating expenses for Rig 21 while the rig was undergoing repairs for damage sustained during Hurricane Katrina. During that time, the rig was not considered available and therefore no available days for the rig were included in the calculation of average operating expense per rig per day. On a per day basis, average operating expenses per rig increased $2,137. The increase resulted primarily from an increase in insurance costs, which increased $4,303 per day, partially offset by decreases in labor expenses, which decreased $1,402 per day, and a decrease in rig maintenance costs, which decreased $910 per day.

International Contract Drilling Services Segment. Operating expenses, excluding depreciation and amortization, for our International Contract Drilling Services segment were $7.3 million in the Current Quarter compared with $1.6 in the Comparable Quarter, an increase of $5.7 million or 356%. Available days increased to 182 in the Current Quarter from 37 in the Comparable Quarter. Average operating expenses per rig per day were $40,305 in the Current Quarter compared with $43,320 in the Comparable Quarter. Included in operating expense is $0.4 million related to amortization of deferred mobilization expense in the Current Quarter.

Domestic Marine Services Segment. Operating expenses, excluding depreciation and amortization, for our Domestic Marine Services segment were $15.6 million for the Current Quarter compared with $10.9 million in the Comparable Quarter, an increase of $4.7 million, or 43%. The increase is due to liftboat acquisitions, additional operating days and a $1.0 million deductible related to damage to one of our liftboats accrued in the Current Quarter. Average operating expenses per liftboat per day were $3,736 in the Current Quarter compared with $2,935 in the Comparable Quarter. This increase resulted primarily from an increase in labor expenses, which increased $433 per day, an increase in insurance costs, which increased $79 per day and an increase in maintenance costs, which increased $180 per day.

International Marine Services Segment. Operating expenses, excluding depreciation and amortization, for our International Marine Services segment were $7.5 million for the Current Quarter compared with $1.6 million in the Comparable Quarter, an increase of $5.9 million, or 369%. The increase is due to additional liftboats acquired in the fourth quarter of 2006. Average operating expenses per liftboat per day were $4,862 in the Current Quarter compared with $4,346 in the Comparable Quarter.

Depreciation and Amortization

Depreciation and amortization expense in the Current Quarter was $12.2 million compared with $7.6 million in the Comparable Quarter, an increase of $4.6 million, or 61%. This increase resulted primarily from an additional $0.6 million in depreciation expense for our Domestic Contract Drilling Services segment, $0.6 million for our Domestic Marine Services segment, $1.1 million for our International Contract Drilling Services segment and $0.9 million for our International Marine Services segment. This increase in depreciation expense for these segments is related primarily to acquisition activity between the Comparable Quarter and the Current Quarter. Additionally, amortization of regulatory inspections and related drydockings increased $1.5 million.

General and Administrative Expenses

General and administrative expenses, excluding depreciation and amortization, in the Current Quarter were $9.3 million compared with $6.6 million in the Comparable Quarter, an increase of $2.7 million, or 41%. This increase is due primarily to higher general and administrative expenses for our corporate offices in addition to increases in general and administrative expenses in our operating segments. General and administrative expenses for our corporate office increased to $5.3 million in the Current Quarter from $3.5 million in the Comparable Quarter, an increase of $1.8 million. This increase is due primarily to increased headcount due to growth and acquisitions, severance and accelerated vesting costs of $0.5 million and additional stock-based compensation expense of $0.7 million. General and administrative expenses increased $0.3 million in our International Marine Services segment and $0.5 million in our International Contract Drilling Services Segment from the Comparable Quarter to the Current Quarter and increased $0.1 million in our Domestic Marine Services segment.

Loss on Early Retirement of Debt

The loss on early retirement of debt consisted of $0.9 million related to the write off of deferred financing fees in connection with repayment of $37.0 million of term loan principal in April 2007.

Other Income

Other income in the Current Quarter was $1.2 million compared with $1.5 million in the Comparable Quarter, a decrease of $0.3 million. This decrease is due to a gain in the Comparable Quarter related to insurance proceeds received related to damage to our New Iberia facility in Hurricane Katrina.

Income Tax Provision

Income tax expense was $8.6 million on pre-tax income of $32.1 million during the Current Quarter, compared to $12.3 million on pre-tax income of $35.2 million for the Comparable Quarter. The effective tax rate decreased to 26.9% in the Current Quarter from 34.9% in Comparable Quarter. This decrease is due to a higher percentage of total earnings derived from our international segments.

For the Six Months Ended June 30, 2007 and 2006

Revenues

Consolidated. Total revenues for the six-month period ended June 30, 2007 (the “Current Period”) were $209.5 million compared with $132.4 million for the six-month period ended June 30, 2006 (the “Comparable Period”), an increase of $77.1 million, or 58%. This increase resulted primarily from higher average dayrates in our Domestic Marine Services segment, additional operating days in our International Marine Services segment and the commencement of operations in our International Contract Drilling Services segment, partially offset by fewer operating days in our Domestic Contract Drilling Services segment. Total revenues included $5.5 million in reimbursements from our customers for expenses paid by us in the Current Period compared with $2.5 million in the Comparable Period.

Domestic Contract Drilling Services Segment. Revenues for our Domestic Contract Drilling Services segment were $71.2 million for the Current Period compared with $65.3 million for the Comparable Period, an increase of $5.9 million, or 9%. This increase resulted primarily from higher average dayrates for our fleet, which accounted for an increase of $8.1 million, partially offset by a decrease of $2.2 million due to fewer operating days. Operating days decreased to 849 in the Current Period from 876 in the Comparable Period due to additional downtime on three of our rigs. Average revenue per rig per day was $83,812 in the Current Period compared with $74,530 in the Comparable Period, with average utilization of 78.2% in the Current Period compared with 89.9% in the Comparable Period. Revenues for our Domestic Contract Drilling Services segment included $0.6 million in reimbursements from our customers for expenses paid by us in the Current and Comparable Period.

International Contract Drilling Services Segment. Our International Contract Drilling Services segment comprises one jackup rig working offshore Qatar, a second jackup rig working offshore India, and a third jackup rig currently undergoing upgrade and refurbishment. The two jackups currently working offshore in Qatar and India commenced operations in the second and third quarters of 2006, respectively. Revenues for our International Contract Drilling Services segment were $40.5 million for the Current Period compared with $4.3 million for the Comparable Period, an increase of $36.2 million or 842%. Operating days increased to 359 in the Current Period from 33 in the Comparable Period. Average revenue per rig per day was $112,857 in the Current Period compared with $129,577 in the Comparable Period, with average utilization of 99.2% in the Current Period compared with 89.2% in the Comparable Period. Included in revenue for the Current Period is $2.5 million related to amortization of deferred mobilization revenue and contract specific capital expenditures reimbursed by the customer compared to $0.1 million in the Comparable Period. Revenues in our International Contract Drilling Services segment include reimbursements from our customers of $0.3 million for expenses paid by us in the Current Period. There was no reimbursable revenue in the Comparable Period.

Domestic Marine Services Segment. Revenues for our Domestic Marine Services segment were $69.9 million for the Current Period compared with $55.8 million in the Comparable Period, an increase of $14.1 million, or 25%. This increase resulted primarily from higher average dayrates, which contributed $14.2 million of the increase, partially offset by $0.1 million related to fewer operating days. Operating days in the Current Period were 5,647 compared with 5,652 operating days in the Comparable Period. Average revenue per liftboat per day was $12,378 in the Current Period compared with $9,865 in the Comparable Period, with average utilization of 68.2% in the Current Period compared with 79.0% in the Comparable Period. Revenues for our Domestic Marine Services segment included $2.8 million in reimbursements from our customers for expenses paid by us in the Current Period compared with $1.9 million in the Comparable Period.

International Marine Services Segment. Revenues for our International Marine Services segment were $27.9 million for the Current Period compared with $7.1 million in the Comparable Period, an increase of $20.8 million, or 293%. This increase is due to acquisition activity which resulted in an increase in operating days from 712 days in 2006 to 2,414 days in 2007. Average revenue per liftboat per day was $11,573 in the Current Period compared with $9,980 in the Comparable Period, with average utilization of 79.9% in the Current Period compared with 98.0% in the Comparable Period. During the Current Period, nine of our liftboats in West Africa were evacuated due to political unrest and earned 75% dayrate during that time, totaling 374 days. Revenues for our International Marine Services segment included $1.9 million in reimbursements from our customers for expenses paid by us in the Current Period. There was no reimbursable revenue in the Comparable Period.

Operating Expenses

Consolidated. Total operating expenses, excluding depreciation and amortization, for the Current Period were $85.9 million compared with $48.2 million in the Comparable Period, an increase of $37.7 million, or 78%. This increase resulted primarily from the increase in rig and liftboat operating expenses described below and the commencement of operations in our International Contract Drilling Services segment.

Domestic Contract Drilling Services Segment. Operating expenses, excluding depreciation and amortization, for our Domestic Contract Drilling Services segment were $27.5 million in the Current Period compared with $23.3 million in the Comparable Period, an increase of $4.2 million, or 18%. Available days increased to 1,086 in the Current Period from 974 in the Comparable Period. Average operating expenses per rig per day were $25,287 in the Current Period compared with $23,949 in the Comparable Period. On a per day basis, average operating expenses per rig increased $1,338. The increase resulted primarily from an increase in insurance costs, which increased $4,159 per day, partially offset by decreases in labor expenses, which decreased $1,510 per day, a decrease in rig maintenance costs, which decreased $767 per day, and a decrease in other rig costs, which decreased $544 per day.

International Contract Drilling Services Segment. Operating expenses, excluding depreciation and amortization, for our International Contract Drilling Services segment were $14.7 million in the Current Period compared with $1.6 in the Comparable Period, an increase of $13.1 million or 819%. Available days increased to 362 in the Current Period from 37 in the Comparable Period. Average operating expenses per rig per day were $40,659 in the Current Period compared with $43,320 in the Comparable Period. Included in operating expense is $1.6 million related to amortization of deferred mobilization expense in the Current Period.

Domestic Marine Services Segment. Operating expenses, excluding depreciation and amortization, for our Domestic Marine Services segment were $29.3 million for the Current Period compared with $20.1 million in the Comparable Period, an increase of $9.2 million, or 46%. The increase is due primarily to liftboat acquisitions, additional operating days and a $1.0 million deductible related to damage to one of our liftboats accrued in the Current Period. Average operating expenses per liftboat per day were $3,534 in the Current Period compared with $2,801 in the Comparable Period. This increase resulted primarily from an increase in labor expenses, which increased $402 per day, and an increase in insurance costs, which increased $121 per day, an increase in maintenance costs, which increased $97 per day and an increase in other costs, which increased $113 per day.

International Marine Services Segment. Operating expenses, excluding depreciation and amortization, for our International Marine Services segment were $14.5 million for the Current Period compared with $3.2 million in the Comparable Period, an increase of $11.3 million, or 353%. The increase is due to additional liftboats acquired in the fourth quarter of 2006. Average operating expenses per liftboat per day were $4,788 in the Current Period compared with $4,445 in the Comparable Period.

Depreciation and Amortization

Depreciation and amortization expense in the Current Period was $23.9 million compared with $13.5 million in the Comparable Period, an increase of $10.4 million, or 77%. This increase resulted primarily from an additional $1.6 million in depreciation expense for our Domestic Contract Drilling Services segment, $1.4 million for our Domestic Marine Services segment, $2.4 million for our International Contract Drilling Services segment and $1.9 million for our International Marine Services segment. This increase in depreciation expense for these segments is related primarily to acquisition activity between the Comparable Period and the Current Period. Additionally, amortization of regulatory inspections and related drydockings increased $3.2 million.

General and Administrative Expenses

General and administrative expenses, excluding depreciation and amortization, in the Current Period were $18.5 million compared with $13.2 million in the Comparable Period, an increase of $5.3 million, or 40%. This increase is due primarily to higher general and administrative expenses for our corporate offices in addition to increases in general and administrative expenses in our operating segments. General and administrative expenses for our corporate office increased to $10.5 million in the Current Period from $6.8 million in the Comparable Period, an increase of $3.7 million. This increase is due to increased headcount due to growth and acquisitions, severance and accelerated vesting costs of $0.5 million, additional stock-based compensation expense of $1.1 million and higher professional fees. General and administrative expenses increased $0.2 million in our Domestic Contract Drilling Services segment, $1.0 million in our International Contract Drilling Services segment and $0.5 million in our International Marine Services Segment from the Comparable Period to the Current Period. General and administrative expenses decreased $0.1 million in our Domestic Marine Services segment from the Comparable Period to the Current Period.

Gain on Disposal of Asset

The gain on disposal of asset in the Comparable Period consisted of $29.6 million related to the insurance settlement on the loss of Rig 25 in Hurricane Katrina.

Loss on Early Retirement of Debt

The loss on early retirement of debt consisted of $0.9 million related to the write off of deferred financing fees in connection with repayment of $37.0 million of term loan principal in April 2007.

Other Income

Other income in the Current Period was $2.5 million compared with $1.8 million in the Comparable Period, an increase of $0.7 million. This increase is due to higher cash balances resulting in increased interest income in the Current Period partially offset by a gain of $0.3 million in the Comparable Period related to insurance proceeds received related to damage to our New Iberia facility in Hurricane Katrina.

Income Tax Provision

Income tax expense was $22.5 million on pre-tax income of $79.3 million during the Current Period, compared to $30.9 million on pre-tax income of $84.7 million for the Comparable Period. The effective tax rate decreased to 28.3% in the Current Period from 36.4% in Comparable Period. This decrease is due to a higher percentage of total earnings derived from our international segments.

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 Form 10-Q. 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, and stock-based compensation. 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, 2006, as amended.

OUTLOOK

Contract Drilling Services

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. As of July 19, 2007, the spot price for Henry Hub natural gas was $6.50 per mmbtu and the twelve month strip, or the average of the next twelve month’s futures contract was $7.84 per mmbtu. Spot natural gas prices have declined over the last several months, from a recent high of $9.07 per mmbtu in February 2007 as storage has increased, and now stand 16% above the five year average. Declining reservoir sizes and increasing initial decline rates in North America have been supportive of natural gas prices, while increased onshore drilling activity, growing deepwater production and increasing liquefied natural gas deliveries have played a role in the above average storage levels. 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 $77.03 per bbl since the beginning of 2006. As of July 19, 2007, the price of WTI was $75.92 with a twelve month strip of $74.50. Both natural gas and oil prices are higher than historical levels and are generally supportive of increased capital spending for exploration and production activities.

Global demand for jackup rigs has increased significantly over the last several years. International markets such as the Middle East, India and Mexico have been particularly strong and have drawn available rigs from other regions such as 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 83 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 71. We anticipate that there will be additional need for jackups in several international locations, which could further reduce the supply of rigs in the U.S. Gulf of Mexico.

Demand for jackup rigs in the U.S. Gulf of Mexico has also declined considerably over the last year to a low of 57 in April 2007 from 88 in January 2006. Demand recently increased slightly to 62 jackup rigs. A combination of factors, has resulted in this decline from the levels experienced over the previous several years, including record high natural gas storage during late 2006 and near record storage currently, coupled with declining target reservoir sizes, rising finding, development and lifting costs, and the significant amount of property transfers. As a result, market dayrates have declined from their highs. 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 potential reduced drilling demand.

According to ODS-Petrodata, as of July 6, 2007, 77 jackup rigs have been ordered by industry participants, national oil companies and financial investors for delivery through 2010. We do not anticipate that these rigs will compete directly with our fleet in the U.S. Gulf of Mexico, but may impact us through competition in other markets. As a result of higher dayrates, longer duration contracts, lower insurance costs which are prevalent in international markets, among other factors, we believe the vast majority of the newbuild jackup rigs will target international markets. Our ability to expand our international drilling fleet may be limited, however, by the increased supply of newbuild rigs.

The offshore drilling market remains highly competitive and cyclical, and it has been historically 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.

Marine Services

Although activity levels for liftboats in the U.S. Gulf of Mexico are not as closely correlated to movement in commodity prices as for offshore drilling rigs, a continued weakening in commodity prices could result in lower utilization of our liftboat fleet. Lower commodity prices tend to result in lower cash flows for our customers and, despite the production maintenance related nature of the majority of the work, some of the work may be deferred.

As of July 19, 2007, we believe that there were 9 liftboats under construction or on order in the U.S. that may be used in the U.S. Gulf of Mexico, with anticipated delivery dates during 2007 and 2008. Once delivered, these liftboats may 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, 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 have actively marketed a number of our liftboats currently operating in the U.S. Gulf of Mexico for projects in international locations, which have long-term contract opportunities.

Labor Markets

We require highly skilled personnel to operate our rigs and liftboats and to support our business, including our business acquired in the merger with TODCO. Competition for skilled personnel continues to intensify as new rigs and liftboats enter the market. We have also experienced a tightening in the labor market for rig personnel due to the increasing number of new offshore and onshore rigs in the U.S. markets. In response to these conditions, we have

instituted retention programs, including increases in base compensation and bonuses tied to retention and utilization goals. We expect these programs, along with additional programs that may become necessary to retain skilled personnel, to continue for the foreseeable future. If this trend continues, our labor costs will likewise continue to increase, although we do not believe at this time that our operations will be limited. We have also experienced a tightening in the labor market for liftboat personnel due to price competition.

Many of the shipyards in the U.S. have experienced similar labor issues, including those that we use for the refurbishment and maintenance of our drillings rigs or that support the maintenance of our liftboat fleet. We have, in some instances, experienced delays in shipyard projects on our drilling rigs or lower utilization for our liftboats as some shipyards have experienced a limit on their production due to labor shortages.

LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses of Cash

Sources and uses of cash for the six-month periods ended June 30, 2007 and 2006 are as follows:


	Six Months Ended June 30,
	2007			2006
	(dollars in millions)
Net cash provided by operating activities
Net income	$	56.9		$	53.8
Depreciation and amortization		23.9			13.5
(Decrease) increase in accounts payable and other current liabilities		(6.5	)		16.7
Decrease in insurance note payable		(6.1	)		(2.4	)
Deferred income tax provision		5.0			17.4
Stock-based compensation		2.9			1.5
Excess tax benefit from stock-based payment arrangements		(1.7	)		—
Loss on early retirement of debt		0.9			—
Gain on disposal of assets		(0.3	)		(29.6	)
(Increase) decrease in accounts receivable, insurance claims receivable and other current assets		11.1			(27.9	)

Total	$	86.1		$	43.0

Net cash used in investing activities
Marketable securities	$	(23.9	)	$	—
Acquisition of Rig 26		—			(20.1	)
Acquisition of six liftboats		—			(52.0	)
Acquisition of a liftboat		(8.3	)		—
Refurbishment and upgrade of Rig 16		—			(9.6	)
Refurbishment and upgrade of Rig 31		—			(10.7	)
Refurbishment and upgrade of Rig 26		(24.1	)		(9.0	)
Other rig refurbishments		(3.4	)		(15.8	)
Refurbishments of liftboats		(1.6	)		(2.2	)
Deferred drydocking expenditures for liftboats		(9.9	)		(6.5	)
Insurance proceeds received		—			50.1
Proceeds from sale of assets		0.6			—
Other		(0.7	)		0.4

Total	$	(71.3	)	$	(75.4	)

Net cash provided by (used in) financing activities
Payment of debt	$	(37.7	)	$	(0.7	)
Excess tax benefit from stock-based payment arrangements		1.7			—
Proceeds from issuance of common stock		—			54.2
Proceeds from exercise of stock options		1.5			0.2
Distributions to members		—			(3.7	)
Payment of debt issuance costs		(0.4	)		(0.6	)

Total	$	(34.9	)	$	49.4

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 a bank line of credit. We also maintain a shelf registration statement covering the future issuance of various types of securities, including debt and common shares.

Additional capital in either the form of debt or equity may be required in 2007 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. 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 further 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 can provide no assurance as to the timing of any asset sales or the proceeds that could be realized by us from any such asset sale.

Cash Requirements and Contractual Obligations

TODCO Acquisition

In connection with the acquisition of TODCO in July 2007, we issued approximately 56.6 million of our common shares and borrowed $900.0 million under a new senior secured term loan. Additionally, upon closing of the acquisition, we terminated our former credit facility and entered into a new $150.0 revolving credit facility. In connection with the acquisition of TODCO, we assumed Senior Notes, an unsecured line of credit with a bank in Venezuela and surety bonds. The proceeds of the borrowings under the senior secured term loan will be used, together with cash on hand, as necessary, to finance the cash portion of our acquisition of TODCO, to repay amounts under our and TODCO’s existing senior secured credit facilities outstanding at the closing of the facility and to make certain other payments in connection with our acquisition of TODCO.

Debt

Our current debt structure is used to fund our business operations. At June 30, 2007, our $75.0 million revolving credit facility was a source of liquidity. As of June 30, 2007, $55.6 million of the principal amount of the term loan was outstanding, and the interest rate was 8.60%. No amounts were outstanding and no letters of credit had been issued under the revolving credit facility.

In July 2007, we repaid the remaining outstanding $55.6 million under the term loan, together with accrued and unpaid interest of $1.2 million. Additionally we cancelled all derivative instruments related to the term loan, which included an interest rate swap on $35.0 million of term loan principal and two interest rate caps on a total of $20.0 million of term loan principal.

In July 2007, and in connection with the TODCO acquisition, 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. 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. We are permitted to prepay amounts outstanding under the revolving credit facility at any time without penalty. Amounts outstanding under the revolving credit facility bear interest at either the eurodollar rate or the base prime rate plus a margin that is initially 1.75% for revolving loans bearing interest at the eurodollar rate and 0.75% for revolving loans bearing interest at the base prime rate. After we deliver to the lenders under the credit facility our financial statements for the fiscal year ending December 31, 2007, the applicable margin under the revolving credit facility will vary depending on our leverage ratio, with the applicable margin for revolving loans bearing interest at the eurodollar rate ranging between 1.25% and 1.75% per annum and the applicable margin for revolving loans bearing interest at the base prime rate ranging between 0.25% and 0.75% per annum. We pay a commitment fee on the unused portion of the revolving credit facility, which ranges between 0.25% and 0.375% depending on our leverage ratio. We pay a letter of credit fee of between 1.25% and 1.75% per annum with respect to the undrawn amount of each letter of credit issued under the revolving credit facility.

The principal amount of the term loan under the term loan facility amortizes in equal quarterly installments of $2.25 million, with the balance due on July 11, 2013. In addition, we are required to prepay the term loans with:

•

the net proceeds from sales of certain assets to the extent that we do not reinvest the proceeds in our business within one year;

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the net proceeds from casualties or condemnations of assets to the extent that we do not reinvest the proceeds in our business within one year;

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the net proceeds of debt that we incur to the extent that such debt is not permitted by the credit agreement;

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50% of the net proceeds that we receive from any issuance of preferred stock; and

•

commencing with the fiscal year ending December 31, 2008, 50% of our excess cash flow until the outstanding principal balance of the term loans is less than $550.0 million.

Other than the quarterly payments referred to above and these mandatory prepayments, the term loan facility requires interest-only payments on a quarterly basis until maturity. We are permitted to prepay amounts outstanding under the term loan facility at any time without penalty. Amounts outstanding under the term loan facility bear interest at either the eurodollar rate or the base prime rate plus a margin that is initially 1.75% for term loans bearing interest at the eurodollar rate and 0.75% for term loans bearing interest at the base prime rate. After we deliver to the lenders under the credit agreement our financial statements for the fiscal year ending December 31, 2007, the applicable margin under the term loan facility will vary depending on our leverage ratio, with the applicable margin for term loans bearing interest at the eurodollar rate ranging between 1.50% and 1.75% per annum and the applicable margin for term loans bearing interest at the base prime rate ranging between 0.50% and 0.75% per annum.

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

In July 2007, we entered into derivative instruments with the purpose of hedging future interest payments on our new term loan facility. We entered into a floating to fixed interest rate swap with decreasing notional amounts beginning with $400.0 million with a payment date of December 31, 2007 and ending with $50.0 million with a payment 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 payment 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 payment dates of the collar match those of the term loan.

In connection with our acquisition of TODCO in July 2007, we assumed Senior Notes and an unsecured line of credit with a bank in Venezuela. The Senior Notes outstanding totaled $16.3 million net of unamortized discounts and premiums at June 30, 2007. The notes bear interest at rates ranging from 6.95% to 9.50%, with maturities between April 2008 and April 2018. The line of credit is designed to manage local currency liquidity in Venezuela. The maximum amount available to be drawn is 6.0 billion Bolivars ($2.8 million at the current exchange rate at June 30, 2007), and there was 3.0 billion Bolivars ($1.4 million at the current exchange rate at June 30, 2007) outstanding at June 30, 2007.

In July 2007, 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 $33.7 million was financed through this arrangement. The interest rate is 5.75% and the note matures in June 2008.

Capital Expenditures

We expect to spend approximately $29.0 million over the remainder of 2007 on the refurbishment and upgrade of our rigs and liftboats, excluding amounts allocated to Rig 26, THE 205 and THE 208. 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, and is often costly.

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. As part of our acquisitions of Rig 16, Rig 31 and Rig 26, we had to undertake both a major refurbishment project and upgrade of each rig to make them competitive with rigs that are already in operation.

Over the remainder of 2007, we will continue to incur expenditures to upgrade and refurbish our rigs and our liftboats, much of which will relate to the continuing upgrade of Rig 26 and the continuing reactivation of THE 205 and THE 208. We expect to spend approximately $34.6 million in 2007 to complete the upgrade of Rig 26 and approximately $4.9 million and $20.5 million to complete the reactivation of THE 205 and THE 208, respectively. In addition, 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 senior secured credit facility.

Contractual Obligations

For additional information about our contractual obligations as of December 31, 2006, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Liquidity and Financing Arrangements — Contractual Obligations” in Item 7 of our annual report on Form 10-K for the year ended December 31, 2006, as amended.

In connection with the TODCO acquisition in July 2007, we assumed certain surety bonds totaling $54.2 million at June 30, 2007. The surety bonds guarantee our performance as it relates to TODCO’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 and Venezuela.

Except with respect to the Senior Notes, unsecured line of credit with a bank in Venezuela, surety bonds and purchase commitments of $58.0 million assumed in connection with our July 2007 acquisition of TODCO, there have been no material changes to such disclosure regarding our contractual obligations made in our annual report.

Accounting Pronouncements

In June 2006, the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109 (“FIN 48”). We adopted FIN 48 and its adoption did not have a material impact on our Consolidated Balance Sheet, Statement of Operations or Statement of Cash Flow. We did not derecognize any tax benefits, nor recognize any interest expense or penalties on unrecognized tax benefits as of the date of adoption. We currently do not anticipate a significant increase in unrecognized tax benefits during the next 12 months. With respect to the acquisition of TODCO, we are evaluating TODCO’s tax positions in the context of our evaluation of the liabilities assumed in the acquisition and which will be accounted for under Statement of Financial Accounting Standards (“SFAS”) No. 141, Business Combinations. At this time, we cannot estimate the change during the next 12 months in unrecognized tax benefits related to TODCO.

We and one of our subsidiaries files income tax returns in the United States, and various state and foreign jurisdictions. Our tax returns for 2004 through 2006 remain open for examination by the taxing authorities in the respective jurisdictions where those returns were filed.

FIN 48 requires that interest expense and penalties related to unrecognized tax benefits be recognized in our Statement of Operations. FIN 48 allows recognized interest and penalties to be classified as either income tax expense or another appropriate expense classification. If we recognize interest expense or penalties on future unrecognized tax benefits, we will classify such interest and penalties as income tax expense.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS No. 157”). 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 will be made pursuant to other accounting pronouncements that require or permit fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. The provisions of SFAS No. 157 are to be applied prospectively upon adoption, except for limited specified exceptions. We are evaluating the requirements of SFAS No. 157 and do not expect the adoption to have a material impact on our Consolidated Balance Sheet or Statement of Operations.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS No. 159”). SFAS No. 159 permits companies to choose to measure certain financial instruments and certain other items at fair value. The standard requires that unrealized gains and losses on items for which the fair value option has been elected be reported in earnings. SFAS No. 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007. We are evaluating the impact, if any, that SFAS No. 159 will have on our Consolidated Balance Sheet, Statement of Operations and Cash Flows.

FORWARD-LOOKING STATEMENTS

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

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

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

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future capital expenditures and refurbishment, repair and upgrade costs;

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expected completion times for our refurbishment and upgrade projects;

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amounts expected to be paid by insurance proceeds for the salvage and repair of the Tigershark;

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

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our plans regarding increased international operations;

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expected useful lives of our rigs and liftboats;

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liabilities under laws and regulations protecting the environment;

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

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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; and

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other expectations regarding TODCO and our merger with TODCO.

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, 2006, as amended, and Item 1A of Part II of this quarterly report and the following:

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

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demand for offshore jackup rigs and liftboats;

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

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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;

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the impact of governmental laws and regulations;

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the adequacy of sources of liquidity;

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

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

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the availability of skilled personnel;

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

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

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the effect of litigation and contingencies; and

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our inability to achieve our plans or carry out our strategy including our plans and strategies related to the merger with TODCO.

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

For information regarding our exposure to certain market risks, see “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A of our annual report on Form 10-K for the year ended December 31, 2006, as amended. There have been no material changes to the disclosure regarding our exposure to certain market risks made in the annual report. For additional information regarding our long-term debt, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Liquidity and Financing Arrangements — Debt” in Item 2 of Part I of this quarterly report.

ITEM 4.

CONTROLS AND PROCEDURES

We carried out an evaluation, under the supervision and with the participation of our management, including Randall D. Stilley, 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. Stilley and Ms. Rodriguez, acting in their capacities as our principal executive officer and our principal financial officer, concluded that, as of June 30, 2007, 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, for information required to be disclosed by us in the reports that we file or submit under the Exchange Act.

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

PART II. OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

candor, good faith and/or fair dealing; corporate waste; unlawful self dealing; and claims that the defendants conspired, aided and abetted and/or assisted one another in a common plan to breach these fiduciary duties. Both lawsuits allege, among other things, that the TODCO directors engaged in self-dealing in approving the proposed merger with Hercules by advancing their own personal interests or those of TODCO’s senior management at the expense of the TODCO stockholders, utilized a defective sales process not designed to maximize TODCO stockholder value, and failed to consider any value maximizing alternatives, thus causing TODCO stockholders to receive an unfair price for their shares of TODCO common stock. The second lawsuit also alleges that Hercules conspired, aided and abetted or assisted in these violations. In addition, the second suit alleges that TODCO’s directors breached their fiduciary duties by allegedly improperly awarding stock options to certain officers at a time when they allegedly knew the merger was “imminent” and the stock options would vest immediately upon consummation of the merger. The second suit also names the officers who received these stock option awards as defendants and alleges three causes of action against them: (1) a breach of fiduciary duty claim for having received allegedly improperly awarded stock options, (2) an unjust enrichment claim seeking a constructive trust, and (3) rescission of the stock option awards.

Both lawsuits seek, among other things, rescission of the merger, imposition of a constructive trust in favor of plaintiffs upon any benefits improperly received by the defendants, attorneys’ fees and expenses associated with the lawsuits and any other equitable relief the courts deem just and proper. The Company, the TODCO directors and the officers named as defendants believe the asserted claims are without merit, and each intends to defend them vigorously.

In connection with its merger with TODCO, the Company also assumed certain other material legal proceedings from TODCO and its subsidiaries.

would be responsible for such claims under the Master Separation Agreement between Transocean and TODCO. The Company has not yet had an opportunity to conduct any additional discovery to verify the number of plaintiffs, if any, that were employed by TODCO’s subsidiaries or Transocean’s subsidiaries or otherwise have any connection with TODCO’s or Transocean’s drilling operations. The Company intends to defend itself 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.

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 2000. In March 2003, TODCO paid approximately $2.6 million of the assessment, plus approximately $0.3 million in interest, and the Company is contesting the remainder of the assessment. After TODCO made the partial assessment payment, it received a revised assessment in September 2003 of approximately $16.7 million (based on the current exchange rates at the time of the assessment and inclusive of penalties). Thereafter, TODCO filed an administrative tax appeal with SENIAT and the tax authority rendered a decision that reduced the tax assessment to $8.1 million (based on the current exchange rates at the time of the decision). TODCO then initiated a judicial tax court appeal with the Venezuelan Tax Court to set aside the $8.1 million administrative tax assessment. In order to procure a prompt decision in this case, on July 11, 2007 the Company requested the Tax Court to constitute the court with associate judges. On July 19, 2007, the Company and SENIAT elected the two associate judges. Currently, the judicial tax court appeal is in the stage of the associate judges’ swearing; following with the constitution of the Tax Court with associate judges. If the judicial decision is unfavorable to the Company, the Company can file a tax appeal before the Administrative-Political Chamber of the Supreme Court.

ITEM 1A.

RISK FACTORS

Except as disclosed in Item 1A of Part II of our quarterly report on Form 10-Q for the quarterly period ended June 30, 2007, there have been no material changes from the risk factors previously disclosed in Item 1A of our annual report on Form 10-K for the year ended December 31, 2006, as amended:

Hercules may experience difficulties in integrating TODCO’s business and could fail to realize potential benefits of the merger.

Achieving the anticipated benefits of the merger with TODCO will depend in part upon whether Hercules is able to integrate TODCO’s business in an efficient and effective manner. Hercules may not be able to accomplish this integration process smoothly or successfully. The difficulties of combining the two companies’ businesses potentially will include, among other things:

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geographically separated organizations and possible differences in corporate cultures and management philosophies,

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significant demands on management resources, which may distract management’s attention from day-to-day business,

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differences in the disclosure systems, accounting systems, and accounting controls and procedures of the two companies, which may interfere with the ability of Hercules to make timely and accurate public disclosure, and

•

the demands of managing new locations and new lines of business acquired from TODCO in the merger.

Any inability to realize the potential benefits of the merger, as well as any delays in integration, could have an adverse effect upon the revenues, level of expenses and operating results of the combined company, which may affect the value of Hercules common stock after the closing of the merger.

Hercules is subject to international political, economic, and other uncertainties.

Prior to the merger with TODCO, Hercules owned or operated 17 liftboats located offshore West Africa, including Nigeria, one drilling rig operating offshore Qatar and another operating offshore India, and Hercules is marketing Rig 26 to work in international markets following completion of the refurbishment and upgrade project on that rig. Nigerian operations are particularly subject to operational hazards, property damage or loss, reduction or suspension of oil and gas production and customer activity, kidnappings, uprisings, violence, and seizures of property or facilities. Hercules operates five vessels owned by a third party under a long-term charter agreement, which could be subject to renegotiation or interpretive or other contractual dispute. Because TODCO also has non-U.S. operations, including Angola, Mexico, Trinidad and Venezuela, Hercules’ non-U.S. operations have expanded following the merger and so will its exposure to the risks inherent in foreign operations.

As a result of Hercules’ international expansion following the merger, its condition and results of operations could be susceptible to adverse events beyond Hercules’ control that may occur in the particular country or region in which Hercules is active. Hercules may also experience currency exchange losses where revenues are received and expenses are paid in nonconvertible currencies or where Hercules does not hedge an exposure to a foreign currency. Hercules 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.

Hercules has operations in Venezuela, which are subject to adverse political and economic conditions.

A portion of Hercules’ operations post-merger are conducted in the Republic of Venezuela, which has been experiencing political and economic turmoil, including labor strikes and demonstrations as well as a growing trend towards nationalization. Recently, Venezuelan officials publicly suggested that Venezuela may nationalize drilling rigs located there. This instability could have an adverse effect on Hercules’ business. Depending on future developments, Hercules could decide to cease operations in Venezuela, which could result in material adverse consequences to Hercules. Venezuela also imposes foreign exchange controls that will limit Hercules’ ability to convert local currency into U.S. dollars and transfer excess funds out of Venezuela. Any changes in existing regulation or enforcement could further restrict Hercules’ ability to receive U.S. dollar payments.

The impact of purchase accounting could adversely affect Hercules’ earnings.

Purchase accounting requires Hercules to allocate the price paid in the merger to TODCO’s assets on the basis of their fair values at the time of the closing of the merger. Those adjustments are expected to result in significant increases in the carrying values of acquired property, plant and equipment costs. The increased value of property, plant and equipment will increase Hercules’ depreciation expense, which will reduce reported earnings but have no effect on cash flows.

As a result of the acquisition, we will record significant goodwill on our balance sheet. We will assess the realizability of the goodwill we have on our books annually as well as whenever events or changes in circumstances indicate that the goodwill may be impaired. These events or circumstances generally include operating losses or a significant decline in earnings associated with the acquired business, which may affect one or more of our reported segments. Our ability to realize the value of the goodwill will depend on the future cash flows of our businesses. These cash flows in turn depend in part on how well we have integrated these businesses. If we are not able to realize the

value of the goodwill, we may be required to incur material charges relating to the impairment of those assets. In addition, the goodwill will be tested annually to assess this amount for impairment under generally accepted accounting principles. If Hercules concludes that the goodwill associated with the merger is impaired or, additionally, that the carrying value of assets acquired in the merger are impaired, the amount of the impairment would reduce the amount of earnings Hercules would otherwise report but would have no effect on its cash flows.

The business of Hercules is expected to continue to be cyclical. The goodwill associated with the merger and the increased carrying values of TODCO’s assets on the balance sheet of Hercules could, therefore, increase the potential for impairment, possibly causing a write-down or write-off of the goodwill and the carrying values of Hercules’ assets acquired in the merger.

Hercules’ ability to timely and effectively complete rig upgrade, refurbishment and repair projects within budget could materially impact financial performance.

Three of Hercules’ rigs, Rig 26, THE 205 and THE 208, continue undergoing major upgrades, refurbishments or repairs. Rig upgrade, refurbishment and repair projects are subject to the risks of delay and cost overruns, which have been previously described by Hercules and TODCO in their respective annual reports on Form 10-K, as amended. Hercules may be subject to financial penalties and contract cancellation fees if it fails to timely complete the repair of THE 205 and the refurbishment of THE 208. THE 205 sustained damage in a previously disclosed incident in 2006, and Hercules believes that the rig may have additional damage. Presently, Hercules cannot predict the extent of damage to, or the costs or time required to repair, THE 205, or the extent to which such costs will be recovered from its insurers or third parties. If Hercules incurs unexpected repair, upgrade or refurbishment costs with regard to these or other projects, is unable to recover certain of such costs from its insurers or third parties, or incurs financial penalties to customers under drilling contracts, or such customers cancel the drilling contracts because of shipyard delays, the financial condition or results of operations of Hercules could be materially adversely affected.

TODCO’s tax sharing agreement with Transocean will require substantial payments by Hercules shortly after the completion of the merger and may require continuing substantial payments after completion of the merger.

TODCO and 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 in a negotiated settlement of disputes between Transocean and TODCO over the terms of the original tax sharing agreement. The tax sharing agreement requires Hercules to make an acceleration payment to Transocean upon completion of the merger as a result of the deemed utilization of TODCO’s pre-IPO tax benefits. Hercules is finalizing its determination of the amount of the acceleration payment, the basis of which determination may be subject to a differing interpretation by Transocean.

Additionally, the tax sharing agreement will continue to require after the merger 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, 2007, assuming a Transocean stock price of $105.98 per share at the time of exercise of the compensatory options (the actual price of Transocean’s common stock at June 29, 2007), is approximately $21.9 million. There is no certainty that Hercules will realize future economic benefits from TODCO’s tax benefits equal to the amount of the payments required under the tax sharing agreement. The payments owing to Transocean adversely affect the economic benefits of the merger that would otherwise accrue to Hercules stockholders and TODCO stockholders.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

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


Period	Total Number of Shares Purchased (1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of a Publicly Announced Plan (2)	Maximum Number of Shares That May Yet Be Purchased Under Plan (2)
April 1 – 30, 2007	—		—	N/A	N/A
May 1 – 31, 2007	440	$	33.50	N/A	N/A
June 1 – 30, 2007	662	$	35.40	N/A	N/A

Total	1,102	$	34.64	N/A	N/A

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

(2)	We did not have at any time during the quarter, and currently do not have, a share repurchase program in place.

ITEM 5.

OTHER INFORMATION

On July 11, 2007, the Company adopted a Policy Regarding Director Recommendations by Stockholders. Under the policy, the nominating and governance committee of the Company’s board of directors will consider candidates properly and timely recommended for directorship by a stockholder or group of stockholders of the Company in accordance with the policy and the Company’s bylaws.

The policy provides that stockholder recommendations must be timely submitted to the Secretary of the Company in writing in accordance with the deadlines contained in the Company’s bylaws. In order to be timely in connection with an annual meeting under the Company’s bylaws, which were amended and restated on July 11, 2007, the recommendation must be received by the Company not less than 90 days or more than 120 days prior to the first anniversary of the date on which the immediately preceding year’s annual meeting of stockholders was held. However, in the event that the date of the annual meeting is more than 30 days before or more than 60 days after the anniversary date, the recommendation must be received by the Company not earlier than the close of business on the 120th day prior to the annual meeting and not later than the close of business on the later of the 90th day prior to the meeting or the 10th day following the day on which public announcement of the date of the meeting is first made by the Company. The bylaws provide for a different set of deadlines if the meeting is a special meeting of stockholders.

The policy requires recommending stockholders submit along with the recommendation written evidence that the recommending stockholder is a stockholder of the Company. The stockholder’s recommendation must include certain information in order to be considered by the committee, including the name and address of the recommending stockholder and the number of shares of each class or series of capital stock of the Company beneficially owned by the recommending stockholder. In addition, the policy requires that the recommending stockholder submit a signed statement that includes certain information regarding the candidate, including the candidate’s name, age, business address and residence address and the candidate’s principal occupation or employment. If the recommending stockholder fails to submit the information required under the policy in a timely manner, the candidate will be ineligible for nomination at the annual meeting.

The policy provides that upon receipt of the recommendation, the committee will consider the qualifications of the candidate and any factors it considers relevant, including the candidate’s general understanding of marketing, finance and other elements relevant to the success of a publicly traded company and the candidate’s understanding of the Company’s business.

The foregoing summary of the policy is qualified in its entirety by reference to the full text of the policy, which is attached as Exhibit 99.1 hereto and incorporated herein by reference. A copy of the policy has also been posted on the Company’s website.

The foregoing description of the Company’s bylaws is qualified in its entirety by reference to the full text of the bylaws, which are attached as Exhibit 3.1 to the Company’s Form 8-K filed July 17, 2007 and incorporated herein by reference. A copy of the bylaws have also been posted on the Company’s website.

ITEM 6.

EXHIBITS


2.1		Amended and Restated Agreement and Plan of Merger effective as of March 18, 2007, by and among Hercules Offshore, Inc., THE Hercules Offshore Drilling Company LLC and TODCO (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed March 22, 2007).

3.1		Amended and Restated Bylaws of Hercules Offshore, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed July 17, 2007).

10.1		Credit Agreement, dated as of July 11, 2007, among the Company, as borrower, its subsidiaries party thereto, as guarantors, UBS AG, Stamford Branch, as issuing bank, administrative agent and collateral agent, Amegy Bank National Association and Comerica Bank, as co-syndication agents, Deutsche Bank AG Cayman Islands Branch and Jefferies Finance LLC, as co-documentation agents, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed July 17, 2007).

10.2		Amended and Restated Hercules Offshore 2004 Long-Term Incentive Plan (incorporated by reference to Annex E to the Company’s Registration Statement on Form S-4 (File No. 333-142314)) (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed July 17, 2007).

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.

99.1*		Policy Regarding Director Recommendations by Stockholders.

*	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/ RANDALL D. STILLEY
		Randall D. Stilley
		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 and Accounting Officer)

Date: August 3, 2007