Edgar Filing: HERCULES OFFSHORE, INC.

Form 10-Q for the quarterly period ended March 31, 2007

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 March 31, 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.


		Outstanding as of April 27, 2007
Common Stock, par value $0.01 per share		32,258,489

HERCULES OFFSHORE, INC.

INDEX


		Page No.
PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Consolidated Balance Sheets as of March 31, 2007 and December 31, 2006		2

Consolidated Statements of Operations for the three months ended March 31, 2007 and March 31, 2006		3

Consolidated Statements of Cash Flows for the three months ended March 31, 2007 and March 31, 2006		4

Consolidated Statements of Comprehensive Income for the three months ended March 31, 2007 and March 31, 2006		5

Notes to Unaudited Consolidated Financial Statements		6

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		15

Item 3. Quantitative and Qualitative Disclosures about Market Risk		28

Item 4. Controls and Procedures		28

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		29

Item 1A. Risk Factors		29

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		30

Item 6. Exhibits		30

Signatures		31

PART I. FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except par value)


	March 31, 2007			December 31, 2006
	(Unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	74,137		$	72,772
Marketable securities		34,000			—
Restricted cash		250			250
Accounts receivable		83,221			89,136
Insurance claims receivable		3,626			—
Prepaid expenses and other		12,828			18,065

Total current assets		208,062			180,223
PROPERTY AND EQUIPMENT, net		421,677			415,864
OTHER ASSETS, net		12,424			9,494

Total assets	$	642,163		$	605,581

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Current portion of long-term debt	$	1,400		$	1,400
Insurance note payable		—			6,058
Accounts payable		35,506			29,123
Accrued liabilities		13,394			16,262
Taxes payable		10,333			8,745
Interest payable		2,047			2,105
Other current liabilities		4,579			5,633

Total current liabilities		67,259			69,326
LONG-TERM DEBT, net of current portion		91,500			91,850
OTHER LIABILITIES		6,491			6,700
DEFERRED INCOME TAXES		46,029			42,854
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS’ EQUITY
Common stock, par value $0.01 per share; 200,000 shares authorized; 32,131 and 32,008 shares issued; 32,124 and 32,002 shares outstanding		321			320
Additional paid-in capital		245,982			243,157
Treasury stock, at cost, 7 shares and 6 shares		(244	)		(220	)
Accumulated other comprehensive income		595			755
Retained earnings		184,230			150,839

Total stockholders’ equity		430,884			394,851

Total liabilities and stockholders’ equity	$	642,163		$	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 March 31,
	2007			2006
REVENUES
Contract drilling services	$	63,707		$	26,997
Marine services		46,757			29,136

		110,464			56,133
COSTS AND EXPENSES
Operating expenses for contract drilling services, excluding depreciation and amortization		20,946			11,107
Operating expenses for marine services, excluding depreciation and amortization		20,581			10,829
Depreciation and amortization		11,730			5,934
General and administrative, excluding depreciation and amortization		9,163			6,586

		62,420			34,456

OPERATING INCOME		48,044			21,677
OTHER INCOME (EXPENSE)
Interest expense		(2,090	)		(2,086	)
Gain on disposal of assets		—			29,580
Other, net		1,275			303

INCOME BEFORE INCOME TAXES		47,229			49,474
INCOME TAX PROVISION		(13,838	)		(18,562	)

NET INCOME	$	33,391		$	30,912

EARNINGS PER SHARE:
Basic	$	1.04		$	1.02
Diluted	$	1.03		$	1.00
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic		31,975			30,173
Diluted		32,471			30,964

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

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Three Months Ended March 31,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	33,391		$	30,912
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		11,730			5,934
Stock-based compensation expense		1,151			703
Deferred income taxes		3,261			13,075
Amortization of deferred financing fees		180			160
Excess tax benefit from stock-based arrangements		(715	)		—
Gain on disposal of assets		(296	)		(29,580	)
(Increase) decrease in operating assets—
Accounts receivable		5,900			(1,438	)
Insurance claims receivable		(3,626	)		(7,673	)
Prepaid expenses and other		3,243			(20	)
Increase (decrease) in operating liabilities—
Accounts payable		6,383			(2,988	)
Insurance note payable		(6,058	)		(1,797	)
Other current liabilities		(1,700	)		9,721
Other liabilities		(209	)		—

Net cash provided by operating activities		52,635			17,009

CASH FLOWS FROM INVESTING ACTIVITIES
Investment in marketable securities		(34,000	)		—
Purchase of property and equipment		(13,719	)		(42,690	)
Deferred drydocking expenditures		(5,486	)		(2,704	)
Proceeds received from sale of assets, net of commissions		610			—

Net cash used in investing activities		(52,595	)		(45,394	)
CASH FLOWS FROM FINANCING ACTIVITIES
Payment of debt		(350	)		(350	)
Proceeds from exercise of stock options		960			—
Excess tax benefit from stock-based arrangements		715			—
Payment of debt issuance costs		—			(193	)
Distributions to members		—			(3,732	)

Net cash provided by (used in) financing activities		1,325			(4,275	)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		1,365			(32,660	)

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

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	74,137		$	14,915

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 March 31,
	2007			2006
NET INCOME	$	33,391		$	30,912

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Unrealized gains (losses) on hedge transactions		(160	)		412

COMPREHENSIVE INCOME	$	33,231		$	31,324

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”). Upon the Conversion, each outstanding membership unit of the limited liability company was converted into 350 shares of common stock of the corporation. 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 markets through its Domestic Contract Drilling Services, International Contract Drilling Services, Domestic Marine Services and International Marine Services segments. The Company owns nine jackup drilling rigs and 59 liftboat vessels and operates an additional five liftboat vessels owned by third parties.

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 March 31, 2007, the results of its operations for the three months ended March 31, 2007 and March 31, 2006 and its cash flows for the three months ended March 31, 2007 and March 31, 2006 have been reflected. The consolidated results of operations for the three months ended March 31, 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.

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 $1,755,000 and $1,170,955 of revenue and expense, respectively, related to mobilization in the three months ended March 31, 2007. The Company had no recognition of deferred revenue or expense for the three months ended March 31, 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 recognized $37,692 of revenue related to such fees in the three months ended March 31, 2007. The Company had no recognition of deferred revenue related to such fees for the three months ended March 31, 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 $3,220,204 and $1,183,312 for the three months ended March 31, 2007 and March 31, 2006, respectively.

Stock-Based Compensation

On January 1, 2006, the Company adopted the modified prospective provisions of Statement of Financial Accounting Standards (“SFAS”) No. 123 (revised 2004) “Share-Based Payment” (“SFAS No. 123R”). Prior to the adoptions of SFAS No. 123R, the Company followed the intrinsic value method as prescribed in Accounting Principles Board Opinion No. 25 “Accounting for Stock Issued to Employees” (“APB Opinion 25”) and related interpretations. SFAS No. 123R requires that compensation cost for stock options is recognized beginning with the effective date based on the requirements of (a) SFAS No. 123R for all share-based payments granted after January 1, 2006 and (b) SFAS No. 123 for all share-based payments granted to employees prior to January 1, 2006 that remain unvested on January 1, 2006. SFAS No. 123R requires that any unearned compensation related to share-based payments awarded prior to adoption be eliminated against the appropriate equity account.

The Company’s 2004 Long-Term Incentive Plan (the “2004 Plan”) provides for the granting of stock options, restricted stock, performance stock awards and other stock-based awards to selected employees and non-employee directors of the Company. At March 31, 2007, 954,214 shares were available for grant or award under the 2004 Plan.

The Company is estimating that the cost relating to stock options granted through March 31, 2007 will be $8,430,871 over the weighted average remaining vesting period of 26 months. No stock options vested during the three months ended March 31, 2007 and March 31, 2006.

The following table summarizes stock option activity under the 2004 Plan:


	Three Months Ended March 31, 2007				Three Months Ended March 31, 2006
	Number of Shares Underlying Options		Weighted Average Exercise Price		Number of Shares Underlying Options	Weighted Average Exercise Price
Outstanding at beginning of period	1,659,922		$	11.27	1,839,500	$	11.38
Granted	423,100			25.48	—		—
Exercised	(123,000	)		7.81	—		—
Forfeited	—			—	—		—

Outstanding at end of period	1,960,022		$	14.56	1,839,500	$	11.38

Exercisable at end of period	1,137,922		$	8.58	1,168,625	$	6.44

The intrinsic value of options exercised during the three months ended March 31, 2007 was $2,242,160.

The following table summarizes information about stock options outstanding at March 31, 2007:


	Options Outstanding				Options Exercisable
Exercise Price	Number Outstanding	Weighted Average Remaining Life (Years)	Weighted Average Exercise Price		Number Exercisable	Weighted Average Exercise Price
$2.86	685,000	7.58	$	2.86	685,000	$	2.86
5.71	87,500	8.08		5.71	87,500		5.71
20.00	764,422	8.58		20.00	365,422		20.00
25.34	373,100	9.88		25.34	—		25.34
26.54	50,000	9.96		26.54	—		26.54

	1,960,022	8.49	$	14.56	1,137,922	$	8.58

The aggregate intrinsic value at March 31, 2007 of options outstanding and options exercisable was $22,932,257 and $20,118,461, respectively.

The following table reflects compensation expense related to stock options (dollars in thousands):

Three Months

Ended

March 31, 2007

Three Months

Ended

March 31, 2006

Compensation expense related to stock options, net of tax of $250 and $199, respectively

464

370

Fair value information and related valuation assumptions for stock options granted are as follows using the Trinomial Lattice option pricing model:


	Three Months Ended March 31, 2007
Expected price volatility		45.00	%
Risk-free interest rate		4.80	%
Expected life of options in years		6
Weighted-average fair value of options granted	$	12.73
Dividend yield		—

The following table summarizes information about restricted stock (dollars in thousands except per share data):


						Gross Compensation Cost				Compensation Cost, Net of Tax
Grant Date	Grant Type	Number of Shares	Value on Grant Date		Vesting Period (Years)	Three Months Ended March 31, 2007		Three Months Ended March 31, 2006		Three Months Ended March 31, 2007		Three Months Ended March 31, 2006
October 2005	Employee	70,000	$	20.00	3	$	117	$	117	$	76	$	76
February 2006	Employee	9,900		30.38	3		25		17		16		11
April 2006	Non-employee director	12,000		40.00	1		120		—		78		—
May 2006	Employee	5,000		34.03	3		14		—		9		—
August 2006	Non-employee director	866		32.70	0.67		11		—		7		—
September 2006	Employee	5,000		33.36	3		14		—		9		—
December 2006	Employee	3,000		34.53	3		8		—		6		—
February 2007	Employee	118,420		25.34	3		125		—		81		—
March 2007	Employee	9,000		26.60	3		3		—		2		—

						$	437	$	134	$	284	$	87

At March 31, 2007 there was $4,379,100 of total unrecognized compensation cost related to unvested restricted stock. The cost is expected to be recognized over a weighted-average period of 2.6 years. The total fair value of restricted shares vested during the three months ended March 31, 2007 was $86,328.

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 March 31, 2007 and December 31, 2006 were $7,144,631 and $5,780,289, respectively. Accumulated amortization of drydocking costs at March 31, 2007 and December 31, 2006 was $7,136,778 and $5,247,651, respectively. Amortization expense for drydocking costs was $4,121,744 and $2,368,124 for the three months ended March 31, 2007 and March 31, 2006, respectively.

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.

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 values 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”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109, Accounting for Income Taxes. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

FIN 48 also requires expanded disclosure with respect to the uncertainty in income tax assets and liabilities. FIN 48 is effective for fiscal years beginning after December 15, 2006. The effect of adoption of FIN 48 is required to be recognized as a change in accounting principle through a cumulative-effect adjustment to retained earnings as of the beginning of the year of adoption. 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.

FIN 48 requires that interest expense and penalties related to unrecognized tax benefits be recognized in the Company’s 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.

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 and 2005 remain open for examination by the taxing authorities in the respective jurisdictions where those returns were filed.

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 Consolidated Balance Sheet and Statement of Operations.

In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS 159”). SFAS 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 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company is evaluating the impact that SFAS 159 will have on its consolidated financial statements.

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 March 31,
	2007		2006
Numerator:
Net income	$	33,391	$	30,912
Denominator:
Weighted average basic shares		31,975		30,173
Add effect of stock equivalents		496		791

Weighted average diluted shares		32,471		30,964

Basic earnings per share	$	1.04	$	1.02
Diluted earnings per share	$	1.03	$	1.00

The Company calculates earnings per share by dividing net income by the weighted average number of shares outstanding. Diluted earnings per share include the dilutive effects of any outstanding stock options calculated under the treasury method. Options with an exercise price equal to or 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 diluted earnings per share calculations.

NOTE 3 –ACQUISITIONS

On March 18, 2007 the Company signed a definitive merger agreement to acquire TODCO for aggregate consideration of approximately 56.9 million shares of common stock of the Company, $0.01 par value (“Company Common Stock”) and approximately $930.0 million in cash. TODCO is a provider of oil and gas services that operates a fleet of 64 drilling rigs, consisting of 27 inland barge rigs, 24 jackup rigs, three submersible rigs, one platform rig and nine land rigs. TODCO also operates through a wholly-owned subsidiary, Delta Towing LLC, a fleet of U.S. marine support vessels consisting primarily of shallow water tugs, crewboats and utility barges along the U.S. Gulf Coast and in the U.S. Gulf of Mexico.

Company Common Stock election or the cash election is oversubscribed. These adjustments, however, will not increase or decrease the total shares of Company Common Stock or the total amount of cash to be paid by the Company. The Company has received a commitment letter for a new syndicated secured term loan of up to $1.1 billion and a $150.0 million revolving credit facility upon the closing of the merger transaction. The Company intends to finance some or all of the cash portion of the merger consideration under the syndicated secured term loan.

The transaction is expected to be completed mid-year 2007 and is subject to approval by the stockholders of both the Company and TODCO, to regulatory approvals and to other customary closing conditions.

NOTE 4 – MARKETABLE SECURITIES

In March 2007, the Company began investing in marketable securities. Marketable securities are classified as available for sale and are stated at fair value on the Consolidated Balance Sheets and are summarized as follows:


			March 31, 2007
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	(in thousands)
Auction rate securities	$	34,000	$	—	$	—	$	34,000

Proceeds from maturities and sales of marketable securities and gross realized gains and losses are summarized as follows:


	Three Months Ended March 31, 2007
	(in thousands)
Proceeds from maturities	$	—
Proceeds from sales		—
Gross realized gains		—
Gross realized losses		—

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

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


	March 31, 2007		December 31, 2006
Senior secured term loan due June 2010	$	92,900	$	93,250

Total debt		92,900		93,250
Less debt due within one year		1,400		1,400

Total long-term debt	$	91,500	$	91,850

Senior secured credit agreement

The Company has a senior secured credit agreement with a syndicate of financial institutions that, as amended, provides for a $140,000,000 term loan and a $75,000,000 revolving credit facility. As of March 31, 2007, $92,900,000 of the principal amount of the term loan was outstanding, and the interest rate was 8.61%. No amounts were outstanding and no letters of credit had been issued under the revolving credit facility.

In April 2007, the Company repaid $37,000,000 of the outstanding amount under the term loan, together with accrued and unpaid interest of $26,517. Additionally, the Company cancelled an interest rate swap on $35,000,000 of the term loan principal.

NOTE 6 – DERIVATIVE INSTRUMENTS AND HEDGING

In July 2005, the Company entered into several transactions to hedge its variable rate debt with the purpose and effect of fixing the interest rate on a portion of the outstanding principal of the term loan. The Company entered into two floating-to-fixed interest rate swaps on a total of $70,000,000 of the term loan principal under which the Company receives an interest rate of three-month LIBOR and pays a fixed coupon over three years, with the terms of the swaps matching those of the term loan. The Company also entered into two purchased interest rate caps hedging interest payments made on a total of $20,000,000 of the term loan principal at a strike price of 5.0% over three years. The counterparty is obligated to pay the Company in any quarter that actual LIBOR resets above the strike price, with the terms of the caps matching those of the term loan. All hedge transactions have payment dates of October 1, January 1, April 1 and July 1.

These hedging arrangements effectively fix the interest rate on $70,000,000 of the principal amount at 7.54% for three years and cap the interest rate on $20,000,000 of the principal amount at 8.25% for three years. 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 was $914,808 and $1,162,317 at March 31, 2007 and December 31, 2006, respectively, and is included in other assets on the Consolidated Balance Sheets. The cumulative net unrealized gain on these hedging instruments was $594,624, net of tax of $320,184, and $755,505, net of tax of $406,812, and is included in accumulated other comprehensive income in the Consolidated Balance Sheets at March 31, 2007 and December 31, 2006, respectively. The Company did not recognize a gain or loss due to hedge ineffectiveness in the Consolidated Statements of Operations for the three months ended March 31, 2007 and March 31, 2006 related to these hedging instruments. The Company recognized a gain of $207,263 and a loss of $40,093 in interest expense for the three months ended March 31, 2007 and March 31, 2006, respectively, related to these hedging instruments.

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 March 31, 2007
	Domestic Contract Drilling Services			International Contract Drilling Services			Domestic Marine Services			International Marine Services			Corporate and Other			Total
Revenues	$	42,831		$	20,876		$	32,703		$	14,054		$	—		$	110,464
Operating expenses, excluding depreciation and amortization		13,563			7,383			13,640			6,941			—			41,527
Depreciation and amortization		2,561			1,368			6,070			1,704			27			11,730
General and administrative, excluding depreciation and amortization		1,942			530			538			950			5,203			9,163

Operating income (loss)		24,765			11,595			12,455			4,459			(5,230	)		48,044
Interest expense		(1,376	)		(7	)		(793	)		(2	)		88			(2,090	)
Other, net		315			284			76			13			587			1,275

Income before income taxes		23,704			11,872			11,738			4,470			(4,555	)		47,229
Income tax (expense) benefit		(8,079	)		(1,172	)		(4,132	)		(1,204	)		749			(13,838	)

Net income (loss)	$	15,625		$	10,700		$	7,606		$	3,266		$	(3,806	)	$	33,391

Total assets (at end of period)	$	143,566		$	130,722		$	192,421		$	98,155		$	77,299		$	642,163

Three Months Ended March 31, 2006
	Domestic Contract Drilling Services			International Contract Drilling Services			Domestic Marine Services			International Marine Services			Corporate and Other			Total
Revenues	$	26,997		$	—		$	25,597		$	3,539		$	—		$	56,133
Operating expenses, excluding depreciation and amortization		11,107			—			9,193			1,636			—			21,936
Depreciation and amortization		1,652			—			3,978			279			25			5,934
General and administrative, excluding depreciation and amortization		1,786			35			745			761			3,259			6,586

Operating income (loss)		12,452			(35	)		11,681			863			(3,284	)		21,677
Interest expense		(1,348	)		—			(738	)		—			—			(2,086	)
Gain on disposal of asset		29,580			—			—			—			—			29,580
Other, net		41			—			13			—			249			303

Income before income taxes		40,725			(35	)		10,956			863			(3,035	)		49,474
Income tax expense		(15,069	)		—			(4,057	)		(303	)		867			(18,562	)

Net income (loss)	$	25,656		$	(35	)	$	6,899		$	560		$	(2,168	)	$	30,912

Total assets (at end of period)	$	164,293		$	62,100		$	136,428		$	19,926		$	18,256		$	401,003

NOTE 8 – COMMITMENTS AND CONTINGENCIES

Legal Proceedings

On March 19 and 20, 2007, two stockholder lawsuits were filed in the District Court of Harris County, Texas, both alleging that the board of directors of TODCO breached their fiduciary duties in approving the proposed acquisition of TODCO by the Company. The first suit, pending in the 333rd Judicial District Court of Harris County, Texas, Cause No. 2007-16397, is a purported stockholder class action suit against the TODCO directors, and contains claims for breach of fiduciary duty. The second suit, pending in the 269th Judicial District Court of Harris County, Texas, Cause No. 2007-16357, is a stockholder derivative action purportedly filed on behalf of TODCO against the TODCO directors and the Company, 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 complaints allege, among other things, that the TODCO directors engaged in self-dealing in approving the proposed acquisition by the Company by advancing their own personal interests or those of TODCO’s senior management at the expense of the

stockholders of TODCO, utilized a defective sales process not designed to maximize 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 suit also alleges that the Company conspired, aided and abetted or assisted in these violations.

Both complaints seek, among other things, an injunction preventing the completion of the acquisition by the Company, rescission if the acquisition is consummated, imposition of a constructive trust in favor of plaintiffs upon any benefits improperly received by the defendants, attorneys’ fees and expenses associated with the lawsuit and any other equitable relief the court deems just and proper. The Company believes the asserted claims are without merit, and intends to defend them vigorously.

The Company is involved in various other claims and lawsuits in the normal course of business. Management does not believe any accruals are necessary in accordance with SFAS No. 5, “Accounting for Contingencies”.

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, maritime employers liability, general liability, vessel pollution and other coverages. 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 $580,000,000; however, coverage for U.S. Gulf of Mexico named windstorm damage is subject to an annual aggregate limit on liability of $75,000,000. The policies are subject to deductibles and other conditions. Deductibles for events that are not U.S. Gulf of Mexico named windstorm events are $1,500,000 per occurrence for drilling rigs, and range from $250,000 to $1,000,000 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 are $1,500,000 per rig for each occurrence plus an additional $5,000,000 for each U.S. Gulf of Mexico named windstorm. The protection and indemnity coverage under the primary marine package has a $5,000,000 limit per occurrence with excess liability coverage up to $100,000,000. 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 domestic liability, employer’s liability, domestic auto liability and non-owned aircraft liability, with customary deductibles and coverage.

NOTE 9 – SUBSEQUENT EVENTS

In April 2007, the Company repaid outstanding debt (see NOTE 5).

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 March 31, 2007 and for the three months ended March 31, 2007, 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.

•

Contract Drilling Services. We own a fleet of nine jackup rigs. 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 59 liftboats in our Domestic and International Marine Services segments, and we operate an additional five liftboats owned by a third-party 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 17 liftboats operating offshore West Africa, including five liftboats owned by a third party. 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. Our international drilling contracts and some of our liftboat contracts in West Africa are longer-term in nature. Our other liftboat contracts in West Africa are short-term.

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 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. Rigs that have been cold-stacked typically require 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 the contract. 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. Most of 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

On March 18, 2007 we signed a definitive merger agreement to acquire TODCO for aggregate consideration of approximately 56.9 million shares of our common stock, $0.01 par value (“Company Common Stock”) and approximately $930.0 million in cash. TODCO is a provider of oil and gas services and operates a fleet of 64 drilling rigs, consisting of 27 inland barge rigs, 24 jackup rigs, three submersible rigs, one platform rig and nine land rigs. TODCO also operates through a wholly-owned subsidiary, Delta Towing LLC, a fleet of U.S. marine support vessels consisting primarily of shallow water tugs, crewboats and utility barges along the U.S. Gulf Coast and in the U.S. Gulf of Mexico.

Under the terms of the definitive merger agreement, the total consideration to be paid to TODCO stockholders in connection with the acquisition is fixed. In the acquisition, on average, each issued and outstanding share of TODCO common stock will be converted into the right to receive an amount of consideration equal to (1) 0.979 shares of Company Common Stock, and (2) $16.00 in cash. Stockholders of TODCO will have the right to elect to receive Company Common Stock or cash for each share of TODCO common stock, subject to equalization so that each share of TODCO common stock receives consideration representing equal value and pro-ration in the event either the Company Common Stock election or the cash election is oversubscribed. These adjustments, however, will not increase or decrease the total shares of Company Common Stock or the total amount of cash to be paid by us. We have received a commitment letter for a new syndicated secured term loan of up to $1.1 billion and a $150.0 million revolving credit facility upon the closing of the merger transaction. We intend to finance some or all of the cash portion of the merger consideration under the syndicated secured term loan.

The transaction is expected to be completed mid-year 2007 and is subject to approval by both our and TODCO’s stockholders, to regulatory approvals and to other customary closing conditions.

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 March 31,
	2007			2006
	(Dollars in thousands, except per day amounts)
Domestic Contract Drilling Services Segment:
Number of rigs (as of end of period)		6			6
Operating days		474			382
Available days		540			450
Utilization (1)		87.8	%		84.9	%
Average revenue per rig per day (2)	$	90,363		$	70,673
Average operating expense per rig per day (3)	$	25,117		$	24,682
Revenues	$	42,831		$	26,997
Operating expenses, excluding depreciation and amortization	$	13,563		$	11,107
Depreciation and amortization expense	$	2,561		$	1,652
General and administrative expenses, excluding depreciation and amortization	$	1,942		$	1,786
Operating income	$	24,765		$	12,452
International Contract Drilling Services Segment:
Number of rigs (as of end of period)		3			3
Operating days		180			—
Available days		180			—
Utilization (1)		100.0	%		—
Average revenue per rig per day (2)	$	115,978		$	—
Average operating expense per rig per day (3)	$	41,016		$	—
Revenues	$	20,876		$	—
Operating expenses, excluding depreciation and amortization	$	7,383		$	—
Depreciation and amortization expense	$	1,368		$	—
General and administrative expenses, excluding depreciation and amortization	$	530		$	35
Operating income	$	11,595		$	(35	)
Domestic Marine Services Segment:
Number of liftboats (as of end of period)		47			42
Operating days		2,667			2,850
Available days		4,099			3,458
Utilization (1)		65.1	%		82.4	%
Average revenue per liftboat per day (2)	$	12,262		$	8,981
Average operating expense per liftboat per day (3)	$	3,328		$	2,659
Revenues	$	32,703		$	25,597
Operating expenses, excluding depreciation and amortization	$	13,640		$	9,193
Depreciation and amortization expense	$	6,070		$	3,978
General and administrative expenses, excluding depreciation and amortization	$	538		$	745
Operating income	$	12,455		$	11,681


	Three Months Ended March 31,
	2007			2006
	(Dollars in thousands, except per day amounts)
International Marine Services Segment:
Number of liftboats (as of end of period)		17			4
Operating days		1,162			357
Available days		1,474			360
Utilization (1)		78.8	%		99.0	%
Average revenue per liftboat per day (2)	$	12,095		$	9,913
Average operating expense per liftboat per day (3)	$	4,709		$	4,544
Revenues	$	14,054		$	3,539
Operating expenses, excluding depreciation and amortization	$	6,941		$	1,636
Depreciation and amortization expense	$	1,704		$	279
General and administrative expenses, excluding depreciation and amortization	$	950		$	761
Operating income	$	4,459		$	863
Total Company:
Revenues	$	110,464		$	56,133
Operating expenses, excluding depreciation and amortization	$	41,527		$	21,936
Depreciation and amortization expense	$	11,730		$	5,934
General and administrative expenses, excluding depreciation and amortization	$	9,163		$	6,586
Operating income	$	48,044		$	21,677
Interest expense	$	2,090		$	2,086
Gain on disposal of assets	$	—		$	29,580
Other income	$	1,275		$	303
Income before income taxes	$	47,229		$	49,474
Income tax provision	$	13,838		$	18,562
Net income	$	33,391		$	30,912

(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, which included Rig 26 in the three months ended March 31, 2007, and Rig 16, Rig 21, Rig 26 and Rig 31 in the three months ended March 31, 2006, or cold-stacked units, which included one and three of our liftboats during the three months ended March 31, 2007 and 2006, respectively, are not counted as available days. Days during which our liftboats are in the shipyard undergoing drydocking or inspection are considered available days for the purposes of calculating utilization.

(2)

Average revenue per rig or liftboat per day is defined as revenue earned by our rigs or liftboats, as applicable, in the period divided by the total number of operating days for our rigs or liftboats, as applicable, in the period. Included in International Contract Drilling Services revenue is a total of $1.8 million related to amortization of deferred mobilization revenue and contract specific capital expenditures reimbursed by the customer for the three months ended March 31, 2007. We had no such revenue for the three months ended March 31, 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 $1.2 million related to amortization of deferred mobilization expenses for the three months ended March 31, 2007. We had no such expenses for the three months ended March 31, 2006.

For the Three Months Ended March 31, 2007 and 2006

Revenues

Consolidated. Total revenues for the three-month period ended March 31, 2007 (the “Current Quarter”) were $110.5 million compared with $56.1 million for the three-month period ended March 31, 2006 (the “Comparable Quarter”), an increase of $54.4 million, or 97%. This increase resulted primarily from higher average dayrates in our Domestic Contract Drilling Services and Domestic Marine Services segments, additional operating days in our International Marine Services segment and the commencement of operations in our International Contract Drilling Services segment. Total revenues included $3.2 million in reimbursements from our customers for expenses paid by us in the Current Quarter compared with $1.2 million in the Comparable Quarter.

Domestic Contract Drilling Services Segment. Revenues for our Domestic Contract Drilling Services segment were $42.8 million for the Current Quarter compared with $27.0 million for the Comparable Quarter, an increase of $15.8 million, or 59%. This increase resulted primarily from higher average dayrates for our fleet, which accounted for $7.5 million and additional operating days, which accounted for $8.3 million of the increase. Operating days increased to 474 in the Current Quarter from 382 in the Comparable Quarter as Rig 21 returned to service. Rig 21 operated 90 days during the Current Quarter and did not operate during the Comparable Quarter due to damage sustained during Hurricane Katrina in August 2005. Average revenue per rig per day was $90,363 in the Current Quarter compared with $70,673 in the Comparable Quarter, with average utilization of 87.8% in the Current Quarter compared with 84.9% in the Comparable Quarter. Revenues for our Domestic Contract Drilling Services segment included $0.5 million in reimbursements from our customers for expenses paid by us in the Current Quarter compared with $0.4 million in the Comparable Quarter.

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 $20.9 million for the three months ended March 31, 2007. Average revenue per rig per day was $115,978, operating days were 180 and average utilization was 100.0% in the three months ended March 31, 2007. Included in revenue for the three months ended March 31, 2007 is $1.8 million related to amortization of deferred mobilization revenue and contract specific capital expenditures reimbursed by the customer. Revenues in our International Contract Drilling Services segment include reimbursements from our customers of $0.2 million for expenses paid by us.

Domestic Marine Services Segment. Revenues for our Domestic Marine Services segment were $32.7 million for the Current Quarter compared with $25.6 million in the Comparable Quarter, an increase of $7.1 million, or 28%. This increase resulted primarily from higher average dayrates, which contributed $9.3 million of the increase, partially offset by $2.2 million related to fewer operating days. Operating days in the Current Quarter were 2,667 compared with 2,850 operating days in the Comparable Quarter. Average revenue per liftboat per day was $12,262 in the Current Quarter compared with $8,981 in the Comparable Quarter, with average utilization of 65.1% in the Current Quarter compared with 82.4% in the Comparable Quarter. The increase in average dayrates was attributable primarily to increased demand in the aftermath of Hurricane Katrina and Hurricane Rita. Revenues for our Domestic Marine Services segment included $1.3 million in reimbursements from our customers for expenses paid by us in the Current Quarter compared with $0.8 million in the Comparable Quarter.

International Marine Services Segment. Revenues for our International Marine Services segment were $14.1 million for the Current Quarter compared with $3.5 million in the Comparable Quarter, an increase of $10.6 million, or 303%. This increase is due to acquisition activity by us which resulted in an increase in operating days from 357 days in 2006 to 1,162 days in 2007. Average revenue per liftboat per day was $12,095 in the Current Quarter compared with $9,913 in the Comparable Quarter, with average utilization of 78.8% in the Current Quarter compared with 99.0% in the Comparable Quarter. Revenues for our International Marine Services segment included $1.2 million in reimbursements from our customers for expenses paid by us in the Current Quarter. There was no reimbursable income in our International Marine Services segment in the Comparable Quarter.

Operating Expenses

Consolidated. Total operating expenses, excluding depreciation and amortization, for the Current Quarter were $41.5 million compared with $21.9 million in the Comparable Quarter, an increase of $19.6 million, or 89%. 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 $13.6 million in the Current Quarter compared with $11.1 million in the Comparable Quarter, an increase of $2.5 million, or 23%. Available days increased to 540 in the Current Quarter from 450 in the Comparable Quarter. Average operating expenses per rig per day were $25,117 in the Current Quarter compared with $24,682 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 $435. The increase resulted primarily from an increase in insurance costs, which increased $3,987 per day, partially offset by decreases in labor expenses, which decreased $1,706 per day, a decrease in rig maintenance costs, which decreased $542 per day, and a decrease in other rig costs, which decreased $1,304 per day.

International Contract Drilling Services Segment. Operating expenses, excluding depreciation and amortization, for our International Contract Drilling Services segment were $7.4 million for the three months ended March 31, 2007, and averaged $41,016 per rig per day. Included in operating expense is $1.2 million related to amortization of deferred mobilization expense. Prior to the second quarter of 2006 we did not have an International Contract Drilling Services Segment.

Domestic Marine Services Segment. Operating expenses, excluding depreciation and amortization, for our Domestic Marine Services segment were $13.6 million for the Current Quarter compared with $9.2 million in the Comparable Quarter, an increase of $4.4 million, or 48%. The increase is due primarily to liftboat acquisitions and additional operating days. Average operating expenses per liftboat per day were $3,328 in the Current Quarter compared with $2,659 in the Comparable Quarter. This increase resulted primarily from an increase in labor expenses, which increased $375 per day, and an increase in insurance costs, which increased $165 per day.

International Marine Services Segment. Operating expenses, excluding depreciation and amortization, for our International Marine Services segment were $6.9 million for the Current Quarter compared with $1.6 million in the Comparable Quarter, an increase of $5.3 million, or 331%. The increase is due to the additional liftboats acquired in the fourth quarter of 2006. Average operating expenses per liftboat per day were $4,709 in the Current Quarter compared with $4,544 in the Comparable Quarter.

Depreciation and Amortization

Depreciation and amortization expense in the Current Quarter was $11.7 million compared with $5.9 million in the Comparable Quarter, an increase of $5.8 million, or 98%. This increase resulted primarily from an additional $0.9 million in depreciation expense for our Domestic Contract Drilling Services segment, $0.8 million for our Domestic Marine Services segment, $1.4 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 $1.8 million.

General and Administrative Expenses

General and administrative expenses, excluding depreciation and amortization, in the Current Quarter were $9.2 million compared with $6.6 million in the Comparable Quarter, an increase of $2.6 million, or 39%. 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 $5.2 million in the Current Quarter from $3.3 million in the Comparable Quarter, an increase of $1.9 million. This increase is due to increased headcount, additional stock-based compensation expense of $0.4 million and higher professional fees. General and administrative expenses increased $0.2 million in our Domestic Contract Drilling Services and International Marine Services segments from the Comparable Quarter to the Current Quarter and decreased $0.2 million in our Domestic Marine Services segment. General and administrative expense for our International Contract Drilling Services segment in the Current Quarter was $0.5 million, which represent expenses associated with our operations in Qatar and India that commenced in the second quarter of 2006.

Gain on Disposal of Asset

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

Other Income

Other income in the Current Quarter was $1.3 million compared with $0.3 million in the Comparable Quarter, an increase of $1.0 million. This increase is due to higher cash balances resulting in increased interest income.

Income Tax Provision

Income tax expense was $13.8 million on pre-tax income of $47.2 million during the Current Quarter, compared to $18.6 million on pre-tax income of $49.5 million for the Comparable Quarter. The effective tax rate decreased to 29.3% in the Current Quarter from 37.5% in Comparable Quarter. This decrease is due to additional earnings in 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 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. Spot natural gas prices are extremely volatile and have ranged from a high of $9.14 per mmbtu to a low of $5.40 per mmbtu during the first quarter. As of April 19, 2007, the spot price for Henry Hub natural gas was $7.54 per mmbtu and the twelve month strip, or the average of the next twelve month’s futures contract was $8.50 per mmbtu. Oil prices have remained at high levels relative to historic prices for the past several years with the spot price for West Texas intermediate crude ranging from $66.03 to $50.48 per bbl during the first quarter of 2007. As of April

19, 2007, the price of WTI was $61.83 with a twelve month strip of $66.52. 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 156 jackups in 2001 to only 87 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 Gulf of Mexico is currently approximately 67. 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 58 in April 2007 from 87 in April 2006. A combination of factors since mid-2006, including record high natural gas storage during late 2006 and extreme volatility in gas prices have caused this reduction in demand and 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 April 6, 2007, 66 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, but may indirectly impact us through competition in other markets. Our ability to expand our international drilling fleet may be limited, however, by the increased supply of newbuild rigs. In addition, nine idle jackups in the U.S. Gulf of Mexico owned by our competitors are cold stacked. We believe that these idle jackup rigs will require extensive capital expenditures to refurbish and bring back into service, but our competitors may opt to reactivate these rigs.

As a result of the extensive damage caused by Hurricanes Rita and Katrina, insurance underwriters sustained significant losses on claims and in 2006 significantly increased the cost of premiums for assets operating in the U.S. Gulf of Mexico and significantly reduced the amount of coverage offered for named windstorm damage. Most companies with insurance policies covering assets in the U.S. Gulf of Mexico have an aggregate limit for what they can recover for assets damaged during named windstorms, which typically is much lower than the total insured value of those assets, as is the case with our insurance coverages. As long as these limits exist, we do not anticipate that newly constructed jackups will be moved to the Gulf of Mexico during hurricane season, which runs from June to November.

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

Because of the significant damage to production platforms, pipelines and other equipment in the U.S. Gulf of Mexico caused by Hurricanes Katrina and Rita, demand for our domestic liftboats for inspection and repair work has been very strong over the last two years, with steadily increasing dayrates for most of this period. While some of our liftboats are continuing to perform hurricane repair work, the mix of well intervention and construction and maintenance work has returned to more normal levels. As a result, we believe our utilization will follow more typical seasonal patterns during 2007 with lower utilization during the winter months.

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 April 20, 2007, we believe that there were 15 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. 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. Generally, we believe demand for liftboats in international locations will be driven by the maintenance of this aging offshore infrastructure in certain areas and by the installation of new infrastructure in other areas, which will be influenced by oil and natural gas prices and 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. 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.

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 three-month periods ended March 31, 2007 and 2006 are as follows:


	Three Months Ended March 31,
	2007			2006
	(dollars in millions)
Net cash provided by operating activities
Net income	$	33.4		$	30.9
Depreciation and amortization		11.7			5.9
Increase in accounts payable and other current liabilities		4.4			6.7
Decrease in insurance note payable		(6.1	)		(1.8	)
Deferred income tax provision		3.3			13.1
Stock-based compensation		1.2			0.7
Excess tax benefit from stock-based payment arrangements		(0.7	)		—
Gain on disposal of assets		(0.3	)		(29.6	)
(Increase) decrease in accounts receivable, insurance claims receivable and other current assets		5.7			(8.9	)

Total	$	52.6		$	17.0

Net cash used in investing activities
Investment in marketable securities	$	(34.0	)	$	—
Acquisition of Rig 26		—			(20.1	)
Refurbishment and upgrade of Rig 16		—			(5.1	)
Refurbishment and upgrade of Rig 31		—			(3.4	)
Refurbishment and upgrade of Rig 26		(10.5	)		(3.1	)
Other rig refurbishments		(1.4	)		(8.4	)
Refurbishments of liftboats		(0.4	)		(1.9	)
Deferred drydocking expenditures for liftboats		(5.5	)		(2.7	)
Proceeds from sale of assets		0.6			—
Other		(1.4	)		(0.7	)

Total	$	(52.6	)	$	(45.4	)

Net cash provided by (used in) financing activities
Payment of debt	$	(0.4	)		(0.4	)
Excess tax benefit from stock-based payment arrangements		0.7			—
Proceeds from exercise of stock options		1.0			—
Distributions to members		—			(3.7	)
Payment of debt issuance costs		—			(0.2	)

Total	$	1.3		$	(4.3	)

Sources of Liquidity and Financing Arrangements

Excluding the effect of the announced acquisition of TODCO, we believe that our current cash on hand and our cash flow from operations through December 31, 2007, together with availability under our revolving credit facility, will be adequate during such period to repay our debts as they become due, to make normal recurring capital additions and improvements, to meet working capital requirements, to complete the refurbishment and upgrade of Rig 26 and otherwise to operate our business. In connection with the acquisition of TODCO, we will issue Company Common Stock and will borrow up to $1.1 billion under a new senior secured term loan or other debt offering. Additionally, upon closing of the acquisition we will terminate our current credit facility and enter into a new $150.0 million revolving credit facility.

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 additional 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.

Debt

Our current debt structure is used to fund our business operations, and our $75.0 million revolving credit facility is a source of liquidity. As of March 31, 2007, $92.9 million of the principal amount of the term loan was outstanding, and the interest rate was 8.61%. No amounts were outstanding and no letters of credit had been issued under the revolving credit facility.

In April 2007, we repaid $37.0 million of the outstanding amount under the term loan, together with accrued and unpaid interest. Additionally, we cancelled an interest rate swap on $35.0 million of the term loan principal.

Capital Expenditures

We expect to spend approximately $16.9 million in 2007 on the refurbishment and upgrade of our rigs and liftboats, excluding amounts allocated to Rig 26. Cost 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. We expect to spend approximately $22.8 million in 2007 to complete the upgrade of Rig 26. 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 table below sets forth information with respect to certain of our capital expenditure projects for 2006 and the first three months of 2007, estimated amounts for the remainder of 2007 and total estimated amounts for the project.


(in millions)	2006 Expenditures		Expenditures – Three Months Ended Mar. 31, 2007		Estimated Remaining Expenditures		Total Expenditures or Estimated Expenditures		Completion or Expected Completion
Rig 16 refurbishment and upgrade	$	10.3	$	—	$	—	$	16.0	Second Quarter 2006
Rig 31 refurbishment and upgrade		22.9		—		—		25.8	Third Quarter 2006
Rig 26 refurbishment and upgrade		27.3		10.5		12.3		50.1	Third Quarter 2007
Drydockings of liftboats		12.5		5.5		14.1		Ongoing	Ongoing

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 — Sources of 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. Except with respect to our merger agreement with TODCO as described under “Recent Developments,” there have been no material changes to such disclosure regarding our contractual obligations made in our annual report.

Accounting Pronouncements

FIN 48 also requires expanded disclosure with respect to the uncertainty in income tax assets and liabilities. FIN 48 is effective for fiscal years beginning after December 15, 2006. The effect of adoption of FIN 48 is required to be recognized as a change in accounting principle through a cumulative-effect adjustment to retained earnings as of the beginning of the year of adoption. We have 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. Currently do not anticipate a significant increase in unrecognized tax benefits during the next 12 months.

FIN 48 requires that interest expense and penalties related to unrecognized tax benefits be recognized in a company’s 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.

We and our subsidiaries files income tax returns in the United States, and various state and foreign jurisdictions. Our tax returns for 2004 and 2005 remain open for examination by the taxing authorities in the respective jurisdictions where those returns were filed.

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 in 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.

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 activities, events or developments that we expect, project, believe or anticipate will or may occur in the future are forward-looking statements. These include such matters as:

•

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

•

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

•

future capital expenditures and refurbishment, repair and upgrade costs;

•

expected completion times for our refurbishment and upgrade projects;

•

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

•

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

•

our plans regarding increased international operations;

•

expected useful lives of our rigs and liftboats;

•

liabilities under laws and regulations protecting the environment;

•

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

•

expectations regarding improvements in offshore drilling activity and dayrates, continuation of current market conditions, demand for our rigs and liftboats, operating revenues, operating and maintenance expense, insurance expense and deductibles, interest expense, debt levels and other matters with regard to outlook and such expectations related to TODCO’s business; and

•

other expectations regarding TODCO and our proposed merger with TODCO, including the timing of and conditions to the proposed merger.

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:

•

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

•

demand for offshore jackup rigs and liftboats;

•

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

•

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

•

the impact of governmental laws and regulations;

•

the adequacy of sources of liquidity;

•

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

•

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

•

the availability of skilled personnel;

•

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

•

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

•

the effect of litigation and contingencies; and

•

our inability to achieve our plans or carry out our strategy including our plans and strategies related to the proposed 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 — Sources of 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 Chief Executive Officer and President, and Lisa W. Rodriguez, our 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 March 31, 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

On March 19 and 20, 2007, two stockholder lawsuits were filed in the District Court of Harris County, Texas, both alleging that the board of directors of TODCO breached their fiduciary duties in approving the proposed acquisition of TODCO by Hercules Offshore, Inc. (the “Company”). The first suit, pending in the 333rd Judicial District Court of Harris County, Texas, Cause No. 2007-16397, is a purported stockholder class action suit against the TODCO directors, and contains claims for breach of fiduciary duty. The second suit, pending in the 269th Judicial District Court of Harris County, Texas, Cause No. 2007-16357, is a stockholder derivative action purportedly filed on behalf of TODCO against the TODCO directors and the Company, 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 complaints allege, among other things, that the TODCO directors engaged in self-dealing in approving the proposed acquisition by the Company by advancing their own personal interests or those of TODCO’s senior management at the expense of the stockholders of TODCO, utilized a defective sales process not designed to maximize 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 suit also alleges that the Company conspired, aided and abetted or assisted in these violations.

ITEM 1A.

RISK FACTORS

Except as disclosed below, 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:

Our proposed merger with TODCO involves risks, including the risk that the merger will be delayed or will not be completed, and risks related to the costs of the merger and debt we expect to incur to fund the cash consideration in the merger.

Risks with respect to the proposed merger of the Company and TODCO include the risk that the Company and TODCO will not be able to close the transaction, as well as difficulties in the integration of the operations and personnel of TODCO and diversion of management’s attention away from other business concerns. The Company expects to incur substantial transaction and merger related costs associated with completing the merger, obtaining regulatory approvals, combining the operations of the two companies and achieving desired synergies. Additional unanticipated costs may be incurred in the integration of the businesses of the Company and TODCO. Expected benefits of the merger may not be achieved in the near term, or at all. The Company will have a significant amount of additional debt as a result of the merger. This debt will require the Company to use cash flow to repay indebtedness, may have a material adverse effect on the Company’s financial health, and may limit the Company’s future operations and ability to borrow additional funds.

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 the Plan (2)
January 1 – 31, 2007	—		—	N/A	N/A
February 1 – 28, 2007	879	$	26.16	N/A	N/A
March 1 – 31, 2007	—		—	N/A	N/A

Total	879	$	26.16	N/A	N/A

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

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

ITEM 6.

EXHIBITS



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 Annex A to the joint proxy statement/prospectus in Part I of Hercules’ Registration Statement on Form S-4 (Reg. No. 333-142314)).

10.1		Commitment letter with UBS.

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.

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: April 30, 2007

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