Edgar Filing: HERCULES OFFSHORE, INC.

Form 10-Q for quarterly period ended September 30, 2006

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 September 30, 2006

¨	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 ¨ Accelerated filer ¨ Non-accelerated filer x

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 November 1, 2006
Common Stock, par value $0.01 per share		31,993,866

HERCULES OFFSHORE, INC.

INDEX


		Page No.
PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements

	Consolidated Balance Sheets as of September 30, 2006 and December 31, 2005 (unaudited)	2
	Consolidated Statements of Operations for the three months ended September 30, 2006 and September 30, 2005 (unaudited)	3
	Consolidated Statements of Operations for the nine months ended September 30, 2006 and September 30, 2005 (unaudited)	4
	Consolidated Statements of Cash Flows for the nine months ended September 30, 2006 and September 30, 2005 (unaudited)	5
	Consolidated Statement of Stockholders’ Equity for the nine months ended September 30, 2006 (unaudited)	6
	Consolidated Statements of Comprehensive Income for the three months ended September 30, 2006 and September 30, 2005 and the nine months ended September 30, 2006 and September 30, 2005 (unaudited)	7
	Notes to Unaudited Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	39

Item 4.	Controls and Procedures	39

PART II.	OTHER INFORMATION

Item 1A.	Risk Factors	39

Item 6.	Exhibits	40

	Signatures	41

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except par value)

(Unaudited)


	September 30, 2006		December 31, 2005
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	84,966	$	47,575
Restricted cash		250		—
Accounts receivable, net		66,876		38,484
Deposits		309		33
Assets held for sale		—		2,040
Insurance claims receivable		12,186		5,919
Prepaid expenses and other		28,564		6,160

Total current assets		193,151		100,211
PROPERTY AND EQUIPMENT, net		354,794		247,443
OTHER ASSETS, net		8,750		7,171

Total assets	$	556,695	$	354,825

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Current portion of long-term debt	$	1,400	$	1,400
Insurance note payable		12,030		2,401
Accounts payable		29,701		13,281
Accrued liabilities		13,147		11,165
Taxes payable		1,075		122
Interest payable		2,120		1,759
Other current liabilities		4,558		—

Total current liabilities		64,031		30,128
LONG-TERM DEBT, net of current portion		92,200		93,250
DEFERRED INCOME TAXES		43,331		15,504
OTHER LIABILITIES		526		—
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS’ EQUITY
Common stock, par value $0.01 per share; 200,000 shares authorized; 31,893 and 30,243 shares issued and outstanding		319		302
Additional paid-in capital		240,174		184,698
Restricted stock (unearned compensation)		—		(1,322	)
Accumulated other comprehensive income		801		476
Retained earnings		115,313		31,789

Total stockholders’ equity		356,607		215,943

Total liabilities and stockholders’ equity	$	556,695	$	354,825

The accompanying notes are an integral part of these statements.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except share data)

(Unaudited)


	Three Months Ended September 30,
	2006			2005
REVENUES
Contract drilling services	$	54,298		$	28,248
Marine services		42,914			13,937

		97,212			42,185
COSTS AND EXPENSES
Operating expenses for contract drilling services, excluding depreciation and amortization		18,327			14,043
Operating expenses for marine services, excluding depreciation and amortization		14,870			7,757
Depreciation and amortization		9,097			3,753
General and administrative, excluding depreciation and amortization		7,209			4,031

		49,503			29,584

OPERATING INCOME		47,709			12,601
OTHER INCOME (EXPENSE)
Interest expense		(2,575	)		(2,735	)
Gain on disposal of assets		1,110			—
Other, net		874			244

INCOME BEFORE INCOME TAXES		47,118			10,110
INCOME TAX PROVISION
Current income tax		(7,166	)		—
Deferred income tax		(10,273	)		—

NET INCOME	$	29,679		$	10,110

EARNINGS PER SHARE (SEE NOTE 2):
Basic	$	0.93		$	0.42
Diluted	$	0.90		$	0.41
WEIGHTED AVERAGE SHARES OUTSTANDING (SEE NOTE 2):
Basic		31,884,566			23,922,850
Diluted		33,069,992			24,630,628

The accompanying notes are an integral part of these statements.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except share data)

(Unaudited)


	Nine Months Ended September 30,
	2006			2005
REVENUES
Contract drilling services	$	123,862		$	79,427
Marine services		105,780			33,888

		229,642			113,315
COSTS AND EXPENSES
Operating expenses for contract drilling services, excluding depreciation and amortization		43,256			37,379
Operating expenses for marine services, excluding depreciation and amortization		38,137			18,184
Depreciation and amortization		22,582			9,075
General and administrative, excluding depreciation and amortization		20,396			9,136

		124,371			73,774

OPERATING INCOME		105,271			39,541
OTHER INCOME (EXPENSE)
Interest expense		(6,824	)		(7,572	)
Gain on disposal of assets Loss on early retirement of debt		30,690 —			— (2,786	)
Other, net		2,697			479

INCOME BEFORE INCOME TAXES		131,834			29,662
INCOME TAX PROVISION
Current income tax		(20,658	)		—
Deferred income tax		(27,652	)		—

NET INCOME	$	83,524		$	29,662

EARNINGS PER SHARE (SEE NOTE 2):
Basic	$	2.67		$	1.24
Diluted	$	2.57		$	1.22
WEIGHTED AVERAGE SHARES OUTSTANDING (SEE NOTE 2):
Basic		31,234,533			23,855,353
Diluted		32,440,950			24,324,935

The accompanying notes are an integral part of these statements.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Nine Months Ended September 30,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	83,524		$	29,662
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization		22,582			9,075
Stock based compensation expense		2,277			—
Deferred income taxes		27,652			—
Amortization of deferred financing fees		506			714
Provision for bad debts		160			(519	)
Loss on early retirement of debt Gain on disposal of assets		— (30,690	)		2,786 —
Gain on sale of assets		(89	)		—
(Increase) decrease in operating assets—
Increase in accounts receivable		(28,552	)		(15,293	)
Increase in insurance claims receivable		(7,913	)		(193	)
Increase in prepaid expenses and other		(23,397	)		(4,147	)
Increase (decrease) in operating liabilities—
Increase in accounts payable		16,420			4,783
Increase in insurance note payable		9,629			4,175
Increase in other current liabilities		12,335			6,667
Increase in other liabilities		526			—

Net cash provided by operating activities		84,970			37,710
CASH FLOWS FROM INVESTING ACTIVITIES
Purchase of property and equipment		(143,282	)		(115,571	)
Deferred drydocking expenditures		(8,967	)		(4,617	)
Insurance proceeds received		50,090			—
Proceeds from sale of assets, net of commissions		5,989			454
Increase in restricted cash		(250	)		—
Decrease (increase) in deposits		(276	)		1,999

Net cash used in investing activities		(96,696	)		(117,735	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings		—			185,000
Payment of debt		(1,050	)		(101,000	)
Proceeds from issuance of common stock		54,198			—
Proceeds from exercise of stock options		340			—
Payment of debt issuance costs		(639	)		(6,008	)
(Distributions to) contributions from members		(3,732	)		4,329

Net cash provided by financing activities		49,117			82,321

NET INCREASE IN CASH AND CASH EQUIVALENTS		37,391			2,296

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		47,575			14,460

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	84,966		$	16,756

The accompanying notes are an integral part of these statements.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(In thousands)


	Common Stock			Additional Paid-In Capital			Restricted Stock			Accumulated Other Comprehensive Income		Retained Earnings		Total Equity
	Shares	Amount		Additional Paid-In Capital			Restricted Stock			Accumulated Other Comprehensive Income		Retained Earnings		Total Equity
Balance at December 31, 2005	30,243	$	302	$	184,698		$	(1,322	)	$	476	$	31,789	$	215,943
Issuance of common stock, net	1,600		16		54,182			—			—		—		54,198
Issuance of restricted stock	33		—		—			—			—		—		—
Exercise of stock options	17		1		339			—			—		—		340
Reclass restricted stock	—		—		(1,322	)		1,322			—		—		—
Compensation expense recognized	—		—		2,277			—			—		—		2,277
Change in unrealized gain on hedge transaction	—		—		—			—			325		—		325
Net income	—		—		—			—			—		83,524		83,524

Balance at September 30, 2006	31,893	$	319	$	240,174		$	—		$	801	$	115,313	$	356,607

The accompanying notes are an integral part of these statements.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)

(Unaudited)


	Three Months Ended September 30,
	2006			2005
NET INCOME	$	29,679		$	10,110

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Unrealized gains (losses) on hedge transactions		(473	)		322

COMPREHENSIVE INCOME	$	29,206		$	10,432


	Nine Months Ended September 30,
	2006			2005
NET INCOME	$	83,524		$	29,662

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Unrealized gains on hedge transactions		325			322

COMPREHENSIVE INCOME	$	83,849		$	29,984

The accompanying notes are an integral part of these 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 51 liftboat vessels.

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 September 30, 2006, the results of its operations for the three months and nine months ended September 30, 2006 and September 30, 2005 and its cash flows for the nine months ended September 30, 2006 and September 30, 2005 have been reflected. The consolidated results of operations for the three months and nine months ended September 30, 2006 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 for the year ended December 31, 2005.

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.

Revenue Recognition

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 deferred $4,180,000 and $5,680,000 of revenue related to the mobilization of rigs under long term contracts for the three and nine months ended September 30, 2006, respectively. The Company deferred $4,199,659 and $4,428,026 of expenses related to the mobilization of rigs under long term contracts for the three and nine months ended September 30, 2006, respectively. The Company recognized $710,000 and $835,000 of revenue related to mobilization in the three and nine months ended September 30, 2006, respectively. The Company recognized $552,918 and $571,949 of expense related to mobilization in the three and nine months ended September 30, 2006, respectively.

For certain Contract Drilling Services contracts, the Company may receive fees from its customers for capital improvements to its rigs. Such fees are deferred and recognized over the term of the related drilling contract. The Company capitalizes such capital improvements and depreciates them over the useful life of the asset. The Company deferred $251,277 of revenue related to such fees in the three months and nine months ended September 30, 2006. The Company recognized $12,564 of revenue related to such fees in the three months and nine months ended September 30, 2006.

The Company records reimbursements from customers for “out-of-pocket” expenses as revenues and the related cost as direct operating expenses. Total revenues from such reimbursements were $1,790,844 and $1,371,656 for the three months ended September 30, 2006 and September 30, 2005, respectively, and $4,264,888 and $3,698,578 for the nine months ended September 30, 2006 and September 30, 2005, respectively.

Stock Offering

The Company completed a public offering of 9,200,000 shares of its common stock at $36.00 per share in April 2006. The Company issued 1,600,000 shares of common stock, while the remaining 7,600,000 shares were sold by certain selling stockholders. The Company received approximately $54.2 million of proceeds from the offering, net of underwriter discounts and commissions and estimated expenses.

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. On April 26, 2006, the Company’s stockholders approved an increase in the shares available for grant or award under the 2004 Plan by 1,000,000 shares. At September 30, 2006, 1,507,734 shares were available for grant or award under the 2004 Plan. The Nominating, Governance and Compensation Committee of the Company’s Board of Directors selects participants from time to time and, subject to the terms and conditions of the 2004 Plan, determines all terms and conditions of awards. Options granted prior to the Company’s initial public offering on November 1, 2005 became fully vested at that date. Options issued at the time of and after the Company’s initial public offering under the 2004 Plan have a 10-year term and vest in four equal installments, one-fourth on the effective date of grant and one-fourth thereafter on the anniversary of the grant date for the next three years.

The Company is estimating that the cost relating to stock options granted through September 30, 2006 will be $4,402,617 over the remaining vesting period of 25 months; however, due to the uncertainty of the level of share-based payments to be granted in the future, these amounts are estimates and subject to change.

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


	Three Months Ended September 30, 2006				Three Months Ended September 30, 2005
	Number of Shares Underlying Options		Weighted Average Exercise Price		Number of Shares Underlying Options	Weighted Average Exercise Price
Outstanding at beginning of period	1,822,875		$	11.49	945,000	$	3.23
Granted	—			—	—		—
Exercised	(6,000	)		20.00	—		—
Forfeited	—			—	—		—

Outstanding at end of period	1,816,875		$	11.28	945,000	$	3.23

Exercisable at end of period	1,151,625		$	6.24	—	$	—


	Nine Months Ended September 30, 2006				Nine Months Ended September 30, 2005
	Number of Shares Underlying Options		Weighted Average Exercise Price		Number of Shares Underlying Options	Weighted Average Exercise Price
Outstanding at beginning of year	1,839,500		$	11.38	—	$	—
Granted	—			—	945,000		3.23
Exercised	(17,000	)		20.00	—		—
Forfeited	(5,625	)		20.00	—		—

Outstanding at end of period	1,816,875		$	11.28	945,000	$	3.23

Exercisable at end of period	1,151,625		$	6.24	—	$	—

The following table summarizes information about stock options outstanding at September 30, 2006:


	Options Outstanding				Options Exercisable
Exercise Prices	Number Outstanding	Weighted Average Remaining Life (Years)	Weighted Average Exercise Price		Number Exercisable	Weighted Average Exercise Price
$ 2.86	822,500	8.08	$	2.86	822,500	$	2.86
5.71	122,500	8.58		5.71	122,500		5.71
20.00	871,875	9.08		20.00	206,625		20.00

	1,816,875	8.60	$	11.28	1,151,625	$	6.24

The following table reflects the impact of adopting SFAS No. 123R (dollars in thousands except per share data):


	Three Months Ended September 30, 2006			Nine Months Ended September 30, 2006
Compensation expense related to stock options, net of tax of $184 and $555, respectively	$	344		$	1,030
Basic earnings per share impact	$	(0.01	)	$	(0.03	)
Diluted earnings per share impact	$	(0.01	)	$	(0.03	)
Cash flow from operating activities impact	$	528		$	1,585
Cash flow from financing activities impact	$	120		$	340

The fair value of the options granted under the 2004 Plan at the time of and after the Company’s initial public offering was estimated on the date of grant using the Trinomial Lattice option pricing model with the following assumptions used:


Dividend yield		—
Expected price volatility		35.00	%
Risk-free interest rate		4.40	%
Expected life of options in years		8.08
Weighted-average fair value of options granted	$	9.45

The following table summarizes information about restricted stock outstanding as of September 30, 2006 (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 September 30, 2006		Nine Months Ended September 30, 2006		Three Months Ended September 30, 2006		Nine Months Ended September 30, 2006
October 2005	Employee	70,000	$	20.00	3	$	117	$	350	$	76	$	227
February 2006	Employee	9,900		30.38	3		25		67		16		43
April 2006	Non-employee director	12,000		40.00	1		120		240		78		156
May 2006	Employee	5,000		34.03	3		15		24		10		16
August 2006	Non-employee director	866		32.70	0.67		7		7		5		5
September 2006	Employee	5,000		33.36	3		4		4		3		3

						$	288	$	692	$	188	$	450

Insurance Claims Receivable

Insurance claims receivable include expenses the Company has incurred and other amounts related to damage suffered in Hurricanes Katrina and Rita that the Company expects to be covered by insurance. The expenses incurred include costs to repair damage sustained by Rig 21, costs related to the clean-up efforts at the Company’s New Iberia facilities and the salvage costs for Rig 25. At September 30, 2006, $12,182,717 was outstanding for insurance claims receivable related to Hurricane Katrina, including $3,858,409 for the salvage effort on Rig 25 and $8,324,308 for the damage sustained by Rig 21. At December 31, 2005, $5,919,308 was outstanding for insurance claims receivable related to Hurricanes Katrina and Rita.

Assets Held for Sale

Assets are classified as held for sale when the Company has a plan for disposal and those assets meet the held for sale criteria of SFAS No. 144, “Accounting for Impairment or Disposal of Long-Lived Assets”. In June 2006, the Company entered into a definitive agreement to sell Rig 41 for $3,150,000, net of commissions. The buyer paid a $340,000 non-refundable deposit, and the transaction closed in July 2006. The Company recognized a gain of approximately $1,110,000 in the third quarter of 2006 on the sale for the excess of the purchase price over the rig’s carrying value.

In June 2006, the Company entered into a definitive agreement to sell its New Iberia facility for $2,850,000, net of commissions. The buyer paid a $100,000 deposit, and the transaction closed in September 2006. The Company recognized a gain of approximately $88,300 in the third quarter of 2006 on the sale for the excess of the purchase price over the facility’s carrying value.

Other Assets

Other assets consist of drydocking costs for liftboats, financing fees, unrealized gain on hedge transactions and other. The 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 September 30, 2006 and December 31, 2005 were $4,730,327 and $3,906,106, respectively. Accumulated amortization of drydocking costs at September 30, 2006 and December 31, 2005 was $4,319,042 and $2,967,062, respectively. Amortization expense for drydocking costs was $2,834,168 and $1,148,595 for the three months ended September 30, 2006 and September 30, 2005, respectively. Amortization expense for drydocking costs was $8,142,930 and $2,142,795 for the nine months ended September 30, 2006 and September 30, 2005, respectively.

Financing fees are deferred and amortized over the life of the applicable debt instrument. Unamortized deferred financing fees at September 30, 2006 were $2,665,957, net of accumulated amortization of $904,712. Unamortized deferred financing fees at December 31, 2005 were $2,531,966, net of accumulated amortization of $398,806. The

amortization expense related to the deferred financing fees is included in interest expense on the statement of operations. Amortization expense for financing fees was $179,387 and $222,030 for the three months ended September 30, 2006 and September 30, 2005, respectively. Amortization expense for financing fees was $505,906 and $714,071 for the nine months ended September 30, 2006 and September 30, 2005, respectively. Deferred financing fees of $7,674 and $639,896 were paid in the three and nine months ended September 30, 2006, respectively. Deferred financing fees of $372,405 and $6,008,036 were paid in the three and nine months ended September 30, 2005, respectively. Unamortized deferred financing fees at December 31, 2005 and September 30, 2006 relate to the debt outstanding at those dates (see NOTE 5).

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 (see NOTE 6).

Income Taxes

The Company was a limited liability company until its conversion to a Delaware corporation on November 1, 2005. Prior to the Conversion, the Company elected to be taxed as a partnership. As such, the members of the Company were taxed on their proportionate share of net income prior to the Conversion and no provision or liability for income taxes was included in the Company’s financial statements for periods prior to the Conversion. When the Company became a taxable entity in the Conversion, a provision of approximately $12,145,040 was made reflecting the tax effect of the difference between the book and tax basis of assets and liabilities as of November 1, 2005, the effective date of the Conversion.

The Company’s net income tax expense or benefit is determined based on the mix of domestic and international pre-tax earnings or losses, respectively, as well as the tax jurisdictions in which the Company operates. Certain of the Company’s international rigs are owned or operated, directly or indirectly, by the Company’s wholly owned Cayman Islands subsidiaries. Earnings from these subsidiaries are reinvested internationally and remittance to the U.S. is indefinitely postponed. Consequently, no U.S. tax expense or benefits were recognized on these earnings or losses in 2006.

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.

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 is effective for fiscal years beginning after December 15, 2006 and the Company intends to adopt FIN 48 in the first quarter of 2007. The Company is evaluating FIN 48 and has not yet determined the impact on its consolidated balance sheet, statement of operations or statement of cash flow.

interim periods of the first fiscal year beginning after November 15, 2006, and the Company intends to apply SAB 108 in connection with the preparation of its annual financial statements for the year ended December 31, 2006. The Company is evaluating the requirements of SAB 108 and it will have no effect on its consolidated balance sheet, statement of operations or statement of cash flow.

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 (net income in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2006		2005		2006		2005
Numerator:
Net income	$	29,679	$	10,110	$	83,524	$	29,662

Denominator:
Weighted average basic shares		31,884,566		23,922,850		31,234,533		23,855,353
Add effect of stock options		1,185,426		707,778		1,206,417		469,582

Weighted average diluted shares		33,069,992		24,630,628		32,440,950		24,324,935

Basic earnings per share	$	0.93	$	0.42	$	2.67	$	1.24
Diluted earnings per share	$	0.90	$	0.41	$	2.57	$	1.22

The Company calculates earnings per share by dividing net income by the weighted average number of shares outstanding. On November 1, 2005, in connection with its initial public offering, the Company converted from a limited liability company to a corporation. Upon the Conversion, each outstanding membership unit of the limited liability company was converted into 350 shares of common stock of the corporation. Share-based information contained herein assumes that the Company had effected the conversion of each outstanding member unit into 350 shares of common stock for all periods prior to the Conversion. 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 – ASSET ACQUISITIONS

In February 2006, the Company purchased Rig 26 for $20,100,000. Rig 26 had been cold stacked for the prior six years. The Company has commenced a reactivation and upgrade project that it expects will take up to one year and cost approximately $40,100,000. In June 2006, the Company increased its planned expenditures on the project to enhance the rig’s drilling capabilities and to increase the marketability of the rig in international regions. Upon completion of the project in 2007, the Company plans to deploy the rig in a suitable international market.

In June 2006, the Company acquired five liftboats from Laborde Marine Lifts, Inc. (“Laborde”). In addition, the Company assumed the construction of an additional liftboat pursuant to a construction agreement assigned to the Company by Laborde at the closing. Pursuant to the terms of the purchase agreement, the original purchase price of $52,000,000 was reduced by $2,655,830, which represented the total amount remaining due at closing under the construction contract for the sixth liftboat. Construction of the additional liftboat was completed in July 2006 and the remaining amount due was paid to the shipyard.

On November 7, 2006, the Company completed its previously announced transaction with Halliburton West Africa Limited and Halliburton Energy Services Nigeria Limited (collectively, “Halliburton”). In the transaction, the Company: (i) purchased eight liftboats owned by Halliburton, (ii) assumed Halliburton’s rights to operate five additional liftboats under an arrangement with the third-party vessel owner, (iii) assumed the lease of a 1.25 hectare shore-based facility located in Warri, Nigeria that includes warehouse space, offices and a machine shop, and (iv) assumed Halliburton’s rights and obligations under certain customer contracts and other agreements related to Halliburton’s liftboat operations in West Africa. The purchase price for the acquisition was $50,000,000, subject to adjustment, plus any amounts payable under the three-year earnout agreement described below. The Company operates the five liftboats owned by the third party under a management agreement that applies while the liftboats are under contract with Chevron Nigeria Limited.

In connection with the closing of the acquisition, the parties entered into an earnout agreement, under which the Company will pay Halliburton 25% of EBITDA (earnings from operations before interest, taxes, depreciation and amortization) earned on the liftboats owned or operated by Halliburton, together with the Company’s existing four liftboats operating in West Africa, to the extent in excess of $19,000,000 annually. Any amount payable to Halliburton under the earnout agreement will be reduced if and to the extent the Company incurs capital expenditures in excess of forecasted expenditures for the assets ($1,700,000, $2,245,000 and $1,900,000, in the first, second and third years, respectively). Any amount payable will also be adjusted for any increase or decrease in the assets. The earnout payments are payable annually over a three-year period up to an aggregate amount of $10,000,000. The EBITDA target will also be increased or decreased if additional assets are mobilized into or out of West Africa and is also subject to additional adjustments.

The liftboats are currently operating in the coastal waters of Nigeria and Cameroon and have leg lengths ranging from 105 to 215 feet.

NOTE 4 – BENEFIT PLANS

The Company has established a 401(k) plan for its employees. Participation is available to all employees beginning two months from the date of hire. Participants can contribute up to a maximum of $15,000 each year, and the Company matches participant contributions equal to 100% of the first 3% and 50% of the next 2% of a participant’s salary. The Company made matching contributions of $476,198 and $299,440 for the three months ended September 30, 2006 and September 30, 2005, respectively. The Company made matching contributions of $1,069,283 and $724,054 for the nine months ended September 30, 2006 and September 30, 2005, respectively.

NOTE 5 – LONG-TERM DEBT

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


	September 30, 2006		December 31, 2005
Senior secured term loan due June 2010	$	93,600	$	94,650

Total debt		93,600		94,650
Less debt due within one year		1,400		1,400

Total long-term debt	$	92,200	$	93,250

In June 2005, the Company entered into a senior secured credit agreement with a syndicate of financial institutions. This agreement, as amended, provides for a $140,000,000 term loan and a $75,000,000 revolving credit facility. As of September 30, 2006, no amounts were outstanding and no letters of credit had been issued under the revolving credit facility. As of that date, $93,600,000 of the principal amount of the term loan was outstanding, and the interest rate was 8.76%. The Company may seek commitments to increase the amount available under the credit agreement by an additional $25,000,000 if its leverage ratio, after giving effect to the incurrence of the additional $25,000,000 of borrowings, is no greater than 2.5 to 1. Amounts repaid under the term loan cannot be reborrowed except pursuant to such an increase in availability.

The credit agreement contains financial covenants relating to leverage, fixed charge coverage and collateral coverage. Other covenants contained in the agreement restrict, among other things, repurchases of equity interests, mergers, asset dispositions, guaranties, debt, liens, acquisitions, dividends, distributions, investments, affiliate transactions, prepayments of other debt and capital expenditures. The credit agreement permits the Company to make advances to and investments in its foreign subsidiaries provided it meets applicable financial covenants. The credit agreement contains customary events of default.

The Company’s obligations under the credit agreement are secured by its liftboats, all of its domestic rigs and substantially all of its other personal property, including all the equity of its domestic subsidiaries and 65% of the equity of certain foreign subsidiaries. All of the Company’s material domestic subsidiaries guarantee the Company’s obligations under the agreement and have granted similar liens on substantially all of their assets. The Company’s foreign subsidiaries are not guarantors and the assets owned by the foreign subsidiaries are not held as collateral for the loans.

In January 2006, the Company amended the credit agreement to provide for, among other things, the release of the guaranty, security agreement and vessel mortgages recently entered into by two of its Cayman subsidiaries in connection with the transfer to such subsidiaries of Rig 16 and Rig 31. In addition, the Company is permitted to advance up to $20,000,000 to these two Cayman subsidiaries and to invest an additional $25,000,000 million in its foreign subsidiaries. The Company also amended the credit agreement to extend the termination date of the 1% prepayment premium (that is applicable to certain prepayments of the term loan) from June 29, 2006 to December 31, 2006. The Company paid $193,176 in fees in the first quarter of 2006 related to these amendments.

In June 2006, the Company further amended the credit agreement. Among other things, the amendment increased the commitments under the revolving credit facility from $25,000,000 to $75,000,000, reduced the interest rate under the revolving credit facility by 1.0% per annum, and extended the maturity date of the revolving credit facility from June 29, 2008 to June 29, 2010. It also removed the limitations on investments by the Company in its subsidiaries that are not guarantors to the credit agreement. The previous limit of $25,000,000 on such investments in its subsidiaries was replaced by a collateral maintenance test that requires the Company to maintain a ratio of (1) the orderly liquidation value of all of the vessels mortgaged pursuant to the credit agreement to (2) the sum of the revolving commitments and outstanding term loans under the credit agreement, of not less than 1.25 to 1.00. In addition, the dollar limits on other investments (including acquisitions) by the Company were eliminated, provided the Company is in compliance with its covenants under the credit agreement after giving effect to the investment and, with respect to an investment greater than $25,000,000, the Company’s leverage ratio is not greater than 3.50 to 1.00 prior to and after giving effect to such investment. The existing annual limit of $25,000,000 on capital expenditures and the interest coverage ratio were replaced by a fixed charge coverage ratio, which requires the Company to maintain a ratio of (1) EBITDA less maintenance capital expenditures and cash taxes paid to (2) fixed charges, of not less than 1.25 to 1.00. Furthermore, a $2,000,000 limitation on insurance deductibles was removed and replaced with a requirement that the Company maintain insurance that is customary for the industry. Finally, a $2,500,000 annual limit on asset sales was increased to an aggregate basket of $95,000,000 for the term of the credit agreement, provided the net proceeds from such asset sales are used to repay amounts outstanding under the term loan.

The Company paid $639,896 in fees in the nine months ended September 30, 2006 related to the amendments discussed above.

As of September 30, 2006, the Company had a letter of credit supported by a restricted cash deposit of $250,000 issued outside of the revolving credit facility.

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 $1,232,481 at September 30, 2006 and is included in other assets and the cumulative net unrealized gain on these hedging instruments was $801,112, net of tax of $431,369, and is included in accumulated other comprehensive income in the consolidated balance sheet at September 30, 2006. The Company did not recognize a gain or loss due to

hedge ineffectiveness in its consolidated statements of operations for the nine months ended September 30, 2006 related to these hedging instruments. The Company recognized gains of $243,265 and $373,080 in other, net in the consolidated statements of operations for the three and nine months ended September 30, 2006, respectively, related to the interest rate swaps. The Company did not recognize a gain or loss due to hedge ineffectiveness in its consolidated statements of operations for the three and nine months ended September 30, 2005 related to these hedging instruments. The Company also did not recognize a gain or loss in interest expense in the consolidated statements of operations for the three and nine months ended September 30, 2005 related to the interest rate swaps.

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 Nigeria). The Company eliminates intersegment revenue and expenses, if any.

Operating results and net income by segment were as follows (in thousands):


Three Months Ended September 30, 2006
	Domestic Contract Drilling Services			International Contract Drilling Services			Domestic Marine Services			International Marine Services			Corporate and Other			Total
Revenues	$	46,415		$	7,883		$	40,082		$	2,832		$	—		$	97,212
Operating expenses, excluding depreciation and amortization		14,280			4,047			13,339			1,531			—			33,197
Depreciation and amortization		2,538			935			5,171			426			27			9,097
General and administrative, excluding depreciation and amortization		1,846			442			618			721			3,582			7,209

Operating income (loss)		27,751			2,459			20,954			154			(3,609	)		47,709
Interest expense		(1,642	)		(27	)		(899	)		(7	)		—			(2,575	)
Gain on disposal of asset		1,110			—			—			—			—			1,110
Other, net		(5	)		—			(89	)		4			964			874

Income before income taxes		27,214			2,432			19,966			151			(2,645	)		47,118
Income tax (expense) benefit		(9,902	)		(621	)		(7,435	)		(188	)		707			(17,439	)

Net income (loss)	$	17,312		$	1,811		$	12,531		$	(37	)	$	(1,938	)	$	29,679

Total assets (at end of period)	$	143,196		$	116,685		$	194,179		$	21,593		$	81,042		$	556,695

Three Months Ended September 30, 2005
	Domestic Contract Drilling Services			International Contract Drilling Services			Domestic Marine Services			International Marine Services			Corporate and Other			Total
Revenues	$	28,248		$	—		$	13,937		$	—		$	—		$	42,185
Operating expenses, excluding depreciation and amortization		14,043			—			7,757			—			—			21,800
Depreciation and amortization		1,410			—			2,334			—			9			3,753
General and administrative, excluding depreciation and amortization		598			—			412			—			3,021			4,031

Operating income (loss)		12,197			—			3,434			—			(3,030	)		12,601
Interest expense		(1,868	)		—			(919	)		—			52			(2,735	)
Loss on early retirement of debt		—			—			—			—			—			—
Other, net		147			—			34			— —			63			244

Net income (loss)	$	10,476		$	—		$	2,549		$	—		$	(2,915	)	$	10,110

Total assets (at end of period)	$	149,161		$	—		$	107,086		$	—		$	9,847		$	266,094

Nine Months Ended September 30, 2006
	Domestic Contract Drilling Services			International Contract Drilling Services			Domestic Marine Services			International Marine Services			Corporate and Other			Total
Revenues	$	111,703		$	12,159		$	95,842		$	9,938		$	—		$	229,642
Operating expenses, excluding depreciation and amortization		37,606			5,650			33,389			4,748			—			81,393
Depreciation and amortization		6,279			1,186			14,059			979			79			22,582
General and administrative, excluding depreciation and amortization		5,219			949			1,780			2,075			10,373			20,396

Operating income (loss)		62,599			4,374			46,614			2,136			(10,452	)		105,271
Interest expense		(4,388	)		(27	)		(2,402	)		(7	)		—			(6,824	)
Gain on disposal of assets		30,690			—			—			—			—			30,690
Other, net		191			—			309			3			2,194			2,697

Income before income taxes		89,092			4,347			44,521			2,132			(8,258	)		131,834
Income tax (expense) benefit		(32,517	)		(621	)		(16,603	)		(840	)		2,271			(48,310	)

Net income (loss)	$	56,575		$	3,726		$	27,918		$	1,292		$	(5,987	)	$	83,524


Nine Months Ended September 30, 2005
	Domestic Contract Drilling Services			International Contract Drilling Services		Domestic Marine Services			International Marine Services		Corporate and Other			Total
Revenues	$	79,427		$	—	$	33,888		$	—	$	—		$	113,315
Operating expenses, excluding depreciation and amortization		37,379			—		18,184			—		—			55,563
Depreciation and amortization		4,020			—		5,035			—		20			9,075
General and administrative, excluding depreciation and amortization		3,463			—		1,233			—		4,440			9,136

Operating income (loss)		34,565			—		9,436			—		(4,460	)		39,541
Interest expense		(5,489	)		—		(2,008	)		—		(75	)		(7,572	)
Loss on early retirement of debt		(1,843	)		—		(943	)		—		—			(2,786	)
Other, net		305			—		97			—		77			479

Net income (loss)	$	27,538		$	—	$	6,582		$	—	$	(4,458	)	$	29,662

NOTE 8 – COMMITMENTS AND CONTINGENCIES

Legal Proceedings

The Company is involved in various 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. Insurance premiums and fees for coverage of the Company’s operations, assets and personnel base (as the same existed at June 30, 2006) are expected to be approximately $23,900,000 for the twelve-month policy period ending July 1, 2007, an increase of approximately 151% over the previous policy period on an annualized basis.

In connection with the renewal of certain of the Company’s insurance policies, the Company entered into an agreement to finance a portion of the annual insurance premiums. Approximately $17,900,000 was financed through this arrangement. The interest rate is 5.75%, and the note matures in April 2007. Approximately $12,030,000 was outstanding at September 30, 2006.

2005 Hurricanes

In August 2005, two of the Company’s jackup rigs, Rig 21 and Rig 25, sustained damage during Hurricane Katrina. Rig 25 was insured for $50,000,000, and the Company reached a settlement with its insurance underwriters and received net insurance proceeds of $48,750,000 related to this claim in the second quarter of 2006, which represents the insured value less the negotiated salvage value of $1,250,000. The Company retained title to the rig and removed usable materials and equipment to be used on its other rigs. The Company recognized a gain of $29,580,283 in March 2006 related to its insurance claim on Rig 25, which represented the gross proceeds of $50,000,000 expected to be received, less the rig book value of $20,116,178 and less $303,539 of items related to the salvage operation of the rig not expected to be reimbursed by the Company’s insurance carriers. Rig 21 sustained substantial damage to its mat and was moved to a shipyard in Mississippi to repair the damage. The rig returned to service in April 2006. As of September 30, 2006, the Company has claims receivable of $12,182,717, net of the $1,000,000 deductible, for the salvage of Rig 25 and the repairs to Rig 21. The Company believes the full amount will be collected.

NOTE 9 – SUBSEQUENT EVENTS

Registration Demand

The Company is a party to a Registration Rights Agreement, dated as of July 8, 2005 (the “Registration Agreement”), with certain holders of common stock of the Company (the “Holders”). On October 31, 2006, the Company received from certain of the Holders, including LR Hercules Holdings, LP, Greenhill Capital Partners, L.P., Greenhill Capital Partners (Cayman), L.P., Greenhill Capital Partners (Executives), L.P. and Greenhill Capital, L.P. (collectively, the “Selling Stockholders”), notice of a demand by the Selling Stockholders under the Registration Agreement to have the Company file a registration statement with the U.S. Securities and Exchange Commission to register shares of common stock of the Company for the sale by the Selling Stockholders in an underwritten public offering. The Company intends to promptly comply with this demand and expects to file a registration statement with the SEC on or about November 7, 2006. The Company will not participate in the offering and will not receive any of the proceeds received in the offering by the Selling Stockholders.

Closing of West African Liftboat Purchase

On November 7, 2006, the Company completed its previously announced liftboat purchase with Halliburton. See Note 3.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the accompanying unaudited consolidated financial statements as of September 30, 2006 and for the three months and nine months ended September 30, 2006 and September 30, 2005, included elsewhere herein, and with our annual report on Form 10-K for the year ended December 31, 2005. 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 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 primarily in the U.S. Gulf of Mexico. 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.

•

Contract Drilling Services. We own a fleet of nine jackup rigs that can drill in maximum water depths ranging from 85 to 250 feet. Our Domestic Contract Drilling Services segment includes six jackup rigs operating in the U.S. Gulf of Mexico, and our International Contract Drilling Services segment includes one jackup rig working offshore Qatar, one jackup rig working offshore India and one jackup rig currently undergoing refurbishment and upgrade. Under most of our contract drilling service agreements, we are paid a fixed daily rental rate called a “dayrate,” and we are required to pay all costs associated with our own crews as well as the upkeep and insurance of the rig and equipment.

•

Marine Services. We operate a fleet of 64 liftboats in our Domestic and International Marine Services segments. 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 Nigeria and Cameroon. Prior to the fourth quarter of 2005, during which we acquired our international liftboats, we did not report an International Marine Services segment. 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.

During the second quarter of 2006, we commenced work with Rig 16 under our first international drilling contract and signed a definitive drilling contract for Rig 31 for work offshore India. In September 2006, we commenced the contract for Rig 31 following the completion of its refurbishment and upgrade. Rig 31 was mobilized to its first drilling location offshore India in early October 2006. In late October 2006, the rig experienced approximately 12 days of downtime due to mechanical problems with its generators, which have been replaced. During the downtime, Rig 31 was not entitled to earn the $110,000 per day dayrate. In November 2006, the rig recommenced operations and is presently on hire.

2005 HURRICANES

Two of our jackup rigs, Rig 21 and Rig 25, sustained damage during Hurricane Katrina in August 2005. Rig 21 sustained substantial damage to its mat and was moved to a shipyard in Mississippi to repair the damage. The rig returned to service in April 2006. Rig 25, which was inoperable, was insured for $50.0 million, and we reached a settlement with our insurance underwriters and received net insurance proceeds of $48.8 million related to the claim in the second quarter of 2006, which represents the insured value less the negotiated salvage value of $1.3 million. We

retained title to the rig and removed usable materials and equipment to be used on our other rigs. We recognized a gain of $29.6 million in March 2006 related to our insurance claim on Rig 25, which represented the $50.0 million in gross proceeds expected to be received, less the rig book value of $20.1 million and less $0.3 million of items related to the salvage operation of the rig not expected to be reimbursed by our insurance carriers. None of our rigs or liftboats sustained any material damage during Hurricane Rita in September 2005. We had accrued a total of $12.2 million as of September 30, 2006 for expenses we have incurred and other amounts related to damage suffered in Hurricane Katrina that we expect to be covered by insurance. These amounts are included in insurance claims receivable on our Consolidated Balance Sheet as of September 30, 2006, and include $3.9 million accrued for the salvage effort on Rig 25 and $8.3 million accrued for the damage sustained by Rig 21. We believe the full amount of these insurance claims receivable, net of the $1.0 million deductible, will be collected in 2006.

RECENT DEVELOPMENTS

Registration Demand

We are a party to a Registration Rights Agreement, dated as of July 8, 2005, with certain holders of our common stock. On October 31, 2006, we received from certain of those holders, including LR Hercules Holdings, LP, Greenhill Capital Partners, L.P., Greenhill Capital Partners (Cayman), L.P., Greenhill Capital Partners (Executives), L.P. and Greenhill Capital, L.P. (collectively, the “Selling Stockholders”), notice of a demand by the Selling Stockholders under the agreement to have us file a registration statement with the SEC to register shares of our common stock for the sale by the Selling Stockholders in an underwritten public offering. We intend to promptly comply with this demand and expect to file a registration statement with the SEC on or about November 7, 2006. We will not participate in the offering and will not receive any of the proceeds received in the offering by the Selling Stockholders.

Closing of West African Liftboat Purchase

On November 7, 2006, we completed our previously announced transaction with Halliburton West Africa Limited and Halliburton Energy Services Nigeria Limited. In the transaction, we: (i) purchased eight liftboats owned by Halliburton, (ii) assumed Halliburton’s rights to operate five additional liftboats under an arrangement with the third-party vessel owner, (iii) assumed the lease of a 1.25 hectare shore-based facility located in Warri, Nigeria that includes warehouse space, offices and a machine shop, and (iv) assumed Halliburton’s rights and obligations under certain customer contracts and other agreements related to Halliburton’s liftboat operations in West Africa. The purchase price for the acquisition was $50,000,000, subject to adjustment, plus any amounts payable under the three-year earnout agreement described below. We operate the five liftboats owned by the third party under a management agreement that applies while the liftboats are under contract with Chevron Nigeria Limited.

In connection with the closing of the acquisition, the parties entered into an earnout agreement, under which we will pay Halliburton 25% of EBITDA (earnings from operations before interest, taxes, depreciation and amortization) earned on the liftboats owned or operated by Halliburton, together with our existing four liftboats operating in West Africa, to the extent in excess of $19.0 million annually. Any amount payable to Halliburton under the earnout agreement will be reduced if and to the extent we incur capital expenditures in excess of forecasted expenditures for the assets ($1.7 million, $2.2 million and $1.9 million in the first, second and third years, respectively). Any amount payable will also be adjusted for any increase or decrease in the assets. The earnout payments are payable annually over a three-year period up to an aggregate amount of $10.0 million. The EBITDA target will also be increased or decreased if additional assets are mobilized into or out of West Africa and is also subject to additional adjustments.

The liftboats are currently operating in the coastal waters of Nigeria and Cameroon and have leg lengths ranging from 105 to 215 feet.

Liftboat Acquisition from Laborde

In June 2006, we acquired five liftboats from Laborde Marine Lifts, Inc. (“Laborde”). In addition, we assumed the construction of an additional liftboat pursuant to a construction agreement assigned to us by Laborde at the closing. Pursuant to the terms of the purchase agreement, the original purchase price of $52.0 million was reduced by $2.7 million, which represented the total amount remaining due at closing under the construction contract for the sixth liftboat. Construction of the liftboat was completed in July 2006 and the additional amount due to the shipyard was paid. The liftboats have leg lengths ranging from 105 to 200 feet and are located in the U.S. Gulf of Mexico.

We used $48.8 million of insurance proceeds related to Rig 25 to pay the purchase price of the Laborde transaction at closing. The balance was paid from cash on hand.

Public Offering of Common Stock

We completed a public offering of 9,200,000 shares of our common stock at $36.00 per share in April 2006. We issued 1,600,000 shares of common stock, while the remaining 7,600,000 shares were sold by certain selling stockholders. We received approximately $54.2 million of proceeds from the offering, net of underwriter discounts and commissions and estimated expenses. We are using the net proceeds we received for general corporate purposes.

Insurance Renewal

In June 2006, we completed the renewal of all of our key insurance policies, except for the directors and officers liability policy, which was renewed on November 1, 2006. We maintain insurance coverage that includes coverage for physical damage, third party liability, maritime employers liability, general liability, vessel pollution and other coverages. Our primary marine package provides for hull and machinery coverage for our drilling rigs and liftboats up to a scheduled value for each asset. Under the renewed policies, the maximum coverage for these assets was increased to $580.0 million; however, coverage for U.S. Gulf of Mexico named windstorm damage is now subject to an annual aggregate limit on liability of $75.0 million. The policies are subject to deductibles and other conditions. Under the new coverage, deductibles for events that are not U.S. Gulf of Mexico named windstorm events are $1.5 million 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 $1.5 million per rig for each occurrence plus an additional $5.0 million for each U.S. Gulf of Mexico named windstorm. Our maritime employers liability policy was renewed for an 18 month term on terms substantially similar to the terms of the previous policy, and the renewed policy retains the previous deductible level of $25,000 per occurrence.

Overall, our insurance premiums and fees for coverage for our operations, assets and personnel base (as the same existed at June 30, 2006) increased from approximately $9.5 million (on an annualized basis) in 2005 to $23.9 million under the renewed coverages. Higher premium costs reflect the damage sustained by the oil and natural gas industry from Hurricanes Ivan, Katrina and Rita. In addition, our premiums were also affected by the large increase in the insured values of Rig 16, Rig 26 and Rig 31, which we acquired since our last insurance renewal and have substantially upgraded, as well as the liftboats acquired in June 2006.

We have obtained financing from the insurance underwriters for 75% of the premium over nine months at an interest rate of 5.75% per annum. We will incur total interest cost of approximately $435,000 under this arrangement. We reduced our total premium by $476,000, and thus offsetting the interest cost, by paying the premium for the rig package immediately.

Rig Sale Agreement

In June 2006, we entered into a definitive agreement to sell Rig 41 for $3.2 million, net of commissions. The buyer paid a $0.3 million non-refundable deposit, and the sale closed in July 2006. We recognized a gain of approximately $1.1 million in the third quarter of 2006 on the sale for the excess of the purchase price over the rig’s carrying value.

Facility Sale Agreement

In June 2006, we entered into a definitive agreement to sell our New Iberia facility for $2.8 million, net of commissions. The buyer paid a $0.1 million deposit, and the sale closed in September 2006. We recognized a gain of approximately $0.1 million in the third quarter of 2006 on the sale for the excess of the purchase price over the facility’s carrying value.

Amendment to Credit Agreement

In June 2006, we amended our credit agreement. Among other things, the amendment increased the commitments under the revolving credit facility from $25.0 million to $75.0 million, reduced the interest rate under the revolving credit facility by 1.0% per annum, and extended the maturity date of the revolving credit facility from June 29, 2008 to June 29, 2010. It also removed the limitations on investments by us in our subsidiaries that are not guarantors to the credit agreement. The previous limit of $25.0 million on such investments was replaced by a collateral maintenance test that requires us to maintain a ratio of (1) the orderly liquidation value of all of the vessels mortgaged pursuant to the credit agreement to (2) the sum of the revolving commitments and outstanding term loans under the credit agreement, of not less than 1.25 to 1.00. In addition, the dollar limits on other investments (including acquisitions) by us were eliminated, provided we are in compliance with our covenants under the credit agreement after giving effect to the investment and, with respect to an investment greater than $25.0 million, our leverage ratio is not greater than 3.50 to 1.00 prior to and after giving effect to such investment. The existing annual limit of $25.0 million on capital

expenditures and the interest coverage ratio were replaced by a fixed charge coverage ratio, which requires us to maintain a ratio of (1) EBITDA less maintenance capital expenditures and cash taxes paid to (2) fixed charges, of not less than 1.25 to 1.00. Furthermore, a $2.0 million limitation on insurance deductibles was removed and replaced with a requirement that we maintain insurance that is customary for the industry. Finally, a $2.5 million annual limit on asset sales was increased to an aggregate basket of $95.0 million for the term of the credit agreement, provided the net proceeds from such asset sales are used to repay amounts outstanding under the term loan. We paid $0.4 million in fees related to the amendment.

CRITICAL ACCOUNTING POLICIES

Critical accounting policies are those that are important to our results of operations, financial condition and cash flows and require management’s most difficult, subjective or complex judgments. Different amounts would be reported under alternative assumptions. We have evaluated the accounting policies used in the preparation of the unaudited consolidated financial statements and related notes appearing elsewhere in this Form 10-Q. We apply those accounting policies that we believe best reflect the underlying business and economic events, consistent with accounting principles generally accepted in the United States. We believe that our policies are generally consistent with those used by other companies in our industry.

We periodically update the estimates used in the preparation of the financial statements based on our latest assessment of the current and projected business and general economic environment. We believe that our more critical accounting policies include those related to property and equipment, revenue recognition, 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, 2005. In addition, on January 1, 2006, we adopted the modified prospective provisions of Statement of Financial Accounting Standards (“SFAS”) No. 123 (revised 2004) “Share-Based Payment,” which changed the manner in which we account for share-based payments granted to employees. For additional information about this Statement, please read Note 1 of the Notes to Consolidated Financial Statements included in Item 1 of Part I of this quarterly report.

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. Our jackup rigs were contracted at dayrates ranging from approximately $65,000 to $115,000 in the third quarter of 2006, as compared to dayrates ranging from approximately $36,000 to $53,000 in the third quarter of 2005. Our liftboats were contracted at dayrates ranging from approximately $5,100 to $31,000 in the third quarter of 2006, as compared to dayrates ranging from approximately $2,400 to $11,700 in the third quarter of 2005. These dayrates do not include reimbursement from customers under the related contracts.


	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
	(Dollars in thousands, except per day amounts)						(Dollars in thousands, except per day amounts)
Domestic Contract Drilling Services Segment:
Number of rigs (as of end of period)		6			9			6			9
Operating days		548			571			1,424			1,783
Available days		552			598			1,526			1,849
Utilization (1)		99.3	%		95.5	%		93.3	%		96.4	%
Average revenue per rig per day (2)	$	84,776		$	49,471		$	78,449		$	44,552
Average operating expense per rig per day (3)	$	25,871		$	23,483		$	24,644		$	20,216
Revenues	$	46,415		$	28,248		$	111,703		$	79,427
Operating expenses, excluding depreciation and amortization	$	14,280		$	14,043		$	37,606		$	37,379
Depreciation and amortization expense	$	2,538		$	1,410		$	6,279		$	4,020
General and administrative expenses, excluding depreciation and amortization	$	1,846		$	598		$	5,219		$	3,463
Operating income	$	27,751		$	12,197		$	62,599		$	34,565

International Contract Drilling Services Segment:
Number of rigs (as of end of period)		3			—			3			—
Operating days		100			—			133			—
Available days		100			—			137			—
Utilization (1)		100.0	%		—			97.1	%		—
Average revenue per rig per day (2)	$	78,825		$	—		$	91,486		$	—
Average operating expense per rig per day (3)	$	40,466		$	—		$	41,147		$	—
Revenues	$	7,883		$	—		$	12,159		$	—
Operating expenses, excluding depreciation and amortization	$	4,047		$	—		$	5,650		$	—
Depreciation and amortization expense	$	935		$	—		$	1,186		$	—
General and administrative expenses, excluding depreciation and amortization	$	442		$	—		$	949		$	—
Operating income	$	2,459		$	—		$	4,374		$	—

Domestic Marine Services Segment:
Number of liftboats (as of end of period)		47			39			47			39
Operating days		3,171			2,566			8,823			5,784
Available days		4,119			3,220			11,276			7,592
Utilization (1)		77.0	%		79.7	%		78.2	%		76.0	%
Average revenue per liftboat per day (2)	$	12,641		$	5,432		$	10,863		$	5,859
Average operating expense per liftboat per day (3)	$	3,238		$	2,409		$	2,961		$	2,395
Revenues	$	40,082		$	13,937		$	95,842		$	33,888
Operating expenses, excluding depreciation and amortization	$	13,339		$	7,757		$	33,389		$	18,184
Depreciation and amortization expense	$	5,171		$	2,334		$	14,059		$	5,035
General and administrative expenses, excluding depreciation and amortization	$	618		$	412		$	1,780		$	1,233
Operating income	$	20,954		$	3,434		$	46,614		$	9,436


	Three Months Ended September 30,					Nine Months Ended September 30,
	2006			2005		2006			2005
	(Dollars in thousands, except per day amounts)					(Dollars in thousands, except per day amounts)
International Marine Services Segment:
Number of liftboats (as of end of period)		4			—		4			—
Operating days		235			—		947			—
Available days		368			—		1,092			—
Utilization (1)		63.9	%		—		86.7	%		—
Average revenue per liftboat per day (2)	$	12,050		$	—	$	10,494		$	—
Average operating expense per liftboat per day (3)	$	4,158		$	—	$	4,348		$	—
Revenues	$	2,832		$	—	$	9,938		$	—
Operating expenses, excluding depreciation and amortization	$	1,531		$	—	$	4,748		$	—
Depreciation and amortization expense	$	426		$	—	$	979		$	—
General and administrative expenses, excluding depreciation and amortization	$	721		$	—	$	2,075		$	—
Operating income	$	154		$	—	$	2,136		$	—

Total Company:
Revenues	$	97,212		$	42,185	$	229,642		$	113,315
Operating expenses, excluding depreciation and amortization	$	33,197		$	21,800	$	81,393		$	55,563
Depreciation and amortization expense	$	9,097		$	3,753	$	22,582		$	9,075
General and administrative expenses, excluding depreciation and amortization	$	7,209		$	4,031	$	20,396		$	9,136
Operating income	$	47,709		$	12,601	$	105,271		$	39,541
Interest expense	$	2,575		$	2,735	$	6,824		$	7,572
Loss on early retirement of debt	$	—		$	—	$	—		$	2,786
Gain on disposal of assets	$	1,110		$	—	$	30,690		$	—
Other income	$	874		$	244	$	2,697		$	479
Income before income taxes	$	47,118		$	10,110	$	131,834		$	29,662
Income tax provision	$	17,439		$	—	$	48,310		$	—
Net income	$	29,679		$	10,110	$	83,524		$	29,662

(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 16, Rig 21, Rig 26 and Rig 31, or cold-stacked units, which included three of our liftboats, 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 revenue is a total of $722,564 and $847,564 related to amortization of deferred mobilization revenue and contract specific capital expenditures reimbursed by the customer for the three and nine months ended September 30, 2006, respectively. Included in revenue for our International Contract Drilling Services segment for the nine months ended September 30, 2006 is $2,010,000 earned for a timely departure of Rig 16 from the shipyard in the second quarter of 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 operating expense is a total of $552,918 and $571,949 related to amortization of deferred mobilization expenses for the three and nine months ended September 30, 2006, respectively.

We have not provided below a comparison of our International Contract Drilling Services and International Marine Services segments, because those segments were established subsequent to September 30, 2005.

For the Three Months Ended September 30, 2006 and 2005

Revenues

Consolidated. Total revenues for the three-month period ended September 30, 2006 (the “Current Quarter”) were $97.2 million compared with $42.2 million for the three-month period ended September 30, 2005 (the “Comparable Quarter”), an increase of $55.0 million, or 130%. This increase resulted primarily from higher average dayrates in our Domestic Contract Drilling Services and Domestic Marine Services segments and additional operating days in our Domestic and International Marine Services segment, primarily due to the acquisition of liftboats in November 2005 and June 2006. Total revenues included $1.8 million in reimbursements from our customers for expenses paid by us in the Current Quarter compared with $1.4 million in the Comparable Quarter.

Domestic Contract Drilling Services Segment. Revenues for our Domestic Contract Drilling Services segment were $46.4 million for the Current Quarter compared with $28.2 million for the Comparable Quarter, an increase of $18.2 million, or 65%. This increase resulted primarily from higher average dayrates and utilization for our fleet. Operating days decreased to 548 in the Current Quarter from 571 in the Comparable Quarter. Rig 25, which is no longer operable due to damage sustained during Hurricane Katrina and will be scrapped, did not operate in the Current Quarter and operated 59 days in the Comparable Quarter. Rig 21 operated 92 days in the Current Quarter and operated 76 days in the Comparable Quarter due to damage sustained in Hurricane Katrina. Average revenue per rig per day was $84,776 in the Current Quarter compared with $49,471 in the Comparable Quarter, with average utilization of 99.3% in the Current Quarter compared with 95.5% in the Comparable Quarter. Revenues for our Domestic Contract Drilling Services segment included $0.3 million in reimbursements from our customers for expenses paid by us in the Current Quarter compared with $0.7 million in the Comparable Quarter.

Domestic Marine Services Segment. Revenues for our Domestic Marine Services segment were $40.0 million for the Current Quarter compared with $13.9 million in the Comparable Quarter, an increase of $26.1 million, or 188%. This increase resulted primarily from additional operating days and higher average dayrates. Operating days in the Current Quarter were 3,171 compared with 2,566 operating days in the Comparable Quarter, with the increase due primarily to acquisition activity. Average revenue per liftboat per day was $12,641 in the Current Quarter compared with $5,432 in the Comparable Quarter, with average utilization of 77.0% in the Current Quarter compared with 79.7% 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 $1.4 million in reimbursements from our customers for expenses paid by us in the Current Quarter compared with $0.6 million in the Comparable Quarter.

Operating Expenses

Consolidated. Total operating expenses, excluding depreciation and amortization, for the Current Quarter were $33.2 million compared with $21.8 million in the Comparable Quarter, an increase of $11.4 million, or 52%. This increase resulted primarily from the increase in rig and liftboat operating expenses described below.

Domestic Contract Drilling Services Segment. Operating expenses, excluding depreciation and amortization, for our Domestic Contract Drilling Services segment were $14.3 million in the Current Quarter compared with $14.0 million in the Comparable Quarter, an increase of $0.3 million, or 2%. The Comparable Quarter included a $1.0 million deductible recorded for damage sustained by one of our rigs during Hurricane Katrina in August 2005. Available days decreased to 552 in the Current Quarter from 598 in the Comparable Quarter. The decrease resulted primarily from fewer available days for Rig 25, which was available 62 days in the Comparable Quarter. Rig 25 did not operate in the Current Quarter. Average operating expenses per rig per day were $25,871 in the Current Quarter compared with $23,483 in the Comparable Quarter. On a per day basis, average operating expenses per rig increased $2,388. The increase resulted primarily from an increase in labor expenses, which increased $2,441 per day, an increase in insurance costs, which increased $1,508 per day, and an increase in rig maintenance costs, which increased $136 per day. The increased operating costs were partially offset by a decrease in reimbursable costs of $633 per day and a decrease in other costs. We were able to reduce the effect of the increased labor and insurance costs by charging a portion of the increase to our customers pursuant to our drilling contracts.

Domestic Marine Services Segment. Operating expenses, excluding depreciation and amortization, for our Domestic Marine Services segment were $13.3 million for the Current Quarter compared with $7.8 million in the Comparable Quarter, an increase of $5.5 million, or 71%. The increase is due primarily to liftboat acquisitions and additional operating days. Average operating expenses per liftboat per day were $3,238 in the Current Quarter compared with $2,409 in the Comparable Quarter. This increase resulted primarily from an increase in labor expenses, which increased $487 per day, an increase in insurance costs, which increased $115 per day, and an increase in liftboat maintenance costs, which increased $25 per day.

Depreciation and Amortization

Depreciation and amortization expense in the Current Quarter was $9.1 million compared with $3.8 million in the Comparable Quarter, an increase of $5.3 million, or 139%. This increase resulted primarily from an additional $1.1 million in depreciation expense for our Domestic Contract Drilling Services segment, $1.2 million for our Domestic Marine Services segment, $0.9 million for our International Contract Drilling Services segment and $0.4 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 $1.7 million.

General and Administrative Expenses

General and administrative expenses, excluding depreciation and amortization, in the Current Quarter were $7.2 million compared with $4.0 million in the Comparable Quarter, an increase of $3.2 million, or 80%. 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 from $3.0 million in the Comparable Quarter to $3.6 million in the Current Quarter, an increase of $0.6 million. This increase is due primarily to stock-based compensation expense of $0.8 million. General and administrative expenses increased $1.2 million and $0.3 million, respectively, in our Domestic Contract Drilling Services and Domestic Marine Services segments from the Comparable Quarter to the Current Quarter. General and administrative expense for our International Contract Drilling Services segment in the Current Quarter was $0.4 million, which represents expenses associated with our operations in Qatar that commenced in the first quarter of 2006. General and administrative expense for our International Marine Services segment in the Current Quarter was $0.7 million, which represent expenses associated with our operations in Nigeria that commenced in the fourth quarter of 2005.

Interest Expense

Interest expense in the Current Quarter was $2.6 million compared with $2.7 million in the Comparable Quarter, a decrease of $0.1 million, or 4%. This decrease resulted from a decrease in our debt outstanding from $140.0 million at the end of the Comparable Quarter to $93.6 million at the end of the Current Quarter, partially offset by interest expense on our insurance note payable.

Gain on Disposal of Asset

The gain on disposal of asset in the Current Quarter consisted of $1.1 million related to the gain on the sale of Rig 41. There was no gain on disposal of asset in the Comparable Period.

Other Income

Other income in the Current Quarter was $0.9 million compared with $0.2 million in the Comparable Quarter, an increase of $0.7 million. This increase is due to higher cash balances resulting in increased interest income and realized gains related to our interest rate hedging activity.

Income Tax Provision

Income tax expense was $17.4 million on pre-tax income of $47.1 million during Current Quarter, compared to no income tax on pre-tax income of $10.1 million for the Comparable Quarter. No income tax was recorded in the Comparable Quarter due to our status as a partnership for U.S. federal income tax purposes for periods prior to our conversion to a Delaware corporation on November 1, 2005. The tax rate was 36.9% in the Current Quarter.

For the Nine Months Ended September 30, 2006 and 2005

Revenues

Consolidated. Total revenues for the nine-month period ended September 30, 2006 (the “Current Period”) were $229.6 million compared with $113.3 million for the nine-month period ended September 30, 2005 (the “Comparable Period”), an increase of $116.3 million, or 103%. This increase resulted primarily from higher average dayrates in our Domestic Marine Services segment and additional operating days in our Domestic and International Marine Services segment, primarily due to the acquisition of liftboats in June and November 2005 and June 2006. Total revenues included $4.3 million in reimbursements from our customers for expenses paid by us in the Current Period compared with $3.7 million in the Comparable Period.

Domestic Contract Drilling Services Segment. Revenues for our Domestic Contract Drilling Services segment were $111.7 million for the Current Period compared with $79.4 million for the Comparable Period, an increase of $32.3 million, or 41%. This increase resulted primarily from higher average dayrates for our fleet partially offset by reduced utilization on four of our rigs, two of which sustained damage during Hurricane Katrina in August 2005. Operating days decreased to 1,424 in the Current Period from 1,783 in the Comparable Period. Rig 21 operated 156 days in the Current Period compared to 250 days in the Comparable Period. The rig was in the shipyard for repairs for 112 days in the Current Period. Rig 25, which is no longer operable due to damage sustained during Hurricane Katrina and will be scrapped, did not operate in the Current Period and operated 235 days in the Comparable Period. Two of our other rigs were in the shipyard for repairs, upgrades and refurbishments during the Current Period. Average revenue per rig per day was $78,449 in the Current Period compared with $44,552 in the Comparable Period, with average utilization of 93.3% in the Current Period compared with 96.4% in the Comparable Period. Revenues for our Domestic Contract Drilling Services segment included $0.9 million in reimbursements from our customers for expenses paid by us in the Current Period compared with $2.0 million in the Comparable Period.

Domestic Marine Services Segment. Revenues for our Domestic Marine Services segment were $95.8 million for the Current Period compared with $33.9 million in the Comparable Period, an increase of $61.9 million, or 183%. This increase resulted primarily from additional operating days, higher average dayrates and higher average utilization. Operating days in the Current Period were 8,823 compared with 5,784 operating days in the Comparable Period, with the increase due primarily to acquisition activity. Average revenue per liftboat per day was $10,863 in the Current Period compared with $5,859 in the Comparable Period, with average utilization of 78.2% in the Current Period compared with 76.0% in the Comparable Period. The increase in average dayrates and average utilization was attributable primarily to increased activity in the aftermath of Hurricane Katrina and Hurricane Rita. Revenues for our Domestic Marine Services segment included $3.3 million in reimbursements from our customers for expenses paid by us in the Current Period compared with $1.6 million in the Comparable Period.

Operating Expenses

Consolidated. Total operating expenses, excluding depreciation and amortization, for the Current Period were $81.4 million compared with $55.6 million in the Comparable Period, an increase of $25.8 million, or 46%. This increase resulted primarily from the increase in rig and liftboat operating expenses described below.

Domestic Contract Drilling Services Segment. Operating expenses, excluding depreciation and amortization, for our Domestic Contract Drilling Services segment were $37.6 million in the Current Period and $37.4 million in the Comparable Period. The Comparable Period included a $1.0 million deductible recorded for damage sustained by

one of our rigs during Hurricane Katrina in August 2005. Available days decreased to 1,526 in the Current Period from 1,849 in the Comparable Period. Average operating expenses per rig per day were $24,644 in the Current Period compared with $20,216 in the Comparable Period. The increase in operating expense per rig per day is due in part to the inclusion of operating expenses for Rig 21 during the Current Period while the rig was undergoing repairs for damage sustained during Hurricane Katrina partially offset by a $1.0 million insurance deductible in the Comparable Period. Rig 21 was in the shipyard for 112 days in the Current Period. On a per day basis, average operating expenses per rig increased $4,428, of which $696 was attributable to Rig 21 while it was in the shipyard. The increase resulted primarily from an increase in labor expenses, which increased $3,179 per day, of which $665 was attributable to expenses on Rig 21 while in the shipyard, an increase in insurance costs, which increased $1,140 per day, and an increase in rig maintenance costs, which increased $887 per day, of which $158 was attributable to Rig 21.

Domestic Marine Services Segment. Operating expenses, excluding depreciation and amortization, for our Domestic Marine Services segment were $33.4 million for the Current Period compared with $18.2 million in the Comparable Period, an increase of $15.2 million, or 84%. The increase is due to liftboat acquisitions and additional operating days. Average operating expenses per liftboat per day were $2,961 in the Current Period compared with $2,395 in the Comparable Period. This increase resulted primarily from an increase in labor expenses, which increased $372 per day, an increase in insurance costs, which increased $74 per day, and an increase in liftboat maintenance costs, which increased $35 per day.

Depreciation and Amortization

Depreciation and amortization expense in the Current Period was $22.6 million compared with $9.1 million in the Comparable Period, an increase of $13.5 million, or 148%. This increase resulted primarily an additional $2.3 million in depreciation expense for our Domestic Contract Drilling Services segment, $3.1 million for our Domestic Marine Services segment, $1.2 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 Period and the Current Period. Additionally, amortization of regulatory inspections and related drydockings increased $6.0 million.

General and Administrative Expenses

General and administrative expenses, excluding depreciation and amortization, in the Current Period were $20.4 million compared with $9.1 million in the Comparable Period, an increase of $11.3 million, or 124%. 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 from $4.4 million in the Comparable Period to $10.4 million in the Current Period, an increase of $6.0 million. This increase is due to increased headcount, additional professional fees related to increased regulatory requirements as a public company and stock-based compensation expense of $2.3 million. General and administrative expenses increased $1.7 million and $0.6 million in our Domestic Contract Drilling Services and Domestic Marine Services segments, respectively. General and administrative expense for our International Contract Drilling Services segment in the Current Period was $0.9 million, which represents expenses associated with our operations in Qatar that commenced in the first quarter of 2006. General and administrative expense for our International Marine Services segment in the Current Period was $2.1 million, which represent expenses associated with our operations in Nigeria that commenced in the fourth quarter of 2005.

Interest Expense

Interest expense in the Current Period was $6.8 million compared with $7.6 million in the Comparable Period, a decrease of $0.8 million, or 11%. This decrease resulted from a decrease in the average interest rate on our overall borrowings. The average interest rate decreased to 7.68% in the Current Period from 8.70% in the Comparable Period.

Gain on Disposal of Assets

The gain on disposal of asset in the Current Period of $30.7 consisted of $29.6 million related to the insurance settlement on the loss of Rig 25 in Hurricane Katrina and $1.1 million related to the gain on the sale of Rig 41. There was no gain on disposal of assets in the Comparable Period.

Other Income

Other income in the Current Period was $2.7 million compared with $0.5 million in the Comparable Period, an increase of $2.2 million. This increase is due to higher cash balances resulting in increased interest income and realized gains related to our interest rate hedging activity.

Income Tax Provision

Income tax expense was $48.3 million on pre-tax income of $131.8 million during Current Period, compared to no income tax on pre-tax income of $29.7 million for the Comparable Period. No income tax was recorded in the Comparable Period due to our status as a partnership for U.S. federal income tax purposes for periods prior to our conversion to a Delaware corporation on November 1, 2005. The tax rate was 36.6% in the Current Period.

International Contract Drilling Services Segment

Our International Contract Drilling Services segment comprises one jackup rig working offshore Qatar, one jackup rig working offshore India and a third jackup rig currently undergoing upgrade and refurbishment. Revenues for our International Contract Drilling Services segment were $7.9 million and $12.2 million for the Current Quarter and Current Period, respectively. Average revenue per rig per day was $78,825, operating days were 100 and average utilization was 100.0% in the Current Quarter. Average revenue per rig per day was $91,486, operating days were 133 and average utilization was 97.1% in the Current Period. Included in revenue is approximately $2.0 million earned for a timely departure of Rig 16 from the shipyard in the second quarter of 2006. Included in revenue for the Current Period is $0.7 million and $0.8 million related to amortization of deferred mobilization revenue and contract specific capital expenditures reimbursed by the customer for the Current Quarter and Current Period, respectively. Revenues in our International Contract Drilling Services segment do not include any reimbursements from our customers for expenses paid by us. Operating expenses, excluding depreciation and amortization, for our International Contract Drilling Services segment were $4.0 million and $5.7 million for the Current Quarter and Current Period, respectively. Operating expenses on our rigs averaged $40,466 per rig per day in the Current Quarter and $41,147 in the Current Period. Included in operating expense is $0.6 million and related to amortization of deferred mobilization expenses for the Current Quarter and Current Period.

International Marine Services Segment

Our International Marine Services segment comprises the four liftboats acquired in November 2005 that are operating in Nigeria. Revenues for our International Marine Services segment were $2.8 million and $9.9 million for the Current Quarter and Current Period, respectively. Average revenue per liftboat per day was $12,050, operating days were 235 and average utilization was 63.9% in the Current Quarter. Average revenue per liftboat per day was $10,494, operating days were 947 and average utilization was 86.7% in the Current Period. Utilization for the Current Quarter and Current Period reflects two liftboats in drydock during the Current Quarter. Revenues in our International Marine Services segment do not include any reimbursements from our customers for expenses paid by us. Operating expenses, excluding depreciation and amortization, for our International Marine Services segment were $1.5 million and $4.7 million for the Current Quarter and Current Period, respectively. Operating expenses on our liftboats averaged $4,158 per liftboat per day in the Current Quarter and $4,348 in the Current Period.

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 were higher than recent historical levels throughout 2005 and the majority of 2006, but have declined significantly in the last two months. The spot price for Henry Hub natural gas has declined by 50% from $8.63 per mmbtu on August 1, 2006 to $3.63 per mmbtu on September 29, 2006, with a price of $6.64 per mmbtu on October 31, 2006. Oil prices increased through 2005 and the first several months of 2006, with the spot price for West Texas intermediate crude increasing from $42.12 per bbl as of January 1, 2006, to a recent peak of $77.03 on July 14, 2006 before declining to $58.73 as of October 31, 2006.

The supply of jackup rigs in the U.S. Gulf of Mexico has declined considerably over the last several years. During the first nine months of 2006, our competitors mobilized 15 jackups out of the U.S. Gulf of Mexico to international markets. Further, as of October 31, 2006, there were an additional 11 jackups that have announced plans to depart the U.S. Gulf of Mexico for international work. We anticipate that there will be additional need for jackups in several international markets, which could further reduce the supply of rigs in the U.S. Gulf of Mexico.

The reduced supply of available rigs in the region, together with historically high commodity prices, generally resulted in strong demand for our domestic drilling units in 2005 and the first nine months of 2006, and dayrates for our drilling rigs increased during this period. However, with current natural gas prices trending lower, the level of drilling activity in the U.S. Gulf of Mexico and dayrates have moderated, which may impact the utilization of jackups operating in shallow waters in this region. 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 due to lower natural gas prices.

According to ODS-Petrodata, as of October 1, 2006, 61 jackup rigs have been ordered by industry participants, national oil companies and financial investors for delivery through 2009. 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, eight idle jackups in the U.S. Gulf of Mexico owned by our competitors have been cold stacked for all of 2005, and in some cases, several years earlier. 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. Companies renewing insurance policies covering assets in the U.S. Gulf of Mexico are likely to have an aggregate limit for what they can recover for assets damaged during named windstorms, which likely 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

Demand for our liftboats has been strong since the second quarter of 2005. The steadily increasing dayrates that we experienced in 2005 continued in the first nine months of 2006. 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 increased through 2005 and the first nine months of 2006; we expect this demand to continue at least through the end of 2006 and likely into 2007. We also expect increased demand for our well intervention capabilities to assist our customers in restoring production from wells damaged by the hurricanes. Plug and abandonment and platform decommissioning work is also expected to increase.

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 significant backlog of work from Hurricanes Katrina and Rita, some of the repair and abandonment work may be deferred.

We anticipate that demand for liftboats will likely increase in international markets. As a result of aging offshore infrastructure in a number of regions and the increase in dayrates for jackups and other equipment that is used to service this infrastructure, we anticipate that there will be longer term contract opportunities in international markets for liftboats currently working in the U.S. Gulf of Mexico and for newly constructed liftboats. Generally, we believe demand for liftboats in international markets will be driven by the maintenance of this aging offshore infrastructure in certain areas and by the installation of new infrastructure in other markets, 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 markets, which have long term contract opportunities.

As of November 1, 2006, we believe that there were 13 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.

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.

International Operations

In accordance with our strategy of expansion into international markets with characteristics similar to those in the U.S. Gulf of Mexico, in the first quarter of 2006, we received commitments to contract two of our drilling rigs internationally. We established shorebase operations in Qatar and India to accommodate these contracts. We have established an international structure based in the Cayman Islands to facilitate this expansion. Certain of our international rigs are owned or operated, directly or indirectly, by various of our wholly owned Cayman Islands subsidiaries. Earnings from these subsidiaries are reinvested to finance foreign activities.

LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses of Cash

Sources and uses of cash for the nine-month periods ended September 30, 2006 and 2005 are as follows:


	Nine Months Ended September 30,
	2006			2005
	(dollars in millions)
Net cash provided by operating activities
Net income	$	83.5		$	29.6
Depreciation and amortization		22.6			9.1
Increase in accounts payable and other current liabilities		29.3			15.6
Increase in insurance note payable		9.6
Deferred income tax provision		27.7			—
Stock-based compensation		2.3			—
Loss on early retirement of debt		—			2.8
Gain on disposal of assets		(30.7	)		—
Gain on sale of assets		(0.1	)
Increase in accounts receivable, insurance claims receivable and other current assets		(59.2	)		(19.4	)

Total	$	85.0		$	37.7

Net cash used in investing activities
Acquisition of Rig 25 and Rig 30 in January 2005	$	—		$	(41.5	)
Acquisition of 17 liftboats in June 2005		—			(20.0	)
Acquisition of Rig 16 in June 2005		—			(20.0	)
Acquisition of the Whale Shark in August 2005		—			(12.5	)
Acquisition of Rig 31 in September 2005		—			(12.6	)
Acquisition of Rig 26 in February 2006		(20.1	)		—
Acquisition of six liftboats in June 2006		(52.0	)		—
Refurbishment and upgrade of Rig 16		(10.3	)		(3.4	)
Refurbishment and upgrade of Rig 31		(22.6	)		—
Refurbishment and upgrade of Rig 26		(18.4	)		—
Other rig refurbishments		(13.9	)		(2.3	)
Refurbishments of liftboats		(2.2	)		—
Drillpipe		(4.4	)		—
Deferred drydocking expenditures for liftboats		(9.0	)		(4.6	)
Insurance proceeds received		50.1			—
Proceeds from sale of assets		6.0			—
Increase in restricted cash		(0.3	)		—
Deposits		(0.3	)		2.0
Other		0.7			(2.8	)

Total	$	(96.7	)	$	(117.7	)

Net cash provided by financing activities
Proceeds from borrowings	$	—		$	185.0
Payment of debt		(1.1	)		(101.0	)
Proceeds from issuance of common stock		54.2			—
Proceeds from exercise of stock options		0.3			—
(Distributions to) contributions from members		(3.7	)		4.3
Payment of debt issuance costs		(0.6	)		(6.0	)

Total	$	49.1		$	82.3

Liquidity and Financing Arrangements

Cash from operations, proceeds from our public offering of common stock in April 2006, insurance proceeds received for the loss of Rig 25, proceeds from the sale of Rig 41 and our New Iberia facility and cash on hand represented our primary source of liquidity for the nine-month period ended September 30, 2006. For the same period,

our primary uses of cash were the acquisition of Rig 26 for $20.1 million, the acquisition of six liftboats for $52.0 million, capital expenditures on our remaining fleet of $71.8 million and deferred drydocking expenditures of $9.0 million. Contributions from owners, borrowings from our creditors and our cash flow from operations represented our primary source of liquidity for the nine-month period ended September 30, 2005. For the same period, our primary uses of cash were the acquisitions of Rig 25, Rig 30, Rig 16, Rig 31, 17 liftboats and the Whale Shark.

We believe that our current cash on hand and our cash flow from operations through December 31, 2006, together with availability under our revolving credit facility and insurance recoveries, 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 refurbish and upgrade Rig 26 and Rig 31 and otherwise to operate our business. Our ability to make payments on our indebtedness and to fund planned capital expenditures in the future will depend on our ability to generate cash, which is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. Our future cash flows may be insufficient to meet all of our debt obligations and commitments, and any insufficiency could negatively impact our business. To the extent we are unable to repay our indebtedness as it becomes due or at maturity with cash on hand or from other sources, we will need to refinance our debt, sell assets or repay the debt with the proceeds from further equity offerings. Additional indebtedness or equity financing may not be available to us in the future for the refinancing or repayment of existing indebtedness, and we can provide no assurance as to the timing of any asset sales or the proceeds that could be realized by us from any such asset sale.

Cash

Cash balances as of September 30, 2006 totaled $85.0 million. This represented an increase of $37.4 million from the cash balances of $47.6 million as of December 31, 2005. The increase was due primarily to net proceeds from our public offering of common stock of $54.2 million, insurance proceeds received for the loss of Rig 25 of $48.8 million, proceeds of $3.2 million and $2.8 million from the sale of Rig 41 and our New Iberia facility and cash flow from operations of $85.0 million, partially offset by the acquisition of Rig 26 for $20.1 million, the Laborde acquisition for $49.3 million, capital expenditures on our remaining fleet of $71.8 million, deferred drydocking expenditures of $9.0 million and a payment of $3.7 million to the former members of our company for a distribution for taxes that was accrued at December 31, 2005.

Debt

Our current debt structure is used to fund our business operations, and our revolving credit facility is a source of liquidity. As of September 30, 2006, we had outstanding long-term debt of $93.6 million, including current maturities of $1.4 million.

In June 2005, we entered into a senior secured credit agreement with a syndicate of financial institutions. This agreement, as amended, provides for a $140.0 million term loan and a $75.0 million revolving credit facility. We may seek commitments to increase the amount available under the credit agreement by an additional $25.0 million if our leverage ratio, after giving effect to the incurrence of the additional $25.0 million of borrowings, is no greater than 2.5 to 1. Amounts repaid under the term loan cannot be reborrowed except pursuant to such an increase in availability.

The revolving credit facility provides for swing line loans of up to $5.0 million and for the issuance of up to $5.0 million of letters of credit. The revolving loans bear interest at a rate equal to, at our option, either (1) the highest of (a) Comerica Bank’s base rate, (b) the three-month certificate of deposit rate plus 0.5% and (c) the Federal funds effective rate plus 0.5%, in each case plus 1.25%, or (2) LIBOR plus 2.25%. We may prepay the revolving loans at any time without premium or penalty. The revolving loans mature in June 2010. We are required to pay a commitment fee of 0.375% on the average daily amount of the unused commitment amount of the revolving credit facility and a letter of credit fee of 2.25%, plus a fronting fee of 0.125%, with respect to the undrawn amount of each issued letter of credit. As of September 30, 2006, no amounts were outstanding and no letters of credit had been issued under the revolving credit facility.

The term loan bears interest at a rate equal to, at our option, either (1) the highest of (a) Comerica Bank’s base rate, (b) the three-month certificate of deposit rate plus 0.5% and (c) the Federal funds effective rate plus 0.5%, in each case plus 2.25%, or (2) LIBOR plus 3.25%. As of September 30, 2006, $93.6 million of the principal amount of the term loan was outstanding, and the interest rate was 8.76%. In accordance with the credit agreement, in July 2005, we entered into hedge transactions with the purpose and effect of fixing the interest rate on $70.0 million of the outstanding principal amount of the term loan at 7.54% for three years. In addition, we entered into hedge transactions with the purpose and effect of capping the interest rate on an additional $20.0 million of such principal amount at 8.25% for three years. Principal payments of $350,000 are due quarterly, and the outstanding principal balance of the term loan is payable in full in June 2010. We may prepay the term loan at any time without premium or penalty, except that prepayments made before December 31, 2006 with proceeds from debt issuances or in connection with a repricing of the term loan will be made at 101% of the principal repaid.

We are required to prepay the term loan with:

•

the proceeds from sales of certain assets;

•

the proceeds from casualties or condemnations of assets to the extent that the net cash proceeds from any such casualty or condemnation exceed $1.0 million and are not reinvested within one year;

•

the net proceeds of certain debt for borrowed money;

•

25% of the net proceeds of any public or private offering of our equity securities, provided that holders of the term loan may reject the mandatory prepayment; and

•

50% of excess cash flow if either our leverage ratio is above 3.0 to 1.0 or the outstanding principal balance of the term loan is greater than $110.0 million.

Our obligations under the credit agreement are secured by our liftboats, all of our domestic rigs and substantially all of our other personal property, including all the equity of our domestic subsidiaries and 65% of the equity of certain of our foreign subsidiaries. All of our domestic material subsidiaries guarantee our obligations under the agreement and have granted similar liens on substantially all of their assets. Our foreign subsidiaries are not guarantors, and the assets owned by our foreign subsidiaries are not held as collateral for the loans.

The credit agreement contains financial covenants relating to leverage, fixed charge coverage and collateral coverage. Other covenants contained in the agreement restrict, among other things, repurchases of equity interests, mergers, asset dispositions, guaranties, debt, liens, acquisitions, dividends, distributions, investments, affiliate transactions, prepayments of other debt and capital expenditures. The credit agreement permits us to make advances to and investments in our foreign subsidiaries provided we meet applicable financial covenants. We are currently in compliance in all material respects with our covenants under the credit agreement. The credit agreement contains customary events of default.

As of September 30, 2006, we had a letter of credit supported by a restricted cash deposit of $250,000 issued outside of the revolving credit facility.

Capital Expenditures

We expect to spend approximately $80.5 million in 2006 on the refurbishment and upgrade of our rigs and liftboats. Rigs or liftboats that have been idle for long periods of time will often require a substantial amount of work to restore the rig or liftboat into operating condition. This often entails replacing or rebuilding much of the operating equipment, and is often costly. We describe this process as a refurbishment, and we capitalize the costs of restoring a unit to operating condition.

We differentiate a refurbishment from an upgrade, in which we materially increase 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 2006, 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 $9.3 million in the fourth quarter of 2006 and an additional $12.4 million in 2007 to complete the upgrade. 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 2005 and the first nine months of 2006, estimated amounts for the remainder of 2006 and total estimated amounts for the project.


(in millions)	2005 Expenditures		Expenditures – Nine Months Ended Sept. 30, 2006		Estimated Remaining Expenditures		Total Expenditures or Estimated Expenditures		Completion or Expected Completion
Rig 16 refurbishment and upgrade	$	5.7	$	10.3	$	—	$	16.0	June 2006
Rig 31 refurbishment and upgrade		2.9		22.6		—		25.5	Third Quarter 2006
Rig 26 refurbishment and upgrade		—		18.4		21.7		40.1	Second Quarter 2007
Rig 21 additional upgrades (not covered by insurance claim for damage)		0.3		5.0		—		5.3	Second Quarter 2006
Corina and Pike refurbishments (inactive liftboats acquired in June 2005)		—		1.4		0.6		2.0	Fourth Quarter 2006
Remora refurbishment		—		0.8		0.2		1.0	Fourth Quarter 2006
Commissioning of Whale Shark		0.5		—		—		0.5	First Quarter 2006
Drydockings of liftboats		7.4		9.0		4.7		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, 2005, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Liquidity and Financing Arrangements — Contractual Obligations” in Item 7 of our annual report on Form 10-K for the year ended December 31, 2005. Except with respect to (1) our agreement with Halliburton to acquire its West Africa liftboat fleet and (2) our insurance note payable, in each case as described above under “-Recent Developments” there have been no material changes to such disclosure regarding our contractual obligations made in the annual report.

Accounting Pronouncements

In June 2006, the Financial Accounting Standards Board 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 is effective for fiscal years beginning after December 15, 2006 and we intend to adopt FIN 48 in the first quarter of 2007. We are evaluating FIN 48 and have not yet determined the impact on our consolidated balance sheet, statement of operations or statement of cash flow.

In September 2006, the Securities and Exchange Commission staff issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements in Current Year Financial Statements” (“SAB 108”). SAB 108 was issued to provide consistency with respect to the manner in which companies quantify financial statement misstatements. SAB 108 establishes an approach that requires companies to quantify misstatements in financial statements based on effects of the misstatement on both the consolidated balance sheet and statement of operations and the related financial statement disclosures. Additionally, companies are required to evaluate the cumulative effect of errors existing in prior years that previously had been considered immaterial. Adoption of SAB 108 is encouraged for interim periods of the first fiscal year beginning after November 15, 2006 and we intend to apply SAB 108 in connection with the preparation of our annual financial statements for the year ended December 31, 2006. We are evaluating the requirements of SAB 108 and it will have no impact on our consolidated balance sheet, statement of operations or statement of cash flow.

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;

•

amounts expected to be paid by insurance proceeds for Rig 21 and the salvage of Rig 25;

•

expected completion times for our refurbishment and upgrade projects;

•

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

•

our plans regarding increased international operations;

•

expected useful lives of our rigs and liftboats;

•

liabilities under laws and regulations protecting the environment;

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

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

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, 2005 and Item 1A of Part II of this quarterly report and the following:

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

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demand for offshore jackup rigs and liftboats;

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

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

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the impact of governmental laws and regulations;

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the adequacy of sources of liquidity;

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

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

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the availability of skilled personnel;

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labor relations and work stoppages, particularly in the Nigerian labor environment;

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

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the effect of litigation and contingencies; and

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

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, 2005. There have been no material changes to the disclosure regarding our exposure to certain market risks made in the annual report. For additional information regarding our long-term debt, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Liquidity and Financing Arrangements — Debt” in Item 2 of Part I of this quarterly report.

ITEM 4. CONTROLS AND PROCEDURES

We carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and President and 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, our Chief Executive Officer and President and our Chief Financial Officer concluded that, as of September 30, 2006, 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 1A. RISK FACTORS

Except as disclosed in Item 1A of Part II of our quarterly report on Form 10-Q for the quarterly period ended March 31, 2006 and in this quarterly report on Form 10-Q, 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, 2005:

The terms of some of our dayrate drilling contracts may limit our ability to benefit from increasing dayrates in an improving market.

Although historically our offshore drilling contracts in the U.S. Gulf of Mexico generally have been on a short-term basis, from time to time, and particularly in international markets, we may enter into longer term contracts. The duration of offshore drilling contracts is generally determined by market demand and the strategies of the offshore drilling contractors and their customers. In periods of rising demand for offshore rigs, a drilling contractor generally would prefer to enter into well-to-well or other shorter term contracts that would allow the contractor to profit from increasing dayrates, while customers with reasonably definite drilling programs would typically prefer longer term contracts in order to maintain dayrates at a consistent level. Conversely, in periods of decreasing demand for offshore rigs, a drilling contractor generally would prefer longer term contracts to preserve dayrates and utilization, while customers generally would prefer well-to-well contracts or other shorter term contracts that would allow the customer to benefit from the decreasing dayrates. Our inability to fully benefit from increasing dayrates in an improving market, due to the long-term nature of some of our contracts, may adversely affect our profitability.

Our drilling and liftboat contracts may be terminated due to events beyond our control.

Our customers may terminate some of our drilling and liftboat contracts if the unit is destroyed or lost or if operations are suspended for a specified period of time as a result of a breakdown of our equipment, or due to events beyond the control of either party. In some cases, our drilling contracts and liftboat contracts may be terminable upon specified advance notice from the customer and, after some termination payment (which would not fully compensate us for the loss of the contract). Early termination of a contract may result in a rig or liftboat being idle for an extended period of time, which could adversely affect our financial position, results of operations and cash flows.

We are subject to additional political, economic, and other uncertainties as our international operations have expanded.

An element of our business strategy is to continue to expand into international oil and natural gas producing areas such as West Africa, the Middle East and the Asia-Pacific region, including India. We currently own or operate 17 liftboats operating offshore Nigeria and Cameroon, one rig operating offshore Qatar and one operating offshore India, and we are marketing Rig 26 to work in international markets following completion of the refurbishment and upgrade project on that rig. Our international operations are subject to a number of risks inherent in any business operating in foreign countries, including:

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

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potential seizure or nationalization of assets;

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damage to our equipment or violence directed at our employees;

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increased operating costs;

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complications associated with repairing and replacing equipment in remote locations;

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modification or renegotiation of contracts;

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

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import-export quotas;

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confiscatory taxation;

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work stoppages, particularly in the Nigerian labor environment;

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restrictions on currency repatriations;

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currency fluctuations and devaluations; and

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

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

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

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

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

ITEM 6. EXHIBITS


10.1		Asset Purchase Agreement, dated August 23, 2006, by and between Hercules International Holdings, Ltd. and Halliburton West Africa Limited and Halliburton Energy Services Nigeria Limited.

10.2		First Amendment to Asset Purchase Agreement, dated November 1, 2006, by and between Hercules International Holdings, Ltd., Halliburton West Africa Limited, Halliburton Energy Services Nigeria Ltd., and Hercules Oilfield Services Ltd.

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/ Steven A. Manz
		Steven A. Manz
		Chief Financial Officer

Date: November 7, 2006