Edgar Filing: HERCULES OFFSHORE, INC.

Form 10-Q for the Quarterly Period Ended September 30, 2005

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, 2005

¨	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 ¨ NO x

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). YES ¨ NO 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 practical date.


		Outstanding as of December 6, 2005
Common Stock, par value $0.01 per share		30,242,850

HERCULES OFFSHORE, INC.

INDEX


		Page No.
PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements

	Consolidated Balance Sheets at September 30, 2005 and December 31, 2004 (unaudited)	2

	Consolidated Statements of Operations for the three months ended September 30, 2005, the period from inception (July 27, 2004) to September 30, 2004 and the nine months ended September 30, 2005 (unaudited)	3

	Consolidated Statements of Cash Flows for the nine months ended September 30, 2005 and the period from inception (July 27, 2004) to September 30, 2004 (unaudited)	4

	Consolidated Statements of Comprehensive Income for the three months ended September 30, 2005, the period from inception (July 27, 2004) to September 30, 2004 and the nine months ended September 30, 2005 (unaudited)	5

	Notes to Unaudited Consolidated Financial Statements	6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	32

Item 4.	Controls and Procedures	32

PART II.	OTHER INFORMATION

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	33

Item 5.	Other Information	33

Item 6.	Exhibits	34

Signatures		35

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except unit data)

(Unaudited)


	September 30, 2005		December 31, 2004
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	16,756	$	14,460
Accounts receivable, net		35,506		19,501
Deposits		33		2,032
Assets held for sale		2,040		—
Prepaid expenses and other		6,506		2,359

Total current assets		60,841		38,352
PROPERTY AND EQUIPMENT, net		197,919		91,774
OTHER ASSETS		7,334		2,030

Total assets	$	266,094	$	132,156

LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES
Current portion of long-term debt	$	1,400	$	3,000
Accounts payable		6,621		1,838
Accrued liabilities		9,898		2,548
Other liabilities		4,175		683

Total current liabilities		22,094		8,069
LONG-TERM DEBT, net of current portion		138,600		53,000
COMMITMENTS AND CONTINGENCIES
MEMBERS’ EQUITY
Member units (68,351 and 64,022 units issued and outstanding)		67,351		63,022
Accumulated other comprehensive income		322		—
Retained earnings		37,727		8,065

Total members’ equity		105,400		71,087

Total liabilities and members’ equity	$	266,094	$	132,156

The accompanying notes are an integral part of these statements.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except unit and share data)

(Unaudited)


	Three Months Ended September 30, 2005			Period from inception (July 27, 2004) to September 30, 2004			Nine Months Ended September 30, 2005
REVENUES
Contract drilling services	$	28,248		$	8,405		$	79,427
Marine services		13,937			—			33,888

		42,185			8,405			113,315
COSTS AND EXPENSES
Operating expenses for contract drilling services, excluding depreciation and amortization		14,043			4,805			37,379
Operating expenses for marine services, excluding depreciation and amortization		7,757			—			18,184
Depreciation and amortization		3,753			425			9,075
General and administrative, excluding depreciation and amortization		4,031			449			9,136

		29,584			5,679			73,774

OPERATING INCOME		12,601			2,726			39,541
OTHER INCOME (EXPENSE)
Interest expense		(2,735	)		(648	)		(7,572	)
Loss on early retirement of debt		—			—			(2,786	)
Other, net		244			63			479

NET INCOME	$	10,110		$	2,141		$	29,662

EARNINGS PER UNIT:
Basic	$	147.91		$	100.88		$	435.20
Diluted	$	143.66		$	100.88		$	426.80
WEIGHTED AVERAGE UNITS OUTSTANDING:
Basic		68,351			21,221			68,158
Diluted		70,373			21,221			69,500

EARNINGS PER SHARE AS CONVERTED (SEE NOTE 2):
Basic	$	0.42		$	0.29		$	1.24
Diluted	$	0.41		$	0.29		$	1.22
WEIGHTED AVERAGE SHARES OUTSTANDING AS CONVERTED (SEE NOTE 2):
Basic		23,922,850			7,427,280			23,855,353
Diluted		24,630,628			7,427,280			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, 2005			Period from inception (July 27, 2004) to September 30, 2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	29,662		$	2,141
Adjustments to reconcile net income to net cash provided by (used in) operating activities
Depreciation and amortization		9,075			425
Amortization of deferred financing fees		714			70
Recovery of bad debts		(519	)		—
Loss on early retirement of debt		2,786			—
Increase in operating assets—
Increase in receivables		(15,293	)		(7,889	)
Increase in prepaid expenses and other		(4,340	)		(3,030	)
Increase in operating liabilities—
Increase in accounts payable		4,783			1,388
Increase in accrued liabilities		7,350			1,443
Increase in other liabilities		3,492			1,196

Net cash provided by (used in) operating activities		37,710			(4,256	)

CASH FLOWS FROM INVESTING ACTIVITIES
Purchase of property and equipment		(115,571	)		(40,195	)
Proceeds from disposal of assets, net of commissions		454			—
Deferred drydocking expenditures		(4,617	)		—
Decrease (increase) in deposits		1,999			(57	)

Net cash used in investing activities		(117,735	)		(40,252	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings		185,000			28,000
Payment of debt		(101,000	)		—
Payment of debt issuance costs		(6,008	)		(1,034	)
Contributions from members		4,329			22,050

Net cash provided by financing activities		82,321			49,016

NET INCREASE IN CASH AND CASH EQUIVALENTS		2,296			4,508

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		14,460			—

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	16,756		$	4,508

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, 2005		Period from inception (July 27, 2004) to September 30, 2004		Nine Months Ended September 30, 2005
NET INCOME	$	10,110	$	2,141	$	29,662

OTHER COMPREHENSIVE INCOME (LOSS)
Unrealized gains on hedge transactions		322		—		322

COMPREHENSIVE INCOME	$	10,432	$	2,141	$	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. All of the financial results reported in this Quarterly Report on Form 10-Q predate this Conversion. Unless the context indicates otherwise, references to the “Company” are to Hercules Offshore, LLC for periods prior to the Conversion and to Hercules Offshore, Inc. for periods after the Conversion.

The Company provides shallow-water drilling and liftboat services to the oil and gas exploration and production industry primarily in the U.S. Gulf of Mexico through its Contract Drilling Services and Marine Services segments. The Company owns, through its subsidiaries Hercules Drilling, LLC (“Drilling”) and Hercules Liftboats, LLC (“Liftboats”), nine jackup drilling rigs, one platform rig and 46 liftboat vessels. One of the jackup rigs was severely damaged in a hurricane and is likely to be declared a constructive total loss.

For the period from inception (July 27, 2004) to September 30, 2004 (“period from inception to September 30, 2004”), the Company owned five jackup drilling rigs and four platform rigs that were purchased from Parker Drilling Company (“Parker”) on August 2, 2004 for $39,250,000. The consolidated results of operations for the period from inception to September 30, 2004 include the operation during such period of the five jackup rigs acquired from Parker. Three of the four platform rigs were sold in November 2004 and the fourth was classified as an asset held for sale as of September 30, 2005 (see Assets Held for Sale).

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, 2005, and the results of its operations and cash flows for the nine months ended September 30, 2005 and the period from inception to September 30, 2004 have been reflected. The consolidated results of operations for the nine months ended September 30, 2005 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 prospectus dated October 26, 2005 included in the Company’s registration statement on Form S-1 (Registration No. 333-126457) declared effective on October 26, 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.

Cash and Cash Equivalents

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

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Revenue Recognition

Revenue generated from the operation of the Company’s drilling rigs and liftboats is recognized under dayrate contracts as services are performed. Certain contracts include provisions for the recovery of direct costs, including mobilization and demobilization costs, extra labor and extra catering. Under most of its liftboat contracts, the Company receives a variable rate for reimbursement of costs such as catering, fuel, rental equipment and other items. Revenue for recovery of these costs is recognized when the costs are incurred. 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 records reimbursements from customers for “out-of-pocket” expenses as revenues and the related cost as direct operating expenses. Total revenues from such reimbursements included $1,371,656, $218,611 and $3,698,578 for the three months ended September 30, 2005, the period from inception to September 30, 2004 and the nine months ended September 30, 2005, respectively.

Stock-Based Compensation

Stock-based compensation arrangements are accounted for using 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. Accordingly, compensation cost for options granted to employees is measured as the excess, if any, of the fair value of shares at the date of grant over the exercise price an employee must pay to acquire the shares. No compensation cost has been recognized in the accompanying consolidated financial statements. Had the Company determined compensation cost using the alternative fair value method prescribed by SFAS No. 123 described below, pro forma net income would not be materially different than that reported in the accompanying financial statements.

In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 123 (revised 2004) Share-Based Payment (“SFAS No. 123R”), which replaces SFAS No. 123, Accounting for Stock-Based Compensation and supersedes APB Opinion 25. SFAS No. 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on the fair values beginning with the first interim period in fiscal year 2006, with early adoption encouraged. The pro forma disclosures previously permitted under SFAS No. 123 no longer will be an alternative to financial statement recognition. The Company is required to adopt SFAS No. 123R in the first quarter of fiscal year 2006. Under SFAS No. 123R, the Company must determine the appropriate fair value model to be used for valuing share-based payments, the amortization method for compensation cost and the transition method to be used at date of adoption. The transition methods include prospective or retroactive adoption options. Under the retroactive option, prior periods may be restated either as of the beginning of the year of adoption or for all periods presented. The prospective method requires that compensation expense be recorded for all unvested stock options and restricted stock as the requisite service is rendered on or after the required effective date beginning with the first quarter of adoption of SFAS No. 123R , while the retroactive methods would record compensation expense for all unvested stock options and restricted stock beginning with the first period restated. The Company is evaluating the requirements of SFAS No. 123R and expects to adopt the standard using the prospective method.

The impact that the adoption of SFAS No. 123R will have on the Company’s consolidated statement of operations will be determined primarily by the number of stock options granted to employees in future periods. Options granted prior to the Company’s initial public offering in November 2005 (see NOTE 9) will continue to be accounted for using the intrinsic value method and, as such, the Company will incur no compensation expense for them upon adoption of SFAS No. 123R.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Allowance for Doubtful Accounts

Management of the Company monitors the accounts receivable from its customers for any collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent factors. Accounts deemed uncollectable are charged to the allowance. During the period from inception (July 27, 2004) to December 31, 2004, the Company recorded a provision for bad debts of $519,165. During the second quarter of 2005, the Company recorded an additional provision for bad debts of $318,967. The Company received payment for the full amount of the receivable of $838,132 during September 2005, and the allowance was reversed. There was no allowance at September 30, 2005.

Property and Equipment

Property and equipment are stated at cost, less accumulated depreciation. Expenditures for property and equipment and items that substantially increase the useful lives of existing assets are capitalized at cost and depreciated. Routine expenditures for repairs and maintenance are expensed as incurred, except for expenditures for drydocking the Company’s liftboats. Drydock costs are capitalized at cost in other non-current assets on the consolidated balance sheet and amortized on the straight-line method (see below). Depreciation is computed using the straight-line method over the useful lives of the assets.

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”. During the first quarter of 2005, the Company’s Contract Drilling Services segment committed to a plan to sell Rig 41, a platform rig, in connection with the Company’s efforts to dispose of certain non-strategic assets. The rig has been idle since being acquired on August 2, 2004. The rig was classified as an asset held for sale in March 2005. The estimated fair value of the rig less its selling costs exceeded the rig’s carrying value of approximately $2,000,000 at September 30, 2005 and, as such, no loss has been recognized for the three or nine months ended September 30, 2005. In October 2005, the Company entered into a definitive agreement to sell Rig 41 for $3,443,750, net of commissions, and received a non-refundable deposit of $181,250. The Company expects the sale of the rig to close in the first quarter of 2006, and anticipates that a gain on the sale of the rig will be recorded at that time. During the second quarter of 2005, the Company’s Marine Services segment committed to a plan to sell the Moonfish, a liftboat, in connection with the Company’s effort to dispose of certain non-strategic assets. The liftboat had been idle since being acquired on June 1, 2005. The Moonfish was sold in August 2005. No gain or loss was recognized on the transaction.

Other Assets

Other assets consist of drydocking costs for liftboats, financing fees and unrealized gain on hedge transactions. The drydock costs are capitalized at cost and amortized on the straight-line method over 12 months. Drydocking costs, net of accumulated amortization, at September 30, 2005 and December 31, 2004 were $2,926,496 and $452,256, respectively. Accumulated amortization of drydocking costs at September 30, 2005 and December 31, 2004 was $2,006,778 and $149,228, respectively. Amortization expense for drydocking costs was $1,148,595, $0 and $2,142,795 for the three months ended September 30, 2005, the period from inception to September 30, 2004 and the nine months ended 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, 2005 were $4,085,389, net of accumulated amortization of $222,030. Unamortized deferred financing fees at December 31, 2004 were $1,577,793, net of accumulated amortization of $215,283. All unamortized deferred financing fees outstanding at December 31, 2004 were expensed in conjunction with the refinancing of the Company’s long-term debt in June 2005, and the portion outstanding as of the date of the refinancing, totaling $2,190,709, is included in the loss on early retirement of debt in the statement of operations for the nine months ended September 30, 2005. 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 $222,030,

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

$70,307 and $714,071 for the three months ended September 30, 2005, the period from inception to September 30, 2004 and the nine months ended September 30, 2005, respectively. All financing fees at September 30, 2005 and December 31, 2004 relate to debt obtained through credit agreements dated July 30, 2004, October 1, 2004 and June 29, 2005 (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 5). The cumulative unrealized gain on these hedging instruments was $321,504 at September 30, 2005 and is recorded in other assets and accumulated other comprehensive income on the consolidated balance sheet (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 is included in the Company’s accompanying financial statements. When the Company became a taxable entity in the Conversion, a provision of approximately $10,800,000 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.

Use of Estimates

In preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management makes estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Fair Value of Financial Instruments

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

NOTE 2 – EARNINGS PER UNIT AND EARNINGS PER SHARE AS CONVERTED

The following tables reconcile the computations of the basic and diluted earnings per unit and the basic and diluted earnings per share, as converted, for the three and nine months ended September 30, 2005 and the period from inception to September 30, 2004:


	Net Income		Basic Units	Basic Earnings per Unit		Diluted Units	Diluted Earnings per Unit
Three Months Ended September 30, 2005	$	10,110	68,351	$	147.91	70,373	$	143.66
Period from Inception to September 30, 2004	$	2,141	21,221	$	100.88	21,221	$	100.88
Nine Months Ended September 30, 2005	$	29,662	68,158	$	435.20	69,500	$	426.80

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS



	Net Income		Basic Shares	Basic Earnings per Share		Diluted Shares	Diluted Earnings per Share
Three Months Ended September 30, 2005	$	10,110	23,922,850	$	0.42	24,630,628	$	0.41
Period from Inception to September 30, 2004	$	2,141	7,427,280	$	0.29	7,427,280	$	0.29
Nine Months Ended September 30, 2005	$	29,662	23,855,353	$	1.24	24,324,935	$	1.22

The Company calculates earnings per unit and earnings per share by dividing net income by the weighted average number of units or shares outstanding. 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 unit and 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 units are excluded from the calculation of the dilutive effect of stock options for diluted earnings per unit and earnings per share calculations. On a member units basis, there were no options outstanding with dilutive effects for the period from inception to September 30, 2004 and there were 2,022 and 1,342 options outstanding with dilutive effects for the three and nine month periods ended September 30, 2005, respectively. On a share basis, there were no options outstanding with dilutive effects for the period from inception to September 30, 2004 and there were 707,778 and 469,582 options outstanding with dilutive effects for the three and nine month periods ended September 30, 2005, respectively.

NOTE 3 – ASSET ACQUISITIONS

During January 2005, the Company completed the purchase of two jackup drilling rigs, Rig 25 and Rig 30, for $21,500,000 and $20,000,000, respectively. These purchases were partially funded by a $25,000,000 term loan under the Lehman Credit Agreement (as defined in NOTE 5 below). In connection with this new term loan, the Lehman Credit Agreement was amended in January 2005 to increase the amount of credit available to the Company from $28,000,000 to $53,000,000 (see NOTE 5).

In June 2005, the Company purchased 17 liftboats from Superior Energy Services, Inc. for $19,725,000. One of these liftboats was being held for sale and was sold in August 2005 (see NOTE 1). The transaction was funded by an increase in the Company’s term loan under the Comerica Credit Agreement (as defined in NOTE 5), which was amended to increase the amount of credit available to the Company under the term loan to $47,000,000. In June 2005, the Company purchased a jackup rig, Rig 16, from Transocean, Inc. for $20,000,000. A $2,000,000 refundable escrow account was funded by the Company in May 2005. The Company funded the purchase price with proceeds from its new term loan under the Company’s senior secured credit agreement (see NOTE 5).

In August 2005, the Company purchased the liftboat Whale Shark from CS Liftboats, Inc. for $12,500,000. The Company funded the purchase with available cash.

In September 2005, the Company purchased Rig 31 from Hydrocarbon Capital II LLC for $12,600,000. The Company funded the purchase with available cash.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

In September 2005, the Company entered into a definitive purchase agreement to acquire eight liftboats and related assets from Danos and Curole Marine Contractors LLC for $44,000,000. The transaction closed in November 2005. See NOTE 9.

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 $14,000 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 $299,440, $13,750 and $669,746 for the three months ended September 30, 2005, for the period from inception to September 30, 2004 and the nine months ended September 30, 2005, respectively.

NOTE 5 – LONG-TERM DEBT

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


	September 30, 2005		December 31, 2004
Senior secured term loan due June 2010	$	140,000		—
12.5% senior secured term loan (Lehman) due December 2006		—	$	28,000
Senior secured term loan (Comerica) due October 2009		—		28,000

Total debt		140,000		56,000
Less debt due within one year		1,400		3,000

Total long-term debt	$	138,600	$	53,000

Lehman Commercial Paper Inc. term loan

On July 30, 2004, Drilling entered into a credit agreement with Lehman Commercial Paper Inc. (the “Lehman Credit Agreement”) providing for a $28,000,000 term loan. On January 4, 2005, the Lehman Credit Agreement was amended, providing for an additional $25,000,000 term loan, which increased the total amount outstanding under the Lehman Credit Agreement to $53,000,000. The term loan bore interest at 12.5% per annum with interest payable monthly. The term loan was repaid in full in June 2005.

Comerica Bank term loan

On October 1, 2004, Liftboats entered into a credit agreement with Comerica Bank providing for a $28,000,000 term loan and a $4,000,000 revolving credit line (the “Comerica Credit Agreement”). At December 31, 2004, the entire balance of the term loan was outstanding and no amount was drawn on the revolving credit line. The term loan and the revolving credit line bore interest at a prime rate determined by the agent to the Comerica Credit Agreement plus a margin derived from the ratio of funded debt to EBITDA. The average interest rates for the period ended December 31, 2004 were approximately 5.7 percent under the term loan and 6.1 percent under the revolving credit line. The Comerica Credit Agreement was amended on June 1, 2005 to increase the amount of credit available to Liftboats by $20,000,000, of which $19,725,000 was used to fund the Superior liftboat acquisition (see NOTE 3). The term loan was repaid in full in June 2005.

Senior secured credit agreement

In June 2005, the Company entered into a senior secured credit agreement with a syndicate of financial institutions. This agreement provides for a $140,000,000 term loan and a $25,000,000 revolving credit facility. The Company may seek commitments to increase the amount available under the credit agreement by an additional $25,000,000 if the amount outstanding under the term loan is no more than $105,000,000 and the Company’s leverage ratio, after giving effect to the incurrence of the additional $25,000,000 of borrowings, is no greater than 2.5 to 1.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

The revolving credit facility provides for swing line loans of up to $2,500,000 and for the issuance of up to $5,000,000 of letters of credit. The revolving loans bear interest at a rate equal to, at the option of the Company, 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%. The Company may repay the revolving loans at any time without premium or penalty. The revolving loans mature in June 2008. The Company is required to pay a commitment fee of 0.50% on the average daily amount of the unused commitment amount of the revolving credit facility and a letter of credit fee of 3.25%, plus a fronting fee of 0.13% with respect to the undrawn amount of each issued letter of credit. As of September 30, 2005, 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 the option of the Company, 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%. Principal payments of $350,000 are due quarterly, and the outstanding principal balance of the term loans is payable in full in June 2010. The Company may prepay the term loans at any time without premium or penalty, except that the prepayments made during the first year with proceeds for debt issuance or in connection with a repricing of the term loan will be made at 101% of the principal repaid. The Company is required to make prepayments on the term loan in certain cases. As of September 30, 2005, the entire principal amount of the original $140,000,000 term loan was outstanding and the interest rate was 6.82%. The Company used $45,000,000 of the proceeds from its initial public offering in November 2005 to repay a portion of the outstanding principal amount. See NOTE 9.

The credit agreement contains financial covenants relating to leverage and interest 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. Management believes that the Company is in compliance in all material respects with its covenants under the credit agreement. The credit agreement contains customary events of default.

Amounts outstanding under the Lehman Credit Agreement and Comerica Credit Agreement were repaid with proceeds from the new senior secured term loan, and the Company terminated the credit agreements upon the repayment. All unamortized deferred financing fees outstanding at December 31, 2004 were expensed in conjunction with the refinancing of the Company’s long-term debt in June 2005, and the portion outstanding as of the date of the refinancing is included in loss on early retirement of debt in the consolidated statements of operations.

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 cumulative net unrealized

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

gain on these hedging instruments was $321,504 at September 30, 2005 and is included in other assets and accumulated other comprehensive income in the consolidated balance sheet at September 30, 2005. 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.

NOTE 7 – SEGMENTS

The Company’s operations are aggregated into two reportable segments: (i) Contract Drilling Services and (ii) Marine Services. The Contract Drilling Services segment consists of jackup rigs used in support of offshore drilling activities. The Marine Services segment consists of liftboats used in offshore support services. Accounting policies of the segments are the same as those described under “Nature of Business and Significant Accounting Policies” in NOTE 1. The Company eliminates intersegment revenue and expenses, if any.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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

Three Months Ended September 30, 2005


	Contract Drilling Services			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)		(1,868	)		(919	)		52			(2,735	)
Other, net		147			34			63			244

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

Total property and equipment, net of accumulated depreciation (at end of period)	$	114,436		$	83,306		$	177		$	197,919

(1)	Interest expense for Corporate and Other includes a reclassification of interest expense from a prior period to the Contract Drilling Services segment.

Period from Inception to September 30, 2004


	Contract Drilling Services			Marine Services		Corporate and Other		Total
Revenues	$	8,405		$	—	$	—	$	8,405
Operating expenses, excluding depreciation and amortization		4,805			—		—		4,805
Depreciation and amortization		425			—		—		425
General and administrative, excluding depreciation and amortization		449			—		—		449

Operating income		2,726			—		—		2,726
Interest expense		(648	)		—		—		(648	)
Other, net		63			—		—		63

Net income	$	2,141		$	—	$	—	$	2,141

Total property and equipment, net of accumulated depreciation (at end of period)	$	39,770		$	—	$	—	$	39,770

Nine Months Ended September 30, 2005


	Contract Drilling Services			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

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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 physical damage, third party liability, maritime employers liability, pollution and other coverage. The primary marine package provides for hull and machinery coverage for the Company’s rigs and liftboats up to a scheduled value for each asset. Rig coverages include a $1.0 million deductible per occurrence; liftboat deductibles vary from $150,000 to $500,000 per occurrence, depending on the insured value of the particular vessel. There is no deductible in the event of a total loss of the vessel. The protection and indemnity coverage under the primary marine package has a $5.0 million limit per occurrence with excess liability up to $100.0 million. The primary marine package also provides coverage for cargo and charterer’s legal liability. Vessel pollution is covered under a Water Quality Insurance Syndicate policy. In addition to the marine package, the Company has separate policies providing coverage for general domestic liability, employer’s liability, domestic auto liability and non-owned aircraft liability, with customary deductibles and coverage. Insurance premiums under the Company’s program are approximately $5.5 million for the twelve-month policy period ending July 31, 2006.

Recent Hurricanes

In August 2005, two of the Company’s jackup rigs, Rig 21 and Rig 25, sustained damage during Hurricane Katrina. The Company believes that Rig 25 is likely to be declared a constructive total loss under its insurance policies. If the rig is not declared a constructive total loss, the rig would require substantial repairs before returning to work. The Company does not believe that it could complete such repairs prior to 2007. Salvage efforts are still ongoing on Rig 25. Rig 21 suffered extensive damage to its mat as a result of the storm. The rig is currently in drydock in a shipyard in Pascagoula, Mississippi undergoing repairs to a section of the mat. The rig is expected be ready for service in the second quarter of 2006 and all repairs are expected to be within insured values. As a result of the damage to Rig 21, the Company recognized a $1,000,000 loss in the three and nine months ended September 30, 2005 representing its insurance deductible. The loss is included in operating expenses for drilling services in the consolidated statements of operations.

NOTE 9 – SUBSEQUENT EVENTS

Initial Public Offering

The Company completed its initial public offering of 10,580,000 shares of common stock at $20.00 per share on November 1, 2005. The Company offered 6,250,000 shares of common stock, while the remaining 4,330,000 shares were offered by selling stockholders. The Company received approximately $115.1 million of proceeds from the offering, net of underwriting discounts and commissions and estimated expenses. The Company used $44,000,000 of the proceeds to complete the acquisition of a fleet of liftboats from Danos & Curole Marine Contractors, LLC (“Danos & Curole”), discussed below. In addition, the Company repaid $45,000,000 of the senior secured term loan plus accrued interest of $273,750, discussed below. The remaining proceeds are being used for general corporate purposes, including refurbishment of and upgrades to Rig 16 and Rig 31.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Liftboat Acquisitions from Danos & Curole

In November 2005, the Company completed the acquisition of a fleet of liftboats and related assets from Danos & Curole for $44,000,000. Three of these liftboats are located in the U.S. Gulf of Mexico and are currently operating under short-term contracts. Four liftboats are currently operating in Nigeria. Danos & Curole will continue to operate these four vessels under an operating agreement until the Company has established its own operations in Nigeria. This operating agreement expires in September 2006 and can be terminated earlier by the Company upon 30 days’ notice to Danos & Curole.

An additional liftboat subject to the purchase agreement, the Andre Danos, was damaged as a result of Hurricane Katrina. Danos & Curole is currently salvaging the vessel. The Company has agreed to reimburse Danos & Curole up to $500,000 of the salvage costs. Danos & Curole insured the Andre Danos for $3,600,000, with a deductible of $1,500,000. Once the vessel is salvaged, Danos & Curole and its insurers will determine whether the vessel is a constructive total loss or can be repaired. If the vessel is determined to be a constructive total loss, a portion of the $44,000,000 purchase price equal to the amount of insurance proceeds Danos & Curole recovers, net of the deductible, will be refunded by Danos & Curole to the Company. However, if the vessel can be repaired, Danos & Curole will conduct the repairs until the insurance proceeds received are completely expended, and will thereafter deliver the vessel to the Company in such condition without additional payment of any consideration. The Company believes the liftboat is likely to be declared a constructive total loss.

Senior Secured Term Loan Paydown

In November 2005, the Company repaid $45,000,000 of the principal amount outstanding under its senior secured term loan. The Company paid $273,750 of accrued interest and expensed $1,291,921 of debt issuance costs in connection with the repayment. The Company will record a loss from the early retirement of debt in the fourth quarter of 2005 of $1,291,921.

Rig Sale Agreement

In November 2005, the Company entered into a definitive agreement to sell Rig 41 for $3,443,750, net of commissions. The buyer paid a $181,250 non-refundable deposit, and the Company expects the sale to close in the first quarter of 2006. The Company expects to recognize a gain of approximately $1,400,000 on the sale for the excess of the purchase price over the rig’s carrying value.

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, 2005 and for the three and nine months ended September 30, 2005 and for the period from inception (July 27, 2004) to September 30, 2004 (“period from inception to September 30, 2004”) included elsewhere herein. The following information contains forward-looking statements. Please read “Forward-Looking Statements” below for a discussion of certain limitations inherent in such statements.

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 two business segments, Contract Drilling Services and Marine Services:

•

Contract Drilling Services. We own a fleet of nine jackup rigs, eight of which are capable of drilling in maximum water depths ranging from 85 to 250 feet. The other rig was severely damaged in Hurricane Katrina as described below and is likely to be declared a constructive total loss under our insurance policies. Under most of our contract drilling service agreements, we are paid a fixed daily rental rate called a “dayrate,” and we are required to pay all costs associated with our own crews as well as the upkeep and insurance of the rig and equipment.

•

Marine Services. We own a fleet of 46 liftboats with leg lengths ranging from 105 to 260 feet. Our liftboats are used to provide a wide range of offshore support services, including platform maintenance, platform construction, well intervention and decommissioning services, and can be moved from location to location within a short period of time. Under most of our liftboat contracts, we are paid a fixed dayrate for the rental of the vessel, which typically includes the costs of a small crew of four to eight employees, and we also receive a variable rate for reimbursement of other operating costs such as catering, fuel, rental equipment and other items.

Our revenues are affected primarily by dayrates, fleet utilization and the number and type of units in our fleet. Utilization and dayrates, in turn, are influenced principally by the demand for rig and liftboat services from the exploration and production sectors of the oil and natural gas industry. Our contracts in the U.S. Gulf of Mexico tend to be short-term in nature and are heavily influenced by changes in the supply of units relative to the fluctuating expenditures for both drilling and production activity.

Our operating costs are primarily a function of fleet configuration and utilization levels. The most significant direct operating costs for our Contract Drilling Services segment are wages paid to crews, maintenance and repairs to the rigs, and marine insurance. These costs do not vary significantly whether the rig is operating under contract or idle, unless we believe that the rig is unlikely to work for a prolonged period of time, in which case we may decide to “cold-stack” the rig. Cold-stacking is a common term used to describe a rig that is expected to be idle for a protracted period and typically for which routine maintenance is suspended and the crews are either redeployed or laid-off. When a rig is cold-stacked, operating expenses for the rig are reduced because the crew is smaller and maintenance activities are suspended. Rigs that have been cold-stacked typically require a lengthy reactivation project that can involve significant expenditures, particularly if the rig has been cold-stacked for a long period of time.

The most significant costs for our Marine Services segment are the wages paid to crews and regulatory drydocking costs. Unlike our Contract Drilling Services segment, a significant portion of the expenses incurred with operating each liftboat are paid for or reimbursed by the customer under contractual terms and prices. This includes fuel, catering expenses, offshore communications and crane overtime. We record reimbursements from customers as revenues and the related expenses as operating costs. Our liftboats are required to undergo regulatory inspections every year and to be drydocked two out of every five years; the drydocking expenses and time of drydock vary depending on the condition of the vessel. All costs associated with regulatory inspections, including related drydocking costs, are deferred and amortized over 12 months.

RECENT DEVELOPMENTS

Initial Public Offering

We completed our initial public offering of 10,580,000 shares of common stock at $20.00 per share on November 1, 2005. We offered 6,250,000 shares of common stock, while the remaining 4,330,000 shares were offered by selling stockholders. We received approximately $115.1 million of proceeds from the offering, net of underwriting discounts and commissions and estimated expenses. We used $44.0 million of the proceeds to complete the acquisition of a fleet of liftboats from Danos & Curole Marine Contractors, LLC (“Danos & Curole”), discussed below. In addition, we repaid $45.0 million of the senior secured term loan plus accrued interest of $0.3 million, discussed below. The remaining proceeds are being used for general corporate purposes, including refurbishment of and upgrades to Rig 16 and Rig 31.

On November 1, 2005, in connection with our initial public offering, we converted from a limited liability company to a corporation (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. Prior to the Conversion, we elected to be taxed as a partnership. As such, the members of our company were taxed on their proportionate share of net income prior to the Conversion and no provision or liability for income taxes is included in our unaudited consolidated financial statements included in this Form 10-Q. When we became a taxable entity in the Conversion, a provision of approximately $10.8 million was made reflecting the tax effect of the difference between the book and tax basis of our assets and liabilities as of November 1, 2005, the effective date of the Conversion.

Liftboat Acquisitions from Danos & Curole

In November 2005, we completed the acquisition of a fleet of liftboats and related assets from Danos & Curole for $44.0 million. Three of these liftboats, which have leg lengths ranging from 130 to 230 feet, are located in the U.S. Gulf of Mexico and are currently operating under short-term contracts.

Four liftboats, which have leg lengths ranging from 130 to 170 feet, are currently operating in Nigeria. Danos & Curole will continue to operate these four vessels under an operating agreement until we have established our own operations in Nigeria. This operating agreement expires in September 2006 and can be terminated by us earlier upon 30 days’ notice to Danos & Curole.

An additional liftboat subject to the purchase agreement, the Andre Danos, was damaged as a result of Hurricane Katrina. Danos & Curole is currently salvaging the vessel. We have agreed to reimburse Danos & Curole up to $0.5 million of the salvage costs. Danos & Curole insured the Andre Danos for $3.6 million, with a deductible of $1.5 million. Once the vessel is salvaged, Danos & Curole and its insurers will determine whether the vessel is a constructive total loss or can be repaired. If the vessel is determined to be a constructive total loss, a portion of the $44.0 million purchase price equal to the amount of insurance proceeds Danos & Curole recovers, net of the deductible, will be refunded by Danos & Curole to us. However, if the vessel can be repaired, Danos & Curole will conduct the repairs until the insurance proceeds received are completely expended, and will thereafter deliver the vessel to us in such condition without additional payment of any consideration. We believe the liftboat is likely to be declared a constructive total loss.

Senior Secured Term Loan Paydown

In November 2005, we repaid $45.0 million of the principal amount outstanding under our senior secured term loan. We paid $0.3 million of accrued interest and expensed $1.3 million of debt issuance costs in connection with the repayment. We will record a loss from the early retirement of debt in the fourth quarter of 2005 of $1.3 million.

Rig Sale Agreement

In November 2005, we entered into a definitive agreement to sell Rig 41 for $3.4 million, net of commissions. The buyer paid a $0.2 million non-refundable deposit, and we expect the sale to close in the first quarter of 2006. We expect to recognize a gain of approximately $1.4 million on the sale for the excess of the purchase price over the rig’s carrying value.

RECENT HURRICANES

Two of our jackup rigs, Rig 21 and Rig 25, sustained damage during Hurricane Katrina. After the storm, we discovered Rig 25 submerged in approximately 15 feet of water. It appears from our preliminary examination of the rig that its legs have been sheered off below the hull, its derrick has been destroyed and the electrical power control systems have been irreparably damaged. Through our preliminary salvage efforts, we have determined that the rig’s jacking systems have been damaged and that seawater has breached the watertight areas of the hull and is likely to have damaged the rig’s mechanical systems. We believe that a complete survey of the rig is likely to reveal that the total repair costs to the rig will exceed $40 million. This would result in the rig being declared a constructive total loss under our insurance policies.

We have commenced the salvage and removal of Rig 25, the cost of which is covered by our insurance, subject to a single deductible of $1.0 million. If Rig 25 is declared a constructive total loss, we would receive the rig’s total insured value of $50.0 million, which would not be subject to a deductible. In this case, because the insurance proceeds would exceed the carrying value of the rig, which was $20.8 million as of September 30, 2005, we would recognize a gain equal to the excess. Under the terms of our senior secured credit agreement, we would be required to either apply the proceeds to the acquisition of additional long-term productive assets or reduce the outstanding principal amount of our term loan within one year of our receipt of the insurance proceeds.

If Rig 25 is not declared a constructive total loss, based on our preliminary analysis of the damage to the rig described above we believe that the rig would require substantial repairs before returning to work. We do not believe that we could complete such repairs prior to 2007.

As a result of the damage to Rig 25, the contract for the rig with our customer was terminated as of August 30, 2005, and the contract revenue that we had been generating ceased on that date. Prior to termination, the rig was contracted at a dayrate of approximately $41,000. For the nine-month period ended September 30, 2005, Rig 25 operated a total of 235 days and contributed revenues of $9.8 million.

Rig 21 suffered extensive damage to its mat as a result of the storm. The rig is currently in drydock in a shipyard in Pascagoula, Mississippi undergoing repairs to a section of its mat. We expect the rig to be available for service in the second quarter of 2006. The cost of the repairs is covered by our insurance, subject to a $1.0 million deductible. We accrued the $1.0 million insurance deductible in operating expenses for drilling services during the third quarter of 2005. The completion of the repairs to Rig 21 could be delayed if, among other things, the magnitude of the damage is greater than originally expected or the repairs are delayed by supply shortages, shipyard unavailability, unforeseen engineering issues or adverse weather.

Rig 21 was working under a contract that provides for a force majeure dayrate that is slightly less than the operating dayrate if operations were to cease as a result of a storm like Hurricane Katrina, but the term of the force majeure period is not specified in the contract. The rig began to earn this rate when operations ceased and the rig was evacuated in advance of the hurricane. We suspended the operation of the contract as of September 14, 2005 and have recognized no additional revenues under the contract since that date. Rig 21 will not earn any additional revenues until the time that we have completed the repairs and the rig is returned to service. In addition, the customer may terminate the current contract for Rig 21, and we may be required to market the rig to other parties in 2006 following the completion of the repairs. For the nine-month period ended September 30, 2005, Rig 21 operated a total of 250 days and contributed revenues of $11.6 million.

We expect that the operating expenses for both Rig 25 and Rig 21 for the fourth quarter of 2005 will be reduced as the rigs will not be operational during that period.

None of our rigs or liftboats sustained any material damage during Hurricane Rita in September 2005.

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. Our significant accounting policies are summarized in Note 1 to our unaudited consolidated financial statements. We believe that our more critical accounting policies include those related to property and equipment, revenue recognition, allowance for doubtful accounts and deferred charges. Inherent in such policies are certain key assumptions and estimates.

Property and Equipment

Property and equipment represents 74.4% of our total assets as of September 30, 2005. Property and equipment is stated at cost, less accumulated depreciation. Expenditures that substantially increase the useful lives of our assets are capitalized and depreciated, while routine expenditures for maintenance items are expensed as incurred, except for expenditures for drydocking our liftboats. Drydock costs are capitalized at cost in other non-current assets on the consolidated balance sheet and amortized on the straight-line method (see “—Deferred Charges” below). Depreciation is computed using the straight-line method over the useful life of the asset, which we estimate to be 15 years for our rigs and liftboats. We review our property and equipment for potential impairment when events or changes in circumstances indicate that the carrying value of any asset may not be recoverable. For property and equipment, the determination of recoverability is made based on the estimated undiscounted future net cash flows of the assets being reviewed. Any actual impairment charge would be recorded using the estimated discounted value of future cash flows. Our estimates, assumptions and judgments used in the application of our property and equipment accounting policies reflect both historical experience and expectations regarding future industry conditions and operations. Using different estimates, assumptions and judgments, especially those involving the useful lives of our rigs and liftboats and expectations regarding future industry conditions and operations, would result in different carrying values of assets and results of operations. For example, a prolonged downturn in the drilling industry in which utilization and dayrates were significantly reduced could result in an impairment of the carrying value of our jackup rigs.

Revenue Recognition

Revenues are generated from our rigs and liftboats working under dayrate contracts as the services are provided. Some of our contracts also allow us to recover additional direct costs, including mobilization and demobilization costs, additional labor and additional catering costs. Under most of our liftboat contracts, we receive a variable rate for reimbursement of costs such as catering, fuel, rental equipment and other items. Revenue for the recovery or reimbursement of these costs is recognized when the costs are incurred except for mobilization revenues, which are amortized over the related drilling contract.

Allowance for Doubtful Accounts

Accounts receivable represents approximately 13.3% of our assets and 58.4% of our current assets as of September 30, 2005. We continuously monitor our accounts receivable from our customers to identify any collectability issues. An allowance for doubtful accounts is established when a review of customer accounts indicates that a specific amount may not be collected. We establish an allowance for doubtful accounts based on the actual amount we believe is not collectable. No allowance was deemed necessary at September 30, 2005.

Deferred Charges

All of our liftboats are required to undergo regulatory inspections on an annual basis and to be drydocked two out of every five years to ensure compliance with U.S. Coast Guard regulations for vessel safety and vessel maintenance standards. Costs associated with these inspections, which generally involve setting the vessels on a drydock, are deferred, and the costs are amortized over 12 months. As of September 30, 2005, our net deferred charges related to regulatory inspection costs totaled $2.9 million. The amortization of the regulatory inspection costs was reported as part of our depreciation and amortization expense.

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:


	For the Three Months Ended September 30, 2005			For the Three Months Ended June 30, 2005			For the Nine Months Ended September 30, 2005			Period from Inception to September 30, 2004
	(Dollars in thousands, except per day amounts)
Contract Drilling Services Segment:
Number of rigs (as of end of period)		9			8			9			5
Operating days		571			602			1,783			290
Available days		598			637			1,849			291
Utilization (1)		95.5	%		94.5	%		96.4	%		99.7	%
Average revenue per rig per day (2)	$	49,471		$	43,653		$	44,552		$	28,953
Average operating expense per rig per day (3) (4)	$	23,483		$	18,988		$	20,216		$	16,522
Revenues	$	28,248		$	26,288		$	79,427		$	8,405
Operating expenses, excluding depreciation and amortization (4)	$	14,043		$	12,095		$	37,379		$	4,805
Depreciation and amortization	$	1,410		$	1,318		$	4,020		$	425
General and administrative expenses, excluding depreciation and amortization	$	598		$	1,682		$	3,463		$	449
Operating income	$	12,197		$	11,193		$	34,565		$	2,726

Marine Services Segment:
Number of liftboats (as of end of period)		39			39			39			—
Operating days		2,566			1,766			5,784			—
Available days		3,220			2,392			7,592			—
Utilization (1)		79.7	%		73.8	%		76.0	%		—
Average revenue per liftboat per day (2)	$	5,432		$	6,109		$	5,859		$	—
Average operating expense per liftboat per day (3)	$	2,409		$	2,444		$	2,395		$	—
Revenues	$	13,937		$	10,787		$	33,888		$	—
Operating expenses, excluding depreciation and amortization	$	7,757		$	5,847		$	18,184		$	—
Depreciation and amortization	$	2,334		$	1,534		$	5,035		$	—
General and administrative expenses, excluding depreciation and amortization	$	412		$	380		$	1,233		$	—
Operating income	$	3,434		$	3,026		$	9,436		$	—

Total Company:
Revenues	$	42,185		$	37,075		$	113,315		$	8,405
Operating expenses, excluding depreciation and amortization	$	21,800		$	17,942		$	55,563		$	4,805
Depreciation and amortization	$	3,753		$	2,860		$	9,075		$	425
General and administrative expenses, excluding depreciation and amortization	$	4,031		$	2,904		$	9,136		$	449
Operating income	$	12,601		$	13,369		$	39,541		$	2,726
Interest expense	$	2,735		$	2,534		$	7,572		$	648
Loss on early retirement of debt	$	—		$	2,786		$	2,786		$	—
Other income	$	244		$	101		$	479		$	63
Net income	$	10,110		$	8,150		$	29,662		$	2,141

(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 are undergoing major refurbishments, upgrades or construction, which include Rig 16, Rig 31 and the Whale Shark, or cold-stacked units, which include 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.

(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.

(4)	Includes a $1.0 million loss for accrual of the deductible for insurance proceeds to repair Rig 21 for the three and nine months ended September 30, 2005.

Three-Month Period Ended September 30, 2005 versus the Three-Month Period Ended June 30, 2005

We have presented below a comparison of the three-month period ended September 30, 2005 to the three-month period ended June 30, 2005 because we believe it provides the most meaningful comparative analysis of our results of operations of recent periods and provides meaningful trend information over those periods. We have not provided a comparison of the three-month period ended September 30, 2005 to the period from inception to September 30, 2004. We do not believe such a comparison would be meaningful since our results of operations for the period from inception to September 30, 2004 include only the results from five rigs for a two-month period as compared with the results from nine rigs and 39 liftboats for a full three-month period in the quarter ended September 30, 2005.

Revenues

Consolidated. Total revenues for the three-month period ended September 30, 2005 (the “Current Quarter”) were $42.2 million compared with $37.1 million for the three-month period ended June 30, 2005 (the “Prior Quarter”), an increase of $5.1 million, or 14%. This increase resulted primarily from higher jackup dayrates and additional operating days in our Marine Services segment, primarily due to the acquisition of the Superior liftboats in June 2005. Total revenues included $1.3 million in reimbursements from our customers for expenses paid by us in the Current Quarter compared with $0.9 million in the Prior Quarter.

Contract Drilling Services Segment. Revenues for our Contract Drilling Services segment were $28.2 million for the Current Quarter compared with $26.3 million for the Prior Quarter, an increase of $1.9 million, or 7%. This increase resulted primarily from higher average dayrates and utilization for our fleet partially offset by reduced utilization on two of our rigs that sustained damage during Hurricane Katrina in August 2005. Average revenue per rig per day was $49,471 in the Current Quarter compared with $43,653 in the Prior Quarter, with average utilization of 95.5% in the Current Quarter compared with 94.5% in the Prior Quarter. Revenues for our Contract Drilling Services segment included $0.7 million in reimbursements from our customers for expenses paid by us in the Current Quarter compared with $0.5 million in the Prior Quarter.

Marine Services Segment. Revenues for our Marine Services segment were $13.9 million for the Current Quarter compared with $10.8 million in the Prior Quarter, an increase of $3.1 million, or 29%. This increase resulted primarily from additional operating days in the Current Quarter, with 2,566 operating days in that quarter compared with 1,766 operating days in the Prior Quarter. Approximately 660 of the additional operating days were attributable to the Superior liftboats acquired in June 2005. Average revenue per liftboat per day was $5,432 in the Current Quarter compared with $6,109 in the Prior Quarter, with average utilization of 79.7% in the Current Quarter compared with 73.8% in the Prior Quarter. The average revenue per liftboat per day was negatively impacted by Hurricanes Katrina and Rita where we experienced 374 days of weather resulting in half dayrates. Average revenue per liftboat per day was also negatively impacted by the Superior liftboats acquired in June 2005, which are smaller and earned lower average dayrates than the remaining fleet. The increase in average utilization was attributable to increased activity in the aftermath of Hurricane Katrina and Hurricane Rita. Revenues for our Marine Services segment included $0.6 million in reimbursements from our customers for expenses paid by us in the Current Quarter compared with $0.4 million in the Prior Quarter.

Operating Expenses

Consolidated. Total operating expenses, excluding depreciation and amortization, for the Current Quarter were $21.8 million compared with $17.9 million in the Prior Quarter, an increase of $3.9 million, or 22%. This increase resulted primarily from increased rig and liftboat operating expenses as described below.

Contract Drilling Services Segment. Operating expenses, excluding depreciation and amortization, for our Contract Drilling Services segment were $14.0 million in the Current Quarter compared with $12.1 million in the Prior Quarter, an increase of $1.9 million, or 16%. This increase resulted primarily from higher insurance expense due to increasing insurance coverage on our jackup rig fleet and a $1.0 million deductible recorded for damage sustained by one of our rigs during Hurricane Katrina in August 2005. We also incurred increased maintenance costs due to increased activity on our rigs. Average operating expenses per rig per day were $23,483 in the Current Quarter compared with $18,988 in the Prior Quarter.

Marine Services Segment. Operating expenses, excluding depreciation and amortization, for our Marine Services segment were $7.8 million for the Current Quarter compared with $5.8 million in the Prior Quarter, an increase of $2.0 million, or 34%. This increase resulted from $2.0 million in additional expenses associated with the Superior liftboats acquired in June 2005.

Depreciation and Amortization

Depreciation and amortization expense in the Current Quarter was $3.8 million compared with $2.9 million in the Prior Quarter, an increase of $0.9 million, or 31%. This increase resulted primarily from $0.5 million in additional amortization of regulatory inspections and related drydockings and $0.3 million in depreciation expense for the Superior liftboats acquired in June 2005 and the Whale Shark liftboat acquired in August 2005 in our Marine Services segment.

General and Administrative Expenses

General and administrative expenses, excluding depreciation and amortization, in the Current Quarter were $4.0 million compared with $2.9 million in the Prior Quarter, an increase of $1.1 million, or 38%. This increase resulted primarily from $2.2 million in additional expenses for our corporate offices related to our initial public offering partially offset by a $1.1 million decrease in expense in our Contract Drilling Services segment. The decrease in our Contract Drilling Services segment was due primarily to the collection of a bad debt in the Current Quarter of $0.8 million. In addition, there was $0.3 million in bad debt expense in the Prior Quarter.

Interest Expense

Interest expense in the Current Quarter was $2.7 million compared with $2.5 million in the Prior Quarter, an increase of $0.2 million, or 8%. This increase resulted from the increase in borrowings associated with the $140.0 million term loan in June 2005, partially offset by a decrease in the average interest rate on our overall borrowings.

Other Income

Other income in the Current Quarter was $0.2 million compared with $0.1 million in the Prior Quarter, an increase of $0.1 million. This increase is due primarily to higher cash balances resulting in increased interest income.

Nine-Month Period Ended September 30, 2005

Revenues

Consolidated. Total revenues for the nine-month period ended September 30, 2005 were $113.3 million. Total revenues were positively impacted by increasing jackup dayrates and additional operating days in our Marine Services segment as a result of the Superior liftboat acquisition and higher activity levels following Hurricane Katrina and Hurricane Rita. Total revenues included $3.7 million in reimbursements from our customers for expenses paid by us.

Contract Drilling Services Segment. Revenues for our Contract Drilling Services segment were $79.4 million for the nine-month period ended September 30, 2005. Average revenue per rig per day was $44,552 and average utilization was 96.4%. Revenues for our Contract Drilling Services segment included $2.0 million in reimbursements from our customers for expenses paid by us.

Marine Services Segment. Revenues for our Marine Services segment were $33.9 million for the nine-month period ended September 30, 2005. Average revenue per liftboat per day was $5,859 and average utilization was 76.0%. Our fleet increased from 22 to 39 liftboats in the nine-month period ended September 30, 2005. Average

revenue per liftboat per day was negatively impacted by the Superior liftboats acquired in June 2005, which are smaller and earned lower average dayrates than the remaining fleet. Revenues for our Marine Services segment included $1.7 million in reimbursements from our customers for expenses paid by us.

Operating Expenses

Consolidated. Total operating expenses, excluding depreciation and amortization, for the nine-month period ended September 30, 2005 were $55.6 million. Operating expenses in our Contract Drilling Services segment were impacted by increasing labor costs attributable to wage increases paid to our crews, and increasing insurance costs, including a $1.0 million deductible accrued for the repair of Rig 21. Operating expenses in our Marine Services segment were impacted by expenses associated with the Superior liftboats acquired in June 2005 and additional expenses due to higher utilization on the remaining fleet.

Contract Drilling Services Segment. Operating expenses, excluding depreciation and amortization, for our Contract Drilling Services segment were $37.4 million for the nine-month period ended September 30, 2005. Average operating expenses per rig per day were $20,216. Average labor costs per rig per day, which include wages and benefits paid to crews, were $10,802. Average rig maintenance expenses per rig per day, excluding capitalized costs, were $2,936. Average insurance expense per rig was $1,756 per day. Other rig expenses, which include catering, rentals, communications, and mobilization costs, averaged $4,722 per rig per day.

Marine Services Segment. Operating expenses, excluding depreciation and amortization, for our Marine Services segment were $18.2 million for the nine-month period ended September 30, 2005. Operating expenses on our liftboats averaged $2,395 per liftboat per day in the period, ranging from $1,181 per liftboat per day for the smaller vessels to $3,509 per liftboat per day for the larger vessels. Average labor costs per liftboat per day, which includes wages and benefits paid to crews, were $1,286. Average maintenance expenses per liftboat per day, excluding capitalized costs, were $320. Average insurance expense per liftboat per day was $200. Other operating expenses, which include catering, rentals and communication costs, averaged $589 per liftboat per day.

Depreciation and Amortization Expenses

Total depreciation and amortization expenses were $9.1 million for the nine-month period ended September 30, 2005. Results for the nine-month period ended September 30, 2005 included $4.0 million of depreciation expense for our drilling fleet, $3.0 million of depreciation expense for our liftboat fleet and $2.0 million of amortization of regulatory inspections and related drydockings.

General and Administrative Expenses

General and administrative expenses, excluding depreciation and amortization, were $9.1 million for the nine-month period ended September 30, 2005. Our Contract Drilling Services and Marine Services segments incurred general and administrative expenses of $3.5 million and $1.2 million, respectively. General and administrative expenses for our corporate office were $4.4 million. Expenses related to our initial public offering totaling $2.2 million are included in our corporate general and administrative expense.

Interest Expense

Interest expense was $7.6 million for the nine-month period ended September 30, 2005. Results for the period included $2.0 million of interest expense associated with the $28.0 million in borrowings incurred in the acquisition of five drilling rigs in August 2004, $1.0 million associated with the $28.0 million in borrowings incurred in the acquisition of 22 liftboats in October 2004, $1.6 million associated with $25.0 million of borrowings incurred in the acquisitions of Rig 25 and Rig 30 in January 2005, $0.1 million associated with the $20.0 million in borrowings incurred in the acquisition of Superior liftboats in June 2005 and $2.9 million associated with $140.0 million in borrowings incurred in refinancing our debt in June 2005.

Other Income

Other income was $0.5 million for the nine-month period ended September 30, 2005. Results for the period included $0.4 million of interest income associated with overnight investments of cash.

Period from Inception to September 30, 2004

Revenues

Total revenues were $8.4 million for the period from inception to September 30, 2004. Revenues for the period include activity in our Contract Drilling Services segment for the five jackup rigs acquired from Parker Drilling in August 2004. Total revenues included $0.2 million in reimbursements from our customers for expenses paid by us. Average revenue per rig per day was $28,953 and average utilization was 99.7%.

Operating Expenses

Total operating expenses, excluding depreciation and amortization, were $4.8 million for the period from inception to September 30, 2004. Total operating expenses included expenses in our Contract Drilling Services segment for five jackup rigs beginning on August 2, 2004. Average operating expenses per rig were $16,522 per day. Average labor costs per rig, which include wages and benefits paid to crews, were $9,402 per day. Rig maintenance expenses per rig, excluding capitalized costs, were $2,083 per day. Average insurance expense per rig was $1,014 per day. Other rig expenses, which included catering, rentals, communications, and mobilization costs, averaged $4,023 per rig per day.

Depreciation and Amortization Expenses

Total depreciation and amortization expenses were $0.4 million for the period from inception to September 30, 2004.

General and Administrative Expenses

General and administrative expenses, excluding depreciation and amortization, were $0.4 million for the period from inception to September 30, 2004.

OUTLOOK

Our industry is cyclical and is typically driven by general economic activity and changes in actual or anticipated oil and natural gas prices. In addition, most of our rigs and liftboats are located in the shallow waters of the U.S. Gulf of Mexico, which is a market characterized by short-term contracts for our rigs and liftboats to support drilling and production primarily of natural gas. Throughout 2005, oil and natural gas prices have been high relative to historical levels and, as a result, we have experienced strong demand for our rigs and liftboats.

In addition to the favorable commodity price environment, two other factors have positively impacted the market conditions for our rigs and liftboats. First, a number of jackup rigs have been mobilized out of the U.S. Gulf of Mexico over the past five years, and several of our competitors have announced the mobilization of a number of additional rigs from the U.S. Gulf of Mexico to international locations in 2006. Second, because of the significant damage to rigs, production platforms and pipelines in the U.S. Gulf of Mexico caused by Hurricanes Katrina and Rita, demand for our liftboats for inspection and repair work has increased significantly compared to the beginning of 2005. We anticipate that the additional inspection and repair work will continue into early 2006.

We believe that the current favorable market conditions will continue for at least the near term. However, demand for our rigs and liftboats could be negatively impacted by a number of factors, including among others increases in the supply of rigs and liftboats in the U.S. Gulf of Mexico, unexpected changes in oil and natural gas prices, increases in insurance costs for both our assets and for our customers’ production assets, the cost and availability of labor and regulatory changes.

According to ODS-Petrodata, as of November 30, 2005, there were 43 higher specification jackup rigs under construction. We do not anticipate that these rigs will compete directly with our fleet, but may indirectly impact us through competition in other markets. In addition, 11 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 given the current tight market conditions, our competitors may begin reactivating at least some of these rigs. There are also five liftboats under construction in the U.S. that are targeted for use in the U.S. Gulf of Mexico. Once delivered, these liftboats may impact the demand for our liftboat fleet.

LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses of Cash

Sources and Uses of Cash for the Nine-Month Period Ended September 30, 2005

Net cash provided by operating activities for the nine-month period ended September 30, 2005 was $37.7 million, which was primarily attributable to net income of $29.6 million plus depreciation and amortization of $9.1 million, an increase in accounts payable and other current liabilities of $15.6 million and a $2.8 million loss on the early retirement of debt, partially offset by a $19.4 million increase in accounts receivable and other current assets. The increase in accounts receivable was due to increased revenue from higher average dayrates for our Contract Drilling Services segment and the revenue from the Superior liftboats acquired in June 2005.

Net cash used in investing activities for the nine-month period ended September 30, 2005 was $117.7 million. The net cash investments during the period included the acquisition in January 2005 of Rig 25 and Rig 30 for an aggregate of $41.5 million, the acquisitions in June 2005 of the Superior liftboats for an aggregate of $19.8 million and Rig 16 for $20.0 million, the acquisition in August 2005 of the Whale Shark liftboat for $12.5 million and the acquisition in September 2005 of Rig 31 for $12.6 million. The acquisition of Rig 25 was funded in part by a $2.0 million deposit paid in 2004, which was applied towards the purchase price at closing. Capital expenditures for our rigs and liftboats included $3.4 million for the refurbishment of Rig 16, $4.6 million for drydockings of liftboats and $2.3 million for general rig refurbishments.

Net cash provided by financing activities for the nine-month period ended September 30, 2005 totaled $82.3 million. This amount included borrowings of $45.0 under two of our credit facilities for the acquisitions of Rig 25 and Rig 30 and the Superior liftboats and $140.0 million under our new senior secured term loan. In addition, we received contributions from owners totaling $4.3 million. We repaid $101.0 million outstanding under our then-existing credit facilities with proceeds from our new term loan. We also paid $6.0 million in fees and expenses in connection with our debt agreements.

Sources and Uses of Cash for the Period from Inception to September 30, 2004

Net cash used in operating activities for the period from inception to September 30, 2004 was $4.3 million, which was primarily attributable to net income of $2.1 million plus depreciation and amortization of $0.4 million and an increase in accounts payable and other current liabilities of $4.0 million, offset by a $10.8 million increase in accounts receivable and other current assets. The increase in both current assets and current liabilities were attributable to the start-up of our business activities.

Net cash used in investing activities for the period from inception to September 30, 2004 was $40.3 million. The net cash investments during the period included the acquisition in August 2004 of five jackup rigs and four platform rigs from Parker Drilling for $39.3 million.

Net cash provided by financing activities for the period from inception to September 30, 2004 totaled $49.0 million. This amount included borrowings of $28.0 under our term loan and contributions from owners totaling $22.0 million. We also paid $1.0 million in fees and expenses in connection with our debt agreements.

Liquidity and Financing Arrangements

Contributions from owners and borrowings from our creditors represented our primary source of liquidity for the period from inception through September 30, 2004. For the same period, our primary use of cash was the acquisition of the jackup and platform rigs from Parker Drilling for $39.3 million. Contributions from owners, borrowings from our creditors and cash from operations represented our primary sources of liquidity for the nine-month period ended September 30, 2005. For the same period, our primary uses of cash were the acquisition of Rig 25 from Parker Drilling for $21.5 million, the acquisition of Rig 30 from Porterhouse Offshore L.P. for $20.0 million, the acquisition of 17 liftboats from Superior Energy for $19.8 million, the acquisition of Rig 16 from Transocean for $20.0 million, the acquisition of the Whale Shark from CS Liftboats, Inc. for $12.5 million, and the acquisition of Rig 31 from Hydrocarbon Capital II LLC for $12.6 million.

We believe that our current cash on hand and our cash flow from operations for the period ending September 30, 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 Rig 16 and Rig 31, to repair Rig 21 and, if it is not declared a constructive total loss, Rig 25 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, 2005 totaled $16.8 million. This represented an increase of $2.3 million from the cash balances of $14.5 million as of December 31, 2004. The increase was due to aggregate borrowings of $185.0 million under our various term loans, contributions from owners totaling $4.3 million and cash flow generated from operations of $37.7 million. The amounts were partially offset by debt repayments of $101.0 million and the acquisition of rigs and liftboats for a total of $115.6 million.

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, 2005, we had outstanding long-term debt of $140.0 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 provides for a $140.0 million term loan and a $25.0 million revolving credit facility. We may seek commitments to increase the amount available under the credit agreement by an additional $25.0 million if the amount outstanding under the term loan is no more than $105.0 million and 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. We used $54.6 million of the proceeds from the term loan to repay all outstanding amounts under the credit facility of our drilling company subsidiary and $47.5 million of the proceeds to repay all outstanding amounts under the credit facility of our liftboat company subsidiary, in each case including accrued interest, fees and applicable prepayment premiums. We terminated both of those credit facilities in connection with the repayment. In addition, we used $20.0 million of the remaining proceeds from the term loan to fund the purchase price of Rig 16. In connection with the repayment of the two credit facilities, we recognized in the second quarter of 2005 pretax charges of $2.8 million, consisting of a prepayment penalty and the write-off of deferred financing costs related to the retired debt.

The revolving credit facility provides for swing line loans of up to $2.5 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 2.25%, or (2) LIBOR plus 3.25%. We may prepay the revolving loans at any time without premium or penalty. The revolving loans mature in June 2008. We are required to pay a commitment fee of 0.50% on the average daily amount of the unused commitment amount of the revolving credit facility and a letter of credit fee of 3.25%, plus a fronting fee of 0.13%, with respect to the undrawn amount of each issued letter of credit. As of September 30, 2005, 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, 2005, the entire principal amount of the $140.0 million term loan was outstanding, and the interest rate was 6.58%. 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 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 during the first year 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.

We repaid $45.0 million of the outstanding amount under the term loan, together with the accrued and unpaid interest of $0.3 million, with proceeds from our initial public offering.

Our obligations under the credit agreement are secured by our liftboats, rigs and substantially all of our other personal property, including the equity of our subsidiaries. All of our material subsidiaries guarantee our obligations under the agreement and have granted similar liens on substantially all of their assets.

The credit agreement contains financial covenants relating to leverage and interest 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. We are currently in compliance with our covenants under the credit agreement. The credit agreement contains customary events of default.

Capital Expenditures

We expect to spend approximately $7.5 million to upgrade Rig 16 and expect to complete the upgrade in the first quarter of 2006. The commissioning of the Whale Shark is expected to be completed in the fourth quarter of 2005 for total expenditures of $0.5 million. We expect to spend approximately $15.0 million to refurbish and upgrade Rig 31 and to complete the project by the third quarter of 2006. Additionally, we expect the cost to repair Rig 21 to be within insured values.

Over the remainder of 2005 and in 2006, we will continue to incur expenditures to upgrade and refurbish our rigs and our liftboats. In addition, we are required to inspect and drydock our liftboats on a periodic basis to meet U.S. Coast Guard requirements. Through the first nine months of 2005, we spent approximately $5.7 million on rig refurbishments and $4.6 million on liftboat drydockings. We expect these amounts to increase as we acquire additional rigs and liftboats and as our fleet ages. The amount of expenditures is impacted by a number of factors, including among others our ongoing maintenance expenditures, adverse weather, changes in regulatory requirements and operating conditions. In addition, from time to time we agree to perform modifications to our rigs and liftboats as part of a contract with a customer. When market conditions allow, we attempt to recover these costs as part of the contract cash flow.

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

The following table summarizes our contractual obligations as of September 30, 2005, after giving effect to the November 2005 repayment of $45.0 million of our senior secured term loan as described in “—Recent Developments”:


	Payments due by period ending September 30,
Contractual Obligations (1)	2006		2007 to 2008		2009 to 2010		Thereafter		Total
	(in thousands)
Long-term debt obligations	$	1,400	$	2,800	$	90,800	$	—	$	95,000
Management compensation obligations		1,125		299		—		—		1,424
Operating lease obligations		240		613		487		83		1,423

Total contractual obligations	$	2,765	$	3,712	$	91,287	$	83	$	97,847

(1)	As of September 30, 2005, we did not have any material purchase obligations for goods or services.

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;

•

expected useful lives of our rigs and liftboats;

•

our plans regarding increased international operations;

•

future capital expenditures and refurbishment and repair costs;

•

expected repair time for Rig 21 and declaration of Rig 25 as a constructive total loss;

•

expected time to complete the refurbishment of Rig 16 and Rig 31 and the commissioning of the Whale Shark;

•

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

•

liabilities under laws and regulations protecting the environment;

•

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

•

expectations regarding improvements in offshore drilling activity, demand for our rigs and liftboats, inspection and repair work for our 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 our prospectus dated October 26, 2005 related to our initial public offering, which was filed with the SEC on October 27, 2005, 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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uncertainties relating to the extent of the damage to Rig 21 and Rig 25 and the other rigs and liftboats in our fleet;

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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;

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operating hazards, war, terrorism and cancellation or unavailability of insurance coverage;

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the effect of litigation and contingencies; and

•

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

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to interest rate risk with respect to our variable rate debt. All of the debt under our term loan is at variable rates. As of September 30, 2005, the interest rate for the $140.0 million outstanding under the term loan was 6.82%. 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. A hypothetical 100 basis point increase in the average interest rate on our variable rate debt outstanding as of September 30, 2005 would increase our annual interest expense by approximately $1.4 million.

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. In the course of this evaluation, management considered certain internal control areas in which we have made and are continuing to make changes to improve and enhance controls. Based upon that evaluation, our Chief Executive Officer and President and our Chief Financial Officer concluded that our disclosure controls and procedures are 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 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Prior to the closing of our initial public offering, on November 1, 2005, we converted from a Delaware limited liability company into a Delaware corporation. At the time of the Conversion, our 68,351 outstanding membership interests were automatically converted into a total of 23,922,850 shares of common stock, on the basis of a conversion ratio of 350 shares of common stock for each membership interest. The issuance of common stock to our members in the Conversion was exempt from registration under the Securities Act by virtue of the exemption provided under Section 3(a)(9) thereof as the common stock was exchanged by us with our existing security holders exclusively where no commission or other remuneration was paid or given directly or indirectly for soliciting such exchange. The issuance of common stock was also exempt from registration under the Securities Act by virtue of Section 4(2) thereof as a transaction not involving a public offering.

On November 1, 2005, we completed our initial public offering of 10,580,000 shares of our common stock at an initial offering price of $20.00 per share. Each share of common stock includes a right to purchase Series A Junior Participating Preferred Stock under the Rights Agreement dated as of October 31, 2005 between us and American Stock Transfer & Trust Company, as rights agent. We sold 6,250,000 shares of common stock at an aggregate offering price of $125.0 million, while selling stockholders sold the remaining 4,330,000 shares at an aggregate offering price of $86.6 million. The offering commenced on October 27, 2005 pursuant to a Registration Statement on Form S-1 (Registration No. 333-126457; the “Registration Statement”) that the SEC declared effective on October 26, 2005. Credit Suisse First Boston LLC and Citigroup Global Markets Inc. served as joint bookrunning managers of the offering. Simmons & Company International, Deutsche Bank Securities Inc. and Howard Weil Incorporated served as co-managers. We registered under the Registration Statement the offering of a number of shares of our common stock having an aggregate offering price of $211,600,000.

The net proceeds to us from the offering, after payment by us of $8.8 million in underwriting discounts and commissions and $1.2 million in estimated offering expenses, were approximately $115.1 million. No offering expenses were paid directly or indirectly to any of our directors, officers or their associates, persons owning ten percent or more of any class of our equity securities or any other affiliates of our company. We used $45.3 million of the net proceeds to repay $45.0 million outstanding principal amount of our senior secured term loan, together with accrued and unpaid interest to the repayment date of $0.3 million, and $44.0 million to complete the acquisition of a fleet of liftboats and related assets from Danos & Curole Marine Contractors, LLC. We also have used approximately $1.8 million of the net proceeds from November 1, 2005 to November 30, 2005 for the refurbishment of Rig 16 and Rig 31. No net offering proceeds received by us have been paid directly or indirectly to any of our directors, officers or their associates, persons owning ten percent or more of any class of our equity securities or any other affiliates of our company. The remaining proceeds remain invested in Eurodollar overnight deposits pending application of the funds to general corporate purposes. We did not receive any of the proceeds from the sale of shares of our common stock by selling stockholders.

ITEM 5. OTHER INFORMATION.

Rule l4a-8 under the Securities and Exchange Act of 1934 addresses when a company must include a stockholder’s proposal in its proxy statement and identify the proposal in its form of proxy when the company holds an annual or special meeting of stockholders. Under Rule l4a-8, proposals that stockholders intend to have included in our proxy statement for the 2006 annual meeting of stockholders should be received by our corporate secretary no later than December 27, 2005, which is the 120th day prior to the date of our annual meeting of stockholders scheduled for April 26, 2006.

If a stockholder desires to bring a matter before our annual meeting and the proposal is submitted outside the process of Rule 14a-8, the stockholder must follow the procedures set forth in our bylaws. Our bylaws provide generally that stockholder proposals for an annual meeting may be made by a stockholder only if (1) the stockholder is a stockholder of record and is entitled to vote at the meeting, and (2) the stockholder gives timely written notice of the proposal to our corporate secretary. To be timely, a stockholder’s notice must be delivered to, or mailed and received

at, our principal executive offices not less than 120 days nor more than 180 days prior to the first annual anniversary of the prior year’s annual meeting of stockholders. However, if the date of the annual meeting of stockholders is advanced by more than 30 days or delayed by more than 60 days from such anniversary date, notice by the stockholder must be so delivered not later than the close of business on the later of the 120th day prior to such annual meeting of stockholders or the tenth day following the day on which we first publicly announce the date of such meeting. Under our bylaws, proposals that stockholders intend to have included in our proxy statement for the 2006 annual meeting of stockholders should be received by our corporate secretary no later than December 27, 2005.

ITEM 6. EXHIBITS


2.1*		Plan of Conversion (incorporated by reference to Exhibit 2.1 to Hercules’ Registration Statement on Form S-1 (Registration No. 333-126457), as amended (the “Registration Statement”), originally filed on July 8, 2005).

3.1*		Certificate of Incorporation of Hercules Offshore, Inc. (incorporated by reference to Exhibit 3.1 to Hercules’ Current Report on Form 8-K dated November 1, 2005 (File No. 0-51582) (the “Form 8-K”)).

3.2*		Bylaws of Hercules Offshore, Inc. (incorporated by reference to Exhibit 3.2 to the Form 8-K).

4.1*		Form of specimen common stock certificate (incorporated by reference to Exhibit 4.1 to the Registration Statement).

4.2*		Rights Agreement, dated as of October 31, 2005, between Hercules and American Stock Transfer & Trust Company, as rights agent (incorporated by reference to Exhibit 4.1 to the Form 8-K).

4.3*		Certificate of Designations of Series A Junior Participating Preferred Stock (incorporated by reference to Exhibit 4.2 to the Form 8-K).

4.4*		Credit Agreement dated as of June 30, 2005 among Hercules Offshore, LLC, as Borrower, Comerica Bank, as Administrative Agent, Citicorp North America, Inc., as Syndication Agent, Credit Suisse, as Documentation Agent, and the Lenders party thereto (incorporated by reference to Exhibit 4.2 to the Registration Statement).

10.1*		Vessel Purchase Agreement dated as of August 4, 2005 between C.S. Liftboats, Inc. and Hercules (incorporated by reference to Exhibit 10.14 to the Registration Statement).

10.2*		Rig Sale Agreement dated as of August 8, 2005 between Hydrocarbon Capital II LLC and Hercules (incorporated by reference to Exhibit 10.15 to the Registration Statement).

10.3*		Asset Purchase Agreement dated as of September 16, 2005 by and among Hercules Liftboat Company, LLC, Danos Marine, Inc. and Danos & Curole Marine Contractors, LLC (incorporated by reference to Exhibit 10.16 to the Registration Statement).

10.4*		Employment Agreement dated as of October 3, 2005 by and between Hercules and John T. Rynd (incorporated by reference to Exhibit 10.17 to the Registration Statement).

10.5*		Separation Agreement dated October 4, 2005 by and between Hercules and Thomas J. Seward II (incorporated by reference to Exhibit 10.18 to the Registration Statement).

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.

*	Incorporated by reference as indicated.

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: December 9, 2005

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