Edgar Filing: HERCULES OFFSHORE, INC.

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2012

¨	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.)

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

(713) 350-5100

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

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


Large accelerated filer ¨	Accelerated filer x	Non-accelerated filer ¨	Smaller reporting company ¨
		(Do not check if a smaller reporting company)

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practicable date.


Common Stock, par value $0.01 per share		Outstanding as of April 23, 2012
		158,450,839

HERCULES OFFSHORE, INC.

INDEX


	Page No.
PART I. FINANCIAL INFORMATION

Item 1. Financial Statements:
Consolidated Balance Sheets as of March 31, 2012 and December 31, 2011		3
Consolidated Statements of Operations for the three months ended March 31, 2012 and 2011		4
Consolidated Statements of Cash Flows for the three months ended March 31, 2012 and 2011		5
Notes to Unaudited Consolidated Financial Statements		6

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		27
Item 3. Quantitative and Qualitative Disclosures about Market Risk		47
Item 4. Controls and Procedures		48

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		48
Item 1A. Risk Factors		48
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		50
Item 6. Exhibits		50

Signatures		52

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except par value)


	March 31, 2012			December 31, 2011
	(Unaudited)
ASSETS
Current Assets:
Cash and Cash Equivalents	$	165,057		$	134,351
Restricted Cash		13,261			9,633
Accounts Receivable, Net of Allowance for Doubtful Accounts of $12,187 and $11,460 as of March 31, 2012 and December 31, 2011, Respectively		139,256			153,688
Prepaids		8,516			16,352
Current Deferred Tax Asset		15,543			15,543
Other		30,747			20,435

		372,380			350,002
Property and Equipment, Net		1,600,530			1,591,791
Equity Investment		34,645			34,735
Other Assets, Net		33,767			30,176

	$	2,041,322		$	2,006,704

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Short-term Debt and Current Portion of Long-term Debt	$	52,886		$	22,130
Accounts Payable		58,635			49,370
Accrued Liabilities		60,248			70,421
Interest Payable		18,546			9,899
Insurance Notes Payable		—			5,218
Other Current Liabilities		25,849			18,366

		216,164			175,404
Long-term Debt, Net of Current Portion		771,002			818,146
Deferred Income Taxes		67,605			83,503
Other Liabilities		20,028			21,098
Commitments and Contingencies
Stockholders' Equity:
Common Stock, $0.01 Par Value; 200,000 Shares Authorized; 160,528 and 139,798 Shares Issued, Respectively; 158,451 and 137,899 Shares Outstanding, Respectively		1,605			1,398
Capital in Excess of Par Value		2,154,834			2,057,824
Treasury Stock, at Cost, 2,077 Shares and 1,899 Shares, Respectively		(53,089	)		(52,184	)
Retained Deficit		(1,136,827	)		(1,098,485	)

		966,523			908,553

	$	2,041,322		$	2,006,704

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

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

(Unaudited)


	Three Months Ended March 31,
	2012			2011
Revenue	$	143,319		$	159,378
Costs and Expenses:
Operating Expenses		111,237			106,381
Depreciation and Amortization		42,978			41,793
General and Administrative		17,674			12,826

		171,889			161,000

Operating Loss		(28,570	)		(1,622	)
Other Income (Expense):
Interest Expense		(19,669	)		(18,506	)
Other, Net		1,009			(194	)

Loss Before Income Taxes		(47,230	)		(20,322	)
Income Tax Benefit		8,888			6,679

Loss from Continuing Operations		(38,342	)		(13,643	)
Loss from Discontinued Operations, Net of Taxes		—			(576	)

Net Loss	$	(38,342	)	$	(14,219	)

Basic and Diluted Loss Per Share:
Loss from Continuing Operations	$	(0.28	)	$	(0.12	)
Loss from Discontinued Operations		—			—

Net Loss	$	(0.28	)	$	(0.12	)

Basic and Diluted Weighted Average Shares Outstanding		139,208			114,906

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

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Three Months Ended March 31,
	2012			2011
Cash Flows from Operating Activities:
Net Loss	$	(38,342	)	$	(14,219	)
Adjustments to Reconcile Net Loss to Net Cash Provided by (Used in) Operating Activities:
Depreciation and Amortization		42,978			42,911
Stock-Based Compensation Expense		1,487			1,158
Deferred Income Taxes		(16,872	)		(18,027	)
Provision (Benefit) for Doubtful Accounts Receivable		1,218			(5,021	)
Amortization of Deferred Financing Fees		993			874
Amortization of Original Issue Discount		1,183			1,089
Gain on Insurance Settlement		(3,400	)		—
Gain on Disposal of Assets		(274	)		(702	)
Other		(972	)		238
(Increase) Decrease in Operating Assets —
Accounts Receivable		13,214			(8,867	)
Prepaid Expenses and Other		(9,606	)		21,673
Increase (Decrease) in Operating Liabilities —
Accounts Payable		8,378			571
Insurance Notes Payable		(5,218	)		(5,248	)
Other Current Liabilities		4,451			21,221
Other Liabilities		(1,114	)		11,461

Net Cash Provided by (Used in) Operating Activities		(1,896	)		49,112
Cash Flows from Investing Activities:
Acquisition of Assets		(40,000	)		—
Additions of Property and Equipment		(16,573	)		(10,277	)
Deferred Drydocking Expenditures		(3,213	)		(4,124	)
Cash Paid for Equity Investment		—			(10,000	)
Insurance Proceeds Received		13,139			—
Proceeds from Sale of Assets, Net		3,312			3,421
Increase in Restricted Cash		(3,628	)		(1	)

Net Cash Used in Investing Activities		(46,963	)		(20,981	)
Cash Flows from Financing Activities:
Long-term Debt Repayments		(17,571	)		—
Common Stock Issuance		97,102			—
Other		34			(1,831	)

Net Cash Provided by (Used in) Financing Activities		79,565			(1,831	)

Net Increase in Cash and Cash Equivalents		30,706			26,300
Cash and Cash Equivalents at Beginning of Period		134,351			136,666

Cash and Cash Equivalents at End of Period	$	165,057		$	162,966

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

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

1. General

Hercules Offshore, Inc., a Delaware corporation, and its majority owned subsidiaries (the “Company”) provide shallow-water drilling and marine services to the oil and natural gas exploration and production industry globally through its Domestic Offshore, International Offshore, Inland, Domestic Liftboats and International Liftboats segments (See Note 12). At March 31, 2012, the Company owned a fleet of 43 jackup rigs, seventeen barge rigs, two submersible rigs, one platform rig, and 58 liftboat vessels and operated an additional five liftboat vessels owned by a third party. The Company’s diverse fleet is capable of providing services such as oil and gas exploration and development drilling, well service, platform inspection, maintenance and decommissioning operations in several key shallow water provinces around the world.

The consolidated financial statements of the Company are unaudited; however, they include all adjustments of a normal recurring nature which, in the opinion of management, are necessary to present fairly the Company’s Consolidated Balance Sheet at March 31, 2012, Consolidated Statements of Operations and Consolidated Statements of Cash Flows for the three months ended March 31, 2012 and 2011. Although the Company believes the disclosures in these financial statements are adequate to make the interim information presented not misleading, certain information relating to the Company’s organization and footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles have been condensed or omitted in this Form 10-Q pursuant to Securities and Exchange Commission rules and regulations. These financial statements should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2011 and the notes thereto included in the Company’s Annual Report on Form 10-K. The results of operations for the three months ended March 31, 2012 are not necessarily indicative of the results expected for the full year.

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

Recent Rig Acquisition

In March 2012, the Company acquired an offshore jackup drilling rig, the Hercules 266 (formerly known as Ocean Columbia) from a subsidiary of Diamond Offshore Drilling, Inc. for $40.0 million. The Company has entered into a three-year drilling contract with Saudi Aramco for the use of this rig with an option to extend the term for an additional one-year period. The Company expects to spend approximately $45.0 million for upgrades and other contract specific refurbishments to the rig and to mobilize the rig from the Gulf of Mexico to the Middle East. The Company expects the rig to commence work under the contract in December 2012.

Recent Common Stock Offering

In March 2012, the Company raised approximately $96.7 million in net proceeds, after adjusting for underwriting discounts and expected offering expenses, from an underwritten public offering of 20.0 million shares of its common stock, par value $0.01 per share at a price to the public of $5.10 per share ($4.85775, net of underwriting discounts). The Company also granted the Underwriters a 30-day option to purchase up to an additional 3.0 million shares of the Company’s common stock on the same terms as the 20.0 million shares sold by the Company, but it was not exercised. The Company used a portion of the net proceeds from the share offering to fund a portion of the purchase price for the acquisition of the Hercules 266 and intends to use the remaining net proceeds for general corporate purposes as well as the costs associated with the upgrade and mobilization of Hercules 266.

Investigations

On April 4, 2011, the Company received a subpoena issued by the Securities and Exchange Commission (“SEC”) requesting the delivery of certain documents to the SEC in connection with its investigation into possible violations of the securities laws, including possible violations of the Foreign Corrupt Practices Act (“FCPA”) in certain international jurisdictions where the Company conducts operations. The Company was also notified by the Department of Justice (“DOJ”) on April 5, 2011, that certain of the Company’s activities were under review by the DOJ.

On April 24, 2012, the Company received a letter from the DOJ notifying the Company that the DOJ has closed its inquiry into the Company regarding possible violations of the FCPA and does not intend to pursue enforcement action against the Company. The DOJ indicated that its decision to close the matter was based on, among other factors, the thorough investigation conducted by the Company’s special counsel and the Company’s compliance program.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

The Company, through the Audit Committee of the Board of Directors, intends to continue to cooperate with the SEC in its investigation. At this time, it is not possible to predict the outcome of the SEC’s investigation, the expenses the Company will incur associated with this matter, or the impact on the price of the Company’s common stock or other securities as a result of this investigation.

Revenue Recognition

Revenue generated from the Company’s contracts is recognized as services are performed, as long as collectability is reasonably assured. For certain contracts, the Company may receive lump-sum fees for the mobilization of equipment and personnel. Mobilization fees received and costs incurred to mobilize a rig from one market to another under contracts longer than ninety days are recognized as services are performed over the term of the related drilling contract. Amounts related to deferred revenue and deferred expenses are summarized below (in thousands):


	Three Months Ended March 31,
	2012		2011
Revenue deferred	$	120	$	24,533
Expense deferred		11,127		1,349
Deferred Revenue recognized		2,966		5,232
Deferred Expense recognized		1,603		586

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

The balances related to the Company’s Deferred Costs and Deferred Revenue are as follows (in thousands):


		As of		As of
	Balance Sheet	March 31,		December 31,
	Classification	2012		2011
Assets:
Deferred Expense-Current Portion	Other	$	10,192	$	3,811
Deferred Expense-Non-Current Portion	Other Assets, Net		6,795		3,652
Liabilities:
Deferred Revenue-Current Portion	Other Current Liabilities		7,617		8,461
Deferred Revenue-Non-Current Portion	Other Liabilities		11,294		13,296

Percentage-of-Completion

The Company has a construction management agreement and a services agreement with Discovery Offshore S.A. (“Discovery Offshore”) with respect to each of the two new-build rigs under construction for Discovery Offshore (each “Rig” or collectively “Rigs”). Under the construction management agreements, the Company is planning, supervising and managing the construction and commissioning of the Rigs for which it received a fixed fee of $7.0 million per Rig in February 2011. The Company is using the percentage-of-completion method of accounting for its revenue and related costs associated with its construction management agreements with Discovery Offshore, combining the construction management agreements, based on a cost-to-cost method. Any revisions in revenue, cost or the progress towards completion, will be treated as a change in accounting estimate and will be accounted for using the cumulative catch-up method. As of March 31, 2012 and December 31, 2011, $9.7 million and $11.2 million was outstanding as deferred revenue, respectively. The Company recognized $1.5 million as revenue during the three months ended March 31, 2012, under the percentage-of-completion method of accounting. Additionally, $1.3 million in cost was

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

recognized during the three months ended March 31, 2012, under the percentage-of-completion method of accounting related to activities associated with the performance of contract obligations. There was no revenue or cost recognized during the three months ended March 31, 2011 under the percentage-of-completion method of accounting as there were no activities associated with the performance of contract obligations during the first quarter of 2011.

Other Assets

Other assets consist of drydocking costs for marine vessels, a derivative asset, deferred income taxes, deferred operating expenses, financing fees, investments and deposits. Drydocking costs are capitalized at cost and amortized on the straight-line method over a period of 12 months. Drydocking costs, net of accumulated amortization, at March 31, 2012 and December 31, 2011, were $4.4 million and $5.2 million, respectively. Amortization expense for drydocking costs was $4.0 million for the three months ended March 31, 2012 and $3.7 million for the three months ended March 31, 2011.

Financing fees are deferred and amortized over the life of the applicable debt instrument. Unamortized deferred financing fees at March 31, 2012 and December 31, 2011 were $8.6 million and $9.1 million, respectively. Amortization expense for financing fees was $1.0 million for the three months ended March 31, 2012, and $0.9 million for the three months ended March 31, 2011, and is included in Interest Expense on the Consolidated Statements of Operations.

2. Earnings Per Share

The Company calculates basic earnings per share by dividing net income by the weighted average number of shares outstanding. Diluted earnings per share is computed by dividing net income by the weighted average number of shares outstanding during the period as adjusted for the dilutive effect of the Company’s stock option and restricted stock awards. The effect of stock option and restricted stock awards is not included in the computation for periods in which a net loss occurs, because to do so would be anti-dilutive. Stock equivalents of 6.0 million and 6.8 million were anti-dilutive and are excluded from the calculation of the dilutive effect of stock equivalents for the diluted earnings per share calculations for the three months ended March 31, 2012 and 2011, respectively.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

3. Equity Investment

The Company has a 28% equity investment in Discovery Offshore of $34.6 million and $34.7 million as of March 31, 2012 and December 31, 2011, respectively which is included in the assets of our International Offshore segment. This investment is being accounted for using the equity method of accounting as the Company has the ability to exert significant influence, but not control, over operating and financial policies. The Company reviews its equity investments for impairment whenever there is a loss in value of an investment which is considered to be other than temporary. The Company was issued warrants to purchase up to 5.0 million additional shares of Discovery Offshore as additional compensation for its costs incurred and efforts expended in forming Discovery Offshore, that, if exercised, would be recorded as an increase in the Company’s equity investment in Discovery Offshore.

4. Business Combination

On April 27, 2011, the Company completed its acquisition of 20 jackup rigs and related assets, accounts receivable, accounts payable and certain contractual rights from Seahawk Drilling, Inc. and certain of its subsidiaries (“Seahawk Transaction”).

The unaudited pro forma financial information set forth below has been compiled from historical financial statements and other information, but is not necessarily indicative of the results that actually would have been achieved had the transaction occurred on the dates indicated or that may be achieved in the future:


	Three Months Ended March 31,
	2011
	(In millions, except per share amounts)
Revenue	$	184.6
Net Loss		(28.9	)
Basic loss per share		(0.21	)
Diluted loss per share		(0.21	)

5. Discontinued Operations

The results of operations of the Delta Towing segment are reflected in the Consolidated Statements of Operations for the three months ended March 31, 2011 as discontinued operations.

Operating results of the Delta Towing segment were as follows (in thousands):


	Three Months Ended March 31,
	2011
Revenue	$	6,868

Loss Before Income Taxes	$	(964	)
Income Tax Benefit		388

Loss from Discontinued Operations, Net of Taxes	$	(576	)

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

6. Debt

Debt is comprised of the following (in thousands):


	March 31,		December 31,
	2012		2011
Term Loan Facility, due July 2013	$	435,338	$	452,909
10.5% Senior Notes, due October 2017		293,874		293,676
3.375% Convertible Senior Notes, due June 2038		91,165		90,180
7.375% Senior Notes, due April 2018		3,511		3,511

Total Debt		823,888		840,276
Less Short-term Debt and Current Portion of Long-term Debt		52,886		22,130

Total Long-term Debt, Net of Current Portion	$	771,002	$	818,146

Recent Notes Issuances and Changes to Existing Debt Balances

On April 3, 2012, the Company made the following changes to its debt structure:

•

Issued $300.0 million aggregate principal amount of 7.125% Senior Secured Notes due 2017;

•

Issued $200.0 million aggregate principal amount of 10.25% Senior Notes due 2019;

•

Entered into a new Credit Agreement that provides for a $75.0 million senior secured revolving credit facility, with a $25.0 million sublimit for the issuance of letters of credit;

•

Terminated its prior credit agreement dated July 11, 2007, as amended to date, which included an undrawn $140.0 million revolving credit facility and a term loan (“prior secured credit facility”) balance of $435.3 million as of March 31, 2012;

•

Repaid in full all outstanding indebtedness under the prior secured credit facility, and the liens securing such obligations were terminated; and

•

On April 3, 2012, and in connection with the aforementioned notes issuances and the repayment of the prior secured credit facility, the Company’s secured indebtedness was reduced below the defined threshold (as established in the indenture governing the 10.5% Senior Secured Notes), whereby, all the liens securing the 10.5% Senior Secured Notes were released (“10.5% Senior Notes”).

Senior Secured Credit Agreement

The Company had a $575.3 million credit facility, consisting of a $435.3 million term loan facility and a $140.0 million revolving credit facility as of March 31, 2012. As of March 31, 2012, no amounts were outstanding and no standby letters of credit had been issued under the revolving credit facility. The interest rate on the amount outstanding under the term loan facility was 7.5% and the annualized effective rate of interest was 7.86% for the three months ended March 31, 2012 after giving consideration to revolver fees.

Under the prior credit agreement, as amended, which governed the prior secured credit facility, the Company had to, among other things, make certain mandatory prepayments of debt outstanding under the credit facility. Accordingly, in addition to its scheduled payments, in January 2012, the Company used the net proceeds from asset sales to retire $17.6 million of the outstanding balance of the Company’s term loan facility as required under the prior credit agreement.

On April 3, 2012, the Company entered into a new Credit Agreement, which governs its new credit facility (the “Credit Agreement”), which provides for a $75.0 million senior secured revolving credit facility, with a $25.0 million sublimit for the issuance of letters of credit. In connection with these events, the Company terminated its prior credit agreement dated July 11, 2007, as amended to date. On April 3, 2012, the Company repaid in full all outstanding indebtedness under the prior secured credit facility, and the liens securing such obligations were terminated. There were no termination penalties incurred by the Company in connection with the termination of the prior secured credit facility.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

The Company may prepay borrowings under the new revolving credit facility at any time without premium or penalty (other than customary LIBOR breakage costs), subject to certain notice requirements. The Credit Agreement requires mandatory prepayments of amounts outstanding thereunder with the net proceeds of certain asset sales, casualty events, preferred stock issuances and debt issuances, but these mandatory prepayments do not require any reduction of the lenders' commitments under the Credit Agreement. All borrowings under the new revolving credit facility mature on April 3, 2017.

Borrowings under the Credit Agreement bear interest, at the Company's option, at either (i) the Alternate Base Rate (“ABR”) (the highest of the administrative agent's corporate base rate of interest, the federal funds rate plus 0.5%, or the one-month Eurodollar rate (as defined in the Credit Agreement) plus 1%), plus an applicable margin that ranges between 3.0% and 4.5%, depending on the Company's leverage ratio, or (ii) the Eurodollar rate plus an applicable margin that ranges between 4.0% and 5.5%, depending on the Company's leverage ratio. The Company will pay a per annum fee on all letters of credit issued under the Credit Agreement, which fee will equal the applicable margin for loans accruing interest based on the Eurodollar rate, and the Company will pay a commitment fee of 0.75% per annum on the unused availability under the Credit Agreement.

The Credit Agreement contains covenants that, among other things, limit the Company’s ability to:

•

incur additional indebtedness or issue certain preferred stock;

•

pay dividends or make other distributions;

•

make other restricted payments or investments;

•

sell assets;

•

create liens;

•

enter into agreements that restrict dividends and other payments by restricted subsidiaries;

•

engage in transactions with affiliates; and

•

consolidate, merge or transfer all or substantially all of its assets.

In addition, during any period of time that outstanding letters of credit under the Credit Agreement exceed $10 million or there are any revolving borrowings outstanding under the Credit Agreement, the Company will have to maintain compliance with a maximum secured leverage ratio (as defined in the Credit Agreement, being generally computed as the ratio of secured indebtedness to consolidated cash flow). The maximum secured leverage ratio is as follows:

Period

Maximum Secured
Leverage Ratio

April 1, 2012

—

September 30, 2012

4.25 to 1.00

October 1, 2012 and thereafter

3.50 to 1.00

The Company’s obligations under the new revolving credit facility are guaranteed by substantially all of the Company’s current domestic subsidiaries (collectively, the “Guarantors”), and the obligations of the Company and the Guarantors are secured by liens on substantially all of the vessels owned by the Company and the Guarantors, together with certain accounts receivable, equity of subsidiaries, equipment and other assets.

The Credit Agreement contains customary events of default. The Credit Agreement also contains a provision under which an event of default on any other indebtedness exceeding $25.0 million would be considered an event of default under the Credit Agreement.

7.125% Senior Secured Notes due 2017

On April 3, 2012, the Company completed the issuance and sale of $300.0 million aggregate principal amount of senior secured notes at a coupon rate of 7.125% (“7.125% Senior Secured Notes”) with maturity in April 2017. These notes were sold at par and the Company received net proceeds from the offering of the notes of approximately $293.8 million after deducting the initial purchasers' discounts and estimated offering expenses. Interest on the notes will accrue from and including April 3, 2012 at a rate of 7.125% per year and is payable semi-annually in arrears on April 1 and October 1 of each year, beginning October 1, 2012.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

The 7.125% Senior Secured Notes are guaranteed by each of the Guarantors that guarantee the Company’s obligations under its new revolving credit facility that was executed on April 3, 2012. The notes are secured by liens on all collateral that secures the Company’s obligations under its secured credit facility, subject to limited exceptions. The liens securing the notes share on an equal and ratable first priority basis with liens securing the Company’s credit facility. Under the intercreditor agreement the collateral agent for the lenders under the Company’s secured credit facility is generally entitled to sole control of all decisions and actions.

The indenture governing the notes contains covenants that, among other things, limit the Company’s ability and the ability of the Company’s restricted subsidiaries to:

•

incur additional indebtedness or issue certain preferred stock;

•

pay dividends or make other distributions;

•

make other restricted payments or investments;

•

sell assets;

•

create liens;

•

enter into agreements that restrict dividends and other payments by restricted subsidiaries;

•

engage in transactions with affiliates; and

•

consolidate, merge or transfer all or substantially all of its assets.

The notes provide that the Company may, at its option, redeem all or part of the notes, at any time prior to April 1, 2014 at a redemption price equal to 100% of the aggregate principal amount of the notes to be redeemed, plus the Secured Applicable Premium as of, and accrued and unpaid interest, if any, to, the applicable redemption date. The term "Secured Applicable Premium" means, with respect to any note on any applicable redemption date, the greater of:

•

1% of the principal amount of such note, and

•

The excess, if any, of:

(a) the present value at such redemption date of (i) the redemption price of such note on April 1, 2014 plus (ii) all required interest payments (excluding accrued and unpaid interest to such redemption date) due on such note through April 1, 2014, computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points; over

(b) the principal amount of such note.

On or after April 1, 2014, the Company may redeem all or part of the notes at the redemption prices set forth below, together with accrued and unpaid interest, if any, to the redemption date, if redeemed during the 12-month period beginning April 1 of the years indicated:


Year	Optional Redemption Price
2014		105.344	%
2015		102.672	%
2016 and thereafter		100.000	%

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

If the Company experiences certain kinds of changes of control, holders of the notes will be entitled to require the Company to purchase all or any portion of the notes for a cash price equal to 101.0% of the principal amount of the applicable notes, plus accrued and unpaid interest, if any, to the date of purchase.

The indenture governing the notes contains customary events of default. The indenture governing the notes also contains a provision under which an event of default by the Company or by any restricted subsidiary on any other indebtedness exceeding $25.0 million would be considered an event of default under the indenture if such default: a) is caused by failure to pay the principal at final maturity, or b) results in the acceleration of such indebtedness prior to maturity.

10.25% Senior Notes due 2019

On April 3, 2012, the Company completed the issuance and sale of $200.0 million aggregate principal amount of senior notes at a coupon rate of 10.25% (“10.25% Senior Notes”) with maturity in April 2019. These notes were sold at par and the Company received net proceeds from the offering of the notes of approximately $195.8 million after deducting the initial purchasers’ discounts and estimated offering expenses. Interest on the notes will accrue from and including April 3, 2012 at a rate of 10.25% per year and is payable semi-annually in arrears on April 1 and October 1 of each year, beginning October 1, 2012.

The 10.25% Senior Notes are guaranteed by each of the Guarantors that guarantee the Company’s obligations under the Company’s new revolving credit facility that was executed on April 3, 2012.

The indenture governing the notes contains covenants that, among other things, limit the Company’s ability and the ability of our restricted subsidiaries to:

•

incur additional indebtedness or issue certain preferred stock;

•

pay dividends or make other distributions;

•

make other restricted payments or investments;

•

sell assets;

•

create liens;

•

enter into agreements that restrict dividends and other payments by restricted subsidiaries;

•

engage in transactions with affiliates; and

•

consolidate, merge or transfer all or substantially all of its assets.

The notes provide that the Company may, at its option, redeem all or part of the notes, at any time prior to April 1, 2015 at a redemption price equal to 100% of the aggregate principal amount of the notes to be redeemed, plus the Senior Applicable Premium as of, and accrued and unpaid interest, if any, to, the applicable redemption date. The term "Senior Applicable Premium" means, with respect to any note on any applicable redemption date, the greater of:

•

1% of the principal amount of such note, and

•

The excess, if any, of:

(a) the present value at such redemption date of (i) the redemption price of such note on April 1, 2015 plus (ii) all required interest payments (excluding accrued and unpaid interest to such redemption date) due on such note through April 1, 2015, computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points; over

(b) the principal amount of such note.

On or after April 1, 2015, the Company may redeem all or part of the notes at the redemption prices set forth below, together with accrued and unpaid interest, if any, to the redemption date, if redeemed during the 12-month period beginning April 1 of the years indicated:


Year	Optional Redemption Price
2015		107.688	%
2016		105.125	%
2017		102.563	%
2018 and thereafter		100.000	%

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

10.5% Senior Notes due 2017 (Formerly Secured prior to April 3, 2012)

The indenture governing the 10.5% Senior Notes provides that all the liens securing the notes may be released if the Company's total amount of secured indebtedness, other than the 10.5% Senior Notes, does not exceed the lesser of $375.0 million and 15.0% of the Company's consolidated tangible assets. The Company refers to such a release as a "collateral suspension." When a collateral suspension is in effect, the 10.5% Senior Notes due 2017 become unsecured. Following the closing of the recent transactions and the use of proceeds thereof to repay in full the prior secured credit facility, the liens securing the 10.5% Senior Notes were released on April 3, 2012. The indenture governing the 10.5% Senior Notes also provides that if, after any such collateral suspension, the aggregate principal amount of the Company's total secured indebtedness, other than the 10.5% Senior Notes due 2017, were to exceed the greater of $375.0 million and 15.0% of the Company's consolidated tangible assets, as defined in such indenture, then the collateral obligations of the Company and guarantors thereunder will be reinstated and must be complied with within 30 days of such event.

The 10.5% Senior Notes are guaranteed by each of the Guarantors that guarantee the Company’s obligations under its new revolving credit facility that was executed on April 3, 2012.

The indenture governing the notes contains covenants that, among other things, limit the Company’s ability and the ability of its restricted subsidiaries to:

•

incur additional indebtedness or issue certain preferred stock;

•

pay dividends or make other distributions;

•

make other restricted payments or investments;

•

sell assets;

•

create liens;

•

enter into agreements that restrict dividends and other payments by restricted subsidiaries;

•

engage in transactions with affiliates; and

•

consolidate, merge or transfer all or substantially all of its assets.

3.375% Convertible Senior Notes due 2038

The 3.375% Convertible Senior Notes will be convertible under certain circumstances into shares of the Company’s common stock (“Common Stock”) at an initial conversion rate of 19.9695 shares of Common Stock per $1,000 principal amount of notes, which is equal to an initial conversion price of approximately $50.08 per share. Upon conversion of a note, a holder will receive, at the Company's election, shares of Common Stock, cash or a combination of cash and shares of Common Stock. At March 31, 2012, the number of conversion shares potentially issuable in relation to the 3.375% Convertible Senior Notes was 1.9 million.

The indenture governing the notes contains customary events of default. The indenture governing the 3.375% Convertible Senior Notes contains a provision under which an event of default by the Company or by any subsidiary on any other indebtedness exceeding $25.0 million would be considered an event of default under the indenture if such default is: a) caused by failure to pay the principal at final maturity, or b) results in the acceleration of such indebtedness prior to maturity.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

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

7. Derivative Instruments

The Company was issued warrants to purchase up to 5.0 million additional shares of Discovery Offshore stock at a strike price of 11.5 Norwegian Kroner (“NOK”) per share which is exercisable in the event that the Discovery Offshore stock price reaches an average equal to or higher than 23 NOK per share for 30 consecutive trading days. As of March 31, 2012, Discovery Offshore’s stock price was 10.5 NOK per share. The warrants are being accounted for as a derivative instrument as the underlying security is readily convertible to cash. Subsequent changes in the fair value of the warrants are recognized to other income (expense). The fair value of the Discovery Offshore warrants was determined using a Monte Carlo simulation (See Note 8).

The following table provides the fair values of the Company’s derivatives (in thousands):


	March 31, 2012		December 31, 2011
Balance Sheet	Fair		Fair
Classification	Value		Value
Derivatives:
Warrants	$	2,806	$	1,758

Other Assets, Net	$	2,806	$	1,758

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

The following table provides the effect of the Company’s derivatives on the Consolidated Statements of Operations (in thousands):


	Three Months Ended March 31,
			2012	2011
Derivatives	I.		II.
Warrants		Other Income (Expense)	$1,048	$	155

Classification of Gain (Loss) Recognized in Income (Loss) on Derivative

II.

Amount of Gain (Loss) Recognized in Income (Loss) on Derivative

8. Fair Value Measurements

Fair value measurements are generally based upon observable and unobservable inputs. Observable inputs reflect market data obtained from independent sources, while unobservable inputs reflect the Company’s view of market assumptions in the absence of observable market information. The Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company uses the fair value hierarchy included in Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 820-10, Fair Value Measurements and Disclosure (“ASC-820-10”), which is intended to increase consistency and comparability in fair value measurements and related disclosures. The fair value hierarchy consists of the following three levels:


Level 1	—	Inputs are quoted prices in active markets for identical assets or liabilities.
Level 2	—	Inputs are quoted prices for similar assets or liabilities in an active market, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable and market-corroborated inputs which are derived principally from or corroborated by observable market data.
Level 3	—	Inputs are derived from valuation techniques in which one or more significant inputs or value drivers are unobservable.

As of March 31, 2012 the fair value of the warrants issued by Discovery Offshore was $2.8 million. The fair value of the warrants was determined using a Monte Carlo simulation based on the following assumptions:


	March 31, 2012
Strike Price (NOK)		11.50
Target Price (NOK)		23.00
Stock Value (NOK)		10.50
Expected Volatility (%)		50.0	%
Risk-Free Interest Rate (%)		0.74	%
Expected Life of Warrants (5.0 years at inception with 3.85 years remaining)		3.85
Number of Warrants		5,000,000

The Company used the historical volatility of companies similar to that of Discovery Offshore to estimate volatility. The risk-free interest rate assumption was based on observed interest rates consistent with the approximate life of the warrants. The stock price represents the closing stock price of Discovery Offshore stock at March 31, 2012. The strike price, target price, expected life and number of warrants are all contractual based on the terms of the warrant agreement.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

The following table represents the Company’s derivative asset for the warrants issued by Discovery Offshore measured at fair value on a recurring basis as of March 31, 2012 and December 31, 2011 (in thousands):


	Total Fair Value Measurement		Quoted Prices in Active Markets for Identical Asset or Liability (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
March 31, 2012	$	2,806	$	—	$	2,806	$	—
December 31, 2011	$	1,758	$	—	$	1,758	$	—

The carrying value and fair value of the Company’s equity investment in Discovery Offshore was $34.6 million and $33.9 million at March 31, 2012, respectively, and $34.7 million and $26.1 million at December 31, 2011, respectively. The fair value at March 31, 2012 and December 31, 2011 was calculated using the closing price of Discovery Offshore shares at each date respectively, converted to U.S. dollars using the exchange rate at each date respectively.

Fair Value of Financial Instruments

The carrying amounts of the Company’s financial instruments, which include cash and cash equivalents, restricted cash, accounts receivable, accounts payable and accrued liabilities, approximate fair values because of the short-term nature of the instruments.

The fair value of the Company’s 3.375% Convertible Senior Notes, 10.5% Senior Notes and term loan facility is estimated based on quoted prices in active markets. The fair value of the Company’s 7.375% Senior Notes is estimated based on discounted cash flows using inputs from quoted prices in active markets for similar debt instruments. The inputs used to determine fair value are considered level two inputs. The following table provides the carrying value and fair value of the Company’s long-term debt instruments:


	March 31, 2012				December 31, 2011
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in millions)
Term Loan Facility, due July 2013	$	435.3	$	434.5	$	452.9	$	442.0
10.5% Senior Notes, due October 2017		293.9		315.9		293.7		291.2
3.375% Convertible Senior Notes, due June 2038		91.2		94.7		90.2		84.7
7.375% Senior Notes, due April 2018		3.5		3.1		3.5		2.8

9. Long-Term Incentive Awards

The Company’s 2004 Amended and Restated Long-Term Incentive Plan (the “2004 Plan”) provides for the granting of stock options, restricted stock, phantom stock, performance stock awards and other stock-based awards to selected employees and non-employee directors of the Company. At March 31, 2012, approximately 5.8 million shares were available for grant or award under the 2004 Plan, as amended in May 2011.

During the three months ended March 31, 2012, the Company granted the following restricted stock awards:

•

Time-based awards – The Company granted 0.7 million time-based restricted stock awards with a grant-date fair value per share of $5.28 (the closing stock price on the grant date). These awards vest 1/3 per year.

•

Objective-based awards – The Company granted additional compensation awards to employees that are based on the Company’s achievement of certain Company-based performance objectives as well as the Company’s achievement of certain market-based objectives, with 50% weighting for each objective, as defined below:

A threshold, target and maximum number of shares have been established for each performance objective, with the employee vesting 25% (30% for executives) more shares at the maximum level, 25% (30% for executives) less shares at the threshold level, with vesting pro-rated between levels. At the target level approximately 0.8 million shares are issuable upon vesting. No shares will be issued with respect to a particular metric if the threshold performance objective is not met with respect to each such metric. The Company’s Chief Executive Officer was granted an objective-based cash incentive award based on the same performance objectives, vesting at $0.1 million, $0.5 million and $1.0 million at the threshold, target and maximum levels, respectively.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

If the performance and market-based objectives are achieved up to the Target level (as defined per the agreements), the awards will be settled in shares and vest 1/3 per year.

If the performance and market-based objectives are achieved above Target and up to the Maximum level, the portion of the grant that is above Target and up to the Maximum level will be settled in cash and will cliff vest at the first anniversary of the grant date.

The Company has certain other awards (“Liability Retention Awards”) granted in 2011 to the Company’s Chief Executive Officer as retention and incentive arrangements. The first award (“Special Retention Award”) is a time based award, which provides for a cash payment equal to the product of 500,000 shares of the Company’s common stock and the lesser of the average price of the Company’s common stock for the 90 days prior to the date of vesting (“Average Share Price”) and $10.00. The fair value of the Special Retention Award is valued based on the average price of the Company’s common stock for the 90 days prior to the end of the quarter or date of vesting. The second and third awards are performance awards under the 2004 Plan (“Performance Retention Award”). Each Performance Retention Award provides for a cash payment based on 250,000 shares of the Company’s common stock. Under each Performance Retention Award, vesting is subject to time based vesting and the further requirement that the Average Share Price is at least $5.00. Subject to the satisfaction of the vesting requirements, the payout of each Performance Retention Award shall be equal to the product of (1) 250,000, (2) the Average Share Price or $10.00, whichever is less, divided by $10.00, and (3) the lesser of the Average Share Price or $10.00.

The Company accounts for awards, or the portion of the awards, requiring cash settlement under stock-compensation principles of accounting as liability instruments. The fair value of all liability instruments are being remeasured based on the awards’ estimated fair value at the end of each reporting period and are being recorded to expense over the vesting period. The awards that are based on the Company’s achievement of market-based objectives related to the Company’s stock price are valued using a Monte Carlo simulation based on the following weighted-average assumptions:


	March 31, 2012
	Performance Retention Awards			Restriced Stock Market-Based
Dividend Yield		—			—
Expected Price Volatility		65.0	%		65.0	%
Risk-Free Interest Rate		0.3	%		0.2	%
Stock Price	$	4.73		$	4.73
Fair Value	$	2.03		$	4.73

The Company used the historical volatility of its common stock to estimate volatility. The dividend yield assumption was based on historical and anticipated dividend payouts. The risk-free interest rate assumption was based on observed interest rates consistent with the approximate vesting period. The stock price represents the closing price of the Company’s common stock at March 31, 2012.

The fair value of all awards requiring share settlement are measured at the fair value on the date of grant. These awards that are based on the Company’s achievement of market-based objectives related to the Company’s stock price are valued at the date of grant using a Monte Carlo simulation based on the following assumptions:


	February 28,
	2012
Dividend Yield		—
Expected Price Volatility		65	%
Risk-Free Interest Rate		0.2	%
Stock Price	$	5.28
Fair Value	$	5.28

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

The following table represents the Company’s liability related to incentive awards:


	March 31, 2012		December 31, 2011
	(In thousands)
Liability Retention Awards	$	1,409	$	917
Liability-based Awards Company-Based Performance Objective		17		—
Liability-based Awards Market-Based Objective		38		—

Total Liability	$	1,464	$	917

The following table represents compensation expense recognized for incentive awards:


	Three Months Ended March 31,
	2012		2011
	(In thousands)
Compensation Expense—share settled	$	1,487	$	1,158
Compensation Expense—cash settled		546		317

Total Compensation Expense	$	2,033	$	1,475

The following table represents the Company’s estimated unrecognized compensation expense and the weighted average remaining term over which such expense is expected to be recognized:


	March 31, 2012
	Unrecognized Compensation Expense		Weighted Average Remaining Term
	(In thousands)		(In years)
Share-based awards:
Options	$	659		0.9
Service-based Restricted Stock		6,775		1.9
Restricted Stock Company-Based Performance Objective		3,784		2.3
Restricted Stock Market-Based Objective		1,200		2.9
Liability-based awards:
Liability Retention Awards		2,011		1.8
Liability-based Awards Company-Based Performance Objective		170		0.9
Liability-based Awards Market-Based Objective		380		0.9

10. Supplemental Cash Flow Information

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED


	Three Months Ended March 31,
	2012		2011
	(In thousands)
Cash paid (received), net during the period for:
Interest	$	8,800	$	41
Income taxes		190		(4,199	)

11. Income Tax

The Company, directly or through its subsidiaries, files income tax returns in the United States, and multiple state and foreign jurisdictions. The Company’s tax returns for 2005 through 2010 remain open for examination by the taxing authorities in the respective jurisdictions where those returns were filed. Although the Company believes that its estimates are reasonable, the final outcome in the event that the Company is subjected to an audit could be different from that which is reflected in its historical income tax provision and accruals. Such differences could have a material effect on the Company’s income tax provision and net income in the period in which such determination is made. In addition, certain tax returns filed by TODCO and its subsidiaries are open for years prior to 2004, however TODCO tax obligations from periods prior to its initial public offering in 2004 are indemnified by Transocean under the tax sharing agreement, except for the Trinidad and Tobago jurisdiction. The Company’s Trinidadian tax returns are open for examination for the years 2005 through 2010.

In January 2008, SENIAT, the national Venezuelan tax authority, commenced an audit for the 2003 calendar year, which was completed in the fourth quarter of 2008. The Company has not yet received any proposed adjustments from SENIAT for that year.

Effective April 27, 2011 the Company completed the Seahawk Transaction. The Company’s financial statements have been prepared assuming that this transaction should be characterized as a purchase of assets for income tax purposes. Seahawk is currently in a Chapter 11 proceeding in the United States Bankruptcy Court. The resolution of the bankruptcy and future actions taken in the reorganization of Seahawk’s operations may require that the transaction is instead treated by the Company as a reorganization pursuant to IRC §368(a)(1)(G). Any resulting change, which is currently indeterminable, to the Company’s financial position would be reflected in its financial statements as a period adjustment to income at that future date.

The Company was in a net income tax payable position of $12.5 million at March 31, 2012 and $4.8 million at December 31, 2011, which is included in Other Current Liabilities on the Consolidated Balance Sheets.

12. Segments

The Company reports its business activities in five business segments: (1) Domestic Offshore, (2) International Offshore, (3) Inland, (4) Domestic Liftboats and (5) International Liftboats. The financial information of the Company’s discontinued operations is not included in the results of operations presented for the Company’s reporting segments (See Note 5). The Company eliminates inter-segment revenue and expenses, if any.

The following describes the Company’s reporting segments as of March 31, 2012:

Domestic Offshore — includes 34 jackup rigs and two submersible rigs in the U.S. Gulf of Mexico that can drill in maximum water depths ranging from 85 to 350 feet. Eighteen of the jackup rigs are either working on short-term contracts or available for contracts and sixteen are cold stacked. Both submersibles are cold stacked.

International Offshore — includes nine jackup rigs and one platform rig outside of the U.S. Gulf of Mexico. The Company has two jackup rigs contracted offshore in Saudi Arabia, one jackup rig contracted offshore in each of Indonesia and the Democratic Republic of Congo and one platform rig under contract in Mexico. The Company has one jackup rig warm stacked in each of Bahrain and Malaysia and one jackup rig cold stacked in Bahrain. One jackup rig is contracted in Angola, however the rig departed the shipyard at Pascagoula, Mississippi after undergoing repairs. The Company currently estimates that the rig will be back in service in early May 2012. The Company has one recently acquired jackup rig in a shipyard in Mississippi to prepare to be transported to a shipyard in the Middle East in the second quarter of 2012 where it will undergo upgrades to prepare for a contract in Saudi Arabia. In addition to owning and operating its own rigs, the Company has a Construction Management Agreement and the Services Agreement with Discovery Offshore.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

Inland — includes a fleet of six conventional and eleven posted barge rigs that operate inland in marshes, rivers, lakes and shallow bay or coastal waterways along the U.S. Gulf Coast. Three of the Company’s inland barges are either operating on short-term contracts or available and fourteen are cold stacked.

Domestic Liftboats — includes 40 liftboats in the U.S. Gulf of Mexico. Thirty-four are operating or available and six are cold stacked. In April 2012, the Company entered into a contract with a heavylift company to transport the Kingfish, a 230 class liftboat located in the U.S. Gulf of Mexico, to the Middle East in the second quarter of 2012. The vessel will undergo upgrades and is anticipated to be available for work early in the fourth quarter of 2012.

International Liftboats — includes 23 liftboats. Eighteen are operating or available for contracts offshore West Africa, including five liftboats owned by a third party, three are cold stacked offshore West Africa and two are operating or available for contracts in the Middle East region.

The Company’s jackup rigs, submersible rigs and platform rigs are used primarily for exploration and development drilling in shallow waters. The Company’s liftboats are self-propelled, self-elevating vessels with a large open deck space, which provides a versatile, mobile and stable platform to support a broad range of offshore maintenance and construction services throughout the life of an oil or natural gas well.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

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


	Three Months Ended March 31, 2012
	Revenue		Income (Loss) from Operations			Depreciation & Amortization
Domestic Offshore	$	82,318	$	1,777		$	18,018
International Offshore		18,048		(20,849	)		12,341
Inland		4,333		(4,598	)		3,209
Domestic Liftboats		10,431		(2,322	)		3,787
International Liftboats		28,189		8,569			4,990

		143,319		(17,423	)		42,345
Corporate		—		(11,147	)		633

Total Company	$	143,319	$	(28,570	)	$	42,978


	Three Months Ended March 31, 2011
	Revenue		Income (Loss) from Operations			Depreciation & Amortization
Domestic Offshore	$	33,799	$	(25,130	)	$	15,082
International Offshore		77,119		32,674			13,300
Inland		5,502		(6,379	)		4,621
Domestic Liftboats		10,631		(3,369	)		3,641
International Liftboats		32,327		11,601			4,498

		159,378		9,397			41,142
Corporate		—		(11,019	)		651

Total Company	$	159,378	$	(1,622	)	$	41,793


	Total Assets
	March 31,		December 31,
	2012		2011
Domestic Offshore	$	955,730	$	890,339
International Offshore		691,731		705,831
Inland		114,475		119,356
Domestic Liftboats		77,820		82,234
International Liftboats		146,209		154,974
Corporate		55,357		53,970

Total Company	$	2,041,322	$	2,006,704

13. Commitments and Contingencies

Legal Proceedings

The Company is involved in various claims and lawsuits in the normal course of business. As of March 31, 2012, management did not believe any accruals were necessary in accordance with FASB ASC 450-20, Contingencies – Loss Contingencies.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

Shareholder Derivative Suits

FCPA Litigation

As disclosed in the Company’s prior filings, on April 27, 2011, a shareholder derivative action was filed in the District Court of Harris County, Texas, allegedly on behalf of the Company, naming the Company as a nominal defendant and certain of its officers and directors as defendants alleging, among other claims, breach of fiduciary duty, abuse of control, waste of corporate assets, and unjust enrichment. The petition alleges that the individual defendants allowed the Company to violate the U.S. Foreign Corrupt Practices Act (“FCPA”) and failed to maintain internal controls and accounting systems for compliance with the FCPA. Plaintiffs sought restitution and injunctive and/or equitable relief purportedly on behalf of the Company, certain corporate actions, and an award of their costs and attorney’s fees.

On February 10, 2012, the District Court dismissed the plaintiff’s action with prejudice. The plaintiff did not file an appeal by the March 12, 2012 deadline.

Say-on-Pay Litigation

In June, two separate shareholder derivative actions were filed purportedly on the Company’s behalf in response to its failure to receive a majority advisory “say-on-pay” vote in favor of the Company’s 2010 executive compensation. On June 8, 2011, the first action was filed in the District Court of Harris County, Texas, and on June 23, 2011, the second action was filed in the United States Court for the District of Delaware. Subsequently, on July 21, 2011, the plaintiff in the Harris County action filed a concurrent action in the United States District Court for the Southern District of Texas. Each action named the Company as a nominal defendant and certain of its officers and directors, as well as the Company’s Compensation Committee’s consultant, as defendants. Plaintiffs allege that the Company’s directors breached their fiduciary duty by approving excessive executive compensation for 2010, that the Compensation Committee consultant aided and abetted that breach of fiduciary duty, that the officer defendants were unjustly enriched by receiving the allegedly excessive compensation, and that the directors violated the federal securities laws by disseminating

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

a materially false and misleading proxy. The plaintiffs seek damages in an unspecified amount on the Company’s behalf from the officer and director defendants, certain corporate governance actions, and an award of their costs and attorney’s fees. The Company and the other defendants have filed motions to dismiss these cases for failure to make demand upon the Company’s board and for failing to state a claim. Those motions are pending.

The Company does not expect the ultimate outcome of any of these shareholder derivative lawsuits to have a material adverse effect on its consolidated results of operations, financial position or cash flows.

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

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

Insurance

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

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

In April 2011, the Company completed the annual renewal of all of its key insurance policies. The Company’s primary marine package provides for hull and machinery coverage for substantially all of the Company’s rigs and liftboats up to a scheduled value of each asset. The total maximum amount of coverage for these assets is $1.6 billion, including the acquired Seahawk units. The marine package includes protection and indemnity and maritime employer’s liability coverage for marine crew personal injury and death and certain operational liabilities, with primary coverage (or self-insured retention for maritime employer’s liability coverage) of $5.0 million per occurrence with excess liability coverage up to $200.0 million. The marine package policy also includes coverage for personal injury and death of third parties with primary and excess coverage of $25 million per occurrence with additional excess liability coverage up to $200 million, subject to a $250,000 per-occurrence deductible. The marine package also provides coverage for cargo and charterer’s legal liability. The marine package includes limitations for coverage for losses caused in U.S. Gulf of Mexico named windstorms, including an annual aggregate limit of liability of $75.0 million for property damage and removal of wreck liability coverage. The Company also procured an additional $75.0 million excess policy for removal of wreck and certain third-party liabilities incurred in U.S. Gulf of Mexico named windstorms. Deductibles for events that are not caused by a U.S. Gulf of Mexico named windstorm are 12.5% of the insured drilling rig values per occurrence, subject to a minimum of $1.0 million, and $1.0 million per occurrence for liftboats. The deductible for drilling rigs and liftboats in a U.S. Gulf of Mexico named windstorm event is $25.0 million. Vessel pollution is covered under a Water Quality Insurance Syndicate policy (“WQIS Policy”) providing limits as required by applicable law, including the Oil Pollution Act of 1990. The WQIS Policy covers pollution emanating from the Company’s vessels and drilling rigs, with primary limits of $5 million (inclusive of a $3.0 million per-occurrence deductible) and excess liability coverage up to $200 million.

Control-of-well events generally include an unintended flow from the well that cannot be contained by equipment on site (e.g., a blow-out preventer), by increasing the weight of the drilling fluid or that does not naturally close itself off through what is typically described as bridging over. The Company carries a contractor’s extra expense policy with $25.0 million primary liability coverage for well control costs, expenses incurred to redrill wild or lost wells and pollution, with excess liability coverage up to $200 million for pollution liability that is covered in the primary policy. The policies are subject to exclusions, limitations, deductibles, self-insured retention and other conditions. In addition to the marine package, the Company has separate policies providing coverage for onshore foreign and domestic general liability, employer’s liability, auto liability and non-owned aircraft liability, with customary deductibles and coverage.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

The Company’s drilling contracts provide for varying levels of indemnification from its customers and in most cases, may require the Company to indemnify its customers for certain liabilities. Under the Company’s drilling contracts, liability with respect to personnel and property is customarily assigned on a “knock-for-knock” basis, which means that the Company and its customers assume liability for their respective personnel and property, regardless of how the loss or damage to the personnel and property may be caused. The Company’s customers typically assume responsibility for and agree to indemnify the Company from any loss or liability resulting from pollution or contamination, including clean-up and removal and third-party damages arising from operations under the contract and originating below the surface of the water, including as a result of blow-outs or cratering of the well (“Blowout Liability”). The customer’s assumption for Blowout Liability may, in certain circumstances, be limited or could be determined to be unenforceable in the event of the Company’s gross negligence, willful misconduct or other egregious conduct. The Company generally indemnifies the customer for the consequences of spills of industrial waste or other liquids originating solely above the surface of the water and emanating from its rigs or vessels.

In 2011, in connection with the renewal of certain of its insurance policies, the Company entered into an agreement to finance a portion of its annual insurance premiums. Approximately $25.8 million was financed through this arrangement with an interest rate of 3.59%. There was $5.2 million outstanding in insurance notes payable as of December 31, 2011 which was fully paid during the three months ended March 31, 2012.

Insurance Claims

In September 2011, the Company was conducting a required annual spud can inspection on the Hercules 185 in protected waters offshore Angola. While conducting the inspection, it was determined that the spud can on the starboard leg had detached from the leg. While preparing the rig for heavy-lift transport to a shipyard in Pascagoula, Mississippi to conduct the spud can repairs, additional leg damage was identified. The rig recently arrived back in Angola after undergoing repairs. The Company currently estimates that the rig will be back in service in early May 2012. While the rig was being repaired and during its mobilization back to Angola, the rig has been on zero dayrate pursuant to its contract with Cabinda Gulf Oil Company. The Company expects to be insured for damage to the rig up to the insured value of $35.0 million, subject to a $3.5 million deductible and other customary limitations and exclusions. The Company recorded expenses up to the deductible amount of $3.5 million during the year ended December 31, 2011 related to rig repairs, inspections and other costs and has recorded an insurance claims receivable of $13.4 million and $6.4 million as of March 31, 2012 and December 31, 2011, respectively, for cumulative costs incurred through each of those dates in excess of the deductible, which is included in Other on the Consolidated Balance Sheets.

In September 2011, the Starfish, a 140 class liftboat, was en route to a project in the Gulf of Mexico when it was hit by a series of waterspouts and capsized. The vessel was salvaged and the underwriters determined that the vessel was a constructive total loss and, therefore, the Company received the full insured value of $2.5 million and recognized a gain of $1.8 million during the three months ended March 31, 2012, which is included in Operating Expenses in the Consolidated Statements of Operations. Additionally, the Company received reimbursement of costs incurred in excess of the Company’s deductible for the salvage operation.

In January 2012, the Mako, a 175 class liftboat in Nigeria, was engulfed by a fire that originated on a third-party rig, the KS Endeavor. The Company’s underwriters determined that the vessel was a constructive total loss and, therefore, the Company received the full insured value of $8.0 million and recognized a gain of $1.6 million during the three months ended March 31, 2012, which is included in Operating Expenses in the Consolidated Statements of Operations.

Surety Bonds, Bank Guarantees and Letters of Credit

The Company had $13.6 million outstanding related to surety bonds at March 31, 2012, of which $9.6 million was cash collaterialized. The surety bonds guarantee the Company’s performance as it relates to its drilling contracts and other obligations in various jurisdictions. These obligations could be called at any time prior to the expiration dates. The obligations that are the subject of the surety bonds are geographically concentrated in Mexico and the U.S.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

The Company had $1.0 million in unsecured bank guarantees, $3.6 million in cash collateralized letters of credit and a $0.1 million unsecured letter of credit outstanding at March 31, 2012.

14. Accounting Pronouncements

In May 2011, the FASB issued Accounting Standards Update (“ASU”) No. 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“ASU 2011-04”), which changes the wording used to describe many of the requirements in U.S. GAAP for measuring fair value and disclosing information about fair value measurements. Some of the amendments clarify the FASB’s intent about the application of existing fair value measurement requirements while other amendments change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. The amendments in this ASU are effective prospectively for interim and annual periods beginning after December 15, 2011, with no early adoption permitted. The Company adopted this standard as of January 1, 2012 with no material impact on its consolidated financial statements.

15. Subsequent Events

The Company had the following subsequent events occur in April 2012:

•

Received a cash payment of $10.0 million from Angola Drilling Company Ltd., a customer in Angola (the “Customer”), which represented a partial payment on the balance owed to the Company from the Customer pursuant to a drilling contract for the Hercules 185 for services provided from July 2009 through January 2011;

•

Issued $300.0 million aggregate principal amount of 7.125% Senior Secured Notes due 2017;

•

Issued $200.0 million aggregate principal amount of 10.25% Senior Notes due 2019;

•

Entered into a new credit agreement that provides for a $75.0 million senior secured revolving credit facility, with a $25.0 million sublimit for the issuance of letters of credit;

•

Terminated its prior credit agreement dated July 11, 2007, as amended to date, which included an undrawn $140.0 million revolving credit facility and a term loan balance of $435.3 million as of March 31, 2012;

•

Repaid in full all outstanding indebtedness under the prior secured credit facility, and the liens securing such obligations were terminated; and

•

In connection with the aforementioned notes issuances and the repayment of the prior secured credit facility, the Company’s secured indebtedness was reduced below the threshold (as defined by the indenture governing the 10.5% Senior Notes), whereby, all the liens securing the 10.5% Senior Notes were released.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the accompanying unaudited consolidated financial statements as of March 31, 2012 and 2011, included elsewhere herein, and with our Annual Report on Form 10-K for the year ended December 31, 2011. The following information contains forward-looking statements. Please read “Forward-Looking Statements” below for a discussion of certain limitations inherent in such statements. Please also read “Risk Factors” in Item 1A of our Annual Report on Form 10-K, for the year ended December 31, 2011, and Item 1A of Part II of this quarterly report for a discussion of certain risks facing our company.

OVERVIEW

We are a leading provider of shallow-water drilling and marine services to the oil and natural gas exploration and production industry globally. We provide these services to national oil and gas companies, major integrated energy companies and independent oil and natural gas operators. We own a fleet of 43 jackup rigs, seventeen barge rigs, two submersible rigs, one platform rig and 58 liftboat vessels and operate an additional five liftboat vessels owned by a third party. Our diverse fleet is capable of providing services such as oil and gas exploration and development drilling, well service, platform inspection, maintenance and decommissioning operations in several key shallow water provinces around the world.

We report our business activities in five business segments, which, as of April 19, 2012, included the following:

International Offshore — includes nine jackup rigs and one platform rig outside of the U.S. Gulf of Mexico. We have two jackup rigs contracted offshore in Saudi Arabia, one jackup rig contracted offshore in each of Indonesia and the Democratic Republic of Congo and one platform rig contracted offshore in Mexico. In addition, we have one jackup rig warm stacked in each of Bahrain and Malaysia and one jackup rig cold stacked in Bahrain. One jackup rig, contracted in Angola, has been in the shipyard at Pascagoula, Mississippi undergoing repairs. The rig recently arrived back in Angola and we currently estimate that the rig will be back in service in early May 2012. We have one recently acquired jackup rig in a shipyard in Mississippi to prepare to be transported to a shipyard in the Middle East in the second quarter of 2012 where it will undergo upgrades to prepare for a contract in Saudi Arabia which is expected to commence in December 2012. In addition to owning and operating our own rigs, we have the Construction Management Agreement and the Services Agreement with Discovery Offshore with respect to each of the Rigs.

Inland — includes a fleet of six conventional and eleven posted barge rigs that operate inland in marshes, rivers, lakes and shallow bay or coastal waterways along the U.S. Gulf Coast. Three of our inland barges are either operating on short-term contracts or available and fourteen are cold stacked.

Domestic Liftboats — includes 40 liftboats in the U.S. Gulf of Mexico. Thirty-four are operating or available and six are cold stacked. In April 2012, we entered into a contract with a heavylift company to transport the Kingfish, a 230 class liftboat located in the U.S. Gulf of Mexico, to the Middle East in the second quarter of 2012. The vessel will undergo upgrades and is anticipated to be available for work early in the fourth quarter of 2012.

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

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

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

Our backlog at April 19, 2012 totaled approximately $589.0 million for our executed contracts. Approximately $265.9 million of this backlog is expected to be realized during the remainder of 2012. We calculate our contract revenue backlog, or future contracted revenue, as the contract dayrate multiplied by the number of days remaining on the contract, assuming full utilization. Backlog excludes revenue for management agreements, mobilization, demobilization, contract preparation and customer reimbursables. The amount of actual revenue earned and the actual periods during which revenue is earned will be different than the backlog disclosed or expected due to various factors. Downtime due to various operational factors, including unscheduled repairs, maintenance, operational delays, health, safety and environmental incidents, weather events in the Gulf of Mexico and elsewhere and other factors (some of which are beyond our control), may result in lower dayrates than the full contractual operating dayrate. In some of the contracts, our customer has the right to terminate the contract without penalty and in certain instances, with little or no notice.

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

The most significant costs for our Domestic Liftboats and International Liftboats segments are the wages paid to crews and the amortization of regulatory drydocking costs. Unlike our Domestic Offshore, International Offshore and Inland segments, a significant portion of the expenses incurred with operating each liftboat are paid for or reimbursed by the customer under contractual terms and prices. This includes catering, fuel, oil, rental equipment, crane overtime and other items. We record reimbursements from customers as revenue and the related expenses as operating costs. Our liftboats are required to undergo regulatory inspections every year and to be drydocked two times every five years; the drydocking expenses and length of time in drydock vary depending on the condition of the vessel. All costs directly associated with regulatory inspections, including related drydocking costs, are deferred and amortized over a period of twelve months.

Rig Acquisition

In March 2012, we acquired the offshore jackup drilling rig Hercules 266 (formerly known as Ocean Columbia) from a subsidiary of Diamond Offshore Drilling, Inc. for $40.0 million. We have entered into a three-year drilling contract with Saudi Aramco for the use of this rig with an option to extend the term for an additional one-year period. We expect to spend approximately $45.0 million for upgrades and other contract specific refurbishments to the rig and to mobilize the rig from the Gulf of Mexico to the Middle East. We expect the rig to commence work under the contract in December 2012.

Common Stock Offering

In March 2012, we raised approximately $96.7 million in net proceeds after adjusting for underwriting discounts and expected offering expenses from an underwritten public offering of 20.0 million shares of its common stock, par value $0.01 per share at a price to the public of $5.10 per share ($4.85775, net of underwriting discounts). We also granted the Underwriters a 30-day option to purchase up to an additional 3.0 million shares of our common stock on the same terms as the 20.0 million

shares sold by us but it was not exercised. We used a portion of the net proceeds from the share offering to fund a portion of the purchase price for the acquisition of Hercules 266 and intend to use the remaining net proceeds for general corporate purposes as well as the costs associated with the upgrade and mobilization of Hercules 266.

Investigations

On April 4, 2011, we received a subpoena issued by the Securities and Exchange Commission (“SEC”) requesting the delivery of certain documents to the SEC in connection with its investigation into possible violations of the securities laws, including possible violations of the Foreign Corrupt Practices Act (“FCPA”) in certain international jurisdictions where we conduct operations. We were also notified by the Department of Justice (“DOJ”) on April 5, 2011, that certain of our activities were under review by the DOJ.

On April 24, 2012, we received a letter from the DOJ notifying us that the DOJ has closed its inquiry into us regarding possible violations of the FCPA and does not intend to pursue enforcement action against us. The DOJ indicated that its decision to close the matter was based on, among other factors, the thorough investigation conducted by our special counsel and our compliance program.

We, through the Audit Committee of the Board of Directors, intend to continue to cooperate with the SEC in its investigation. At this time, it is not possible to predict the outcome of the SEC’s investigation, the expenses we will incur associated with this matter, or the impact on the price of our common stock or other securities as a result of this investigation.

Regulations

The Coast Guard issued a Policy Letter in July 2011 that provides for more frequent inspections of foreign flagged Mobile Offshore Drilling Units (“MODUs”) that operate on the U.S. Outer Continental Shelf (“OCS”). The Coast Guard will make determinations to conduct more frequent inspections of foreign flagged MODUs in accordance with its newly-implemented Mobile Offshore Drilling Unit Safety and Environmental Protection Compliance Targeting Matrix. We may be subject to increased costs and potential downtime for certain of our rigs operating on the OCS if such rigs are determined by the Coast Guard to need additional oversight and inspection under this new Policy Letter.

In addition to this new Coast Guard Policy Letter, in November 2011, the Bureau of Safety and Environmental Enforcement (“BSEE”) announced a change in its enforcement policies in the aftermath of the Macondo well blowout in April 2010, pursuant to which the agency has extended its regulatory enforcement reach to include contractors as well as offshore lease operators. Consequently, the BSEE may elect to hold contractors, including drilling contractors, liable for alleged violations of law arising in the BSEE’s jurisdictional area. Implementation of this announced change in enforcement policy by the BSEE could subject us to added liabilities, including sanctions and penalties, as well as increased costs arising from contractual arrangements in master services agreements that failed to take into account such change in enforcement policy with respect to our operations in the U.S. Gulf of Mexico, which may have an adverse effect on our business and results of operations.

RECENT DEVELOPMENTS

On April 3, 2012, we made the following changes to our debt structure:

•

Issued $300.0 million aggregate principal amount of 7.125% Senior Secured Notes due 2017;

•

Issued $200.0 million aggregate principal amount of 10.25% Senior Notes due 2019;

•

Entered into a new credit agreement that provides for a $75.0 million senior secured revolving credit facility, with a $25.0 million sublimit for the issuance of letters of credit;

•

Terminated our prior credit agreement dated July 11, 2007, as amended to date, which included an undrawn $140.0 million revolving credit facility and a term loan balance of $435.3 million as of March 31, 2012;

•

Repaid in full all outstanding indebtedness under the prior secured credit facility, and the liens securing such obligations were terminated; and

•

On April 3, 2012, and in connection with the aforementioned notes issuances and the repayment of the prior secured credit facility, our secured indebtedness was reduced below the threshold (as defined by the indenture governing the 10.5% Senior Secured Notes), whereby, all the liens securing the 10.5% Senior Secured Notes were released (“10.5% Senior Notes”).

RESULTS OF OPERATIONS

Asset Purchase

On April 27, 2011, we completed our acquisition of 20 jackup rigs and related assets, accounts receivable, accounts payable and certain contractual rights from Seahawk Drilling, Inc. and certain of its subsidiaries (“Seahawk”) (“Seahawk Transaction”). The results of Seahawk are included in our results from the date of acquisition which impacts the comparability of the 2012 period with the corresponding 2011 period.

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


	Three Months Ended
	March 31,
	2012			2011			Change			% Change
	(Dollars in thousands)
Domestic Offshore:
Number of rigs (as of end of period)		36			25
Revenue	$	82,318		$	33,799		$	48,519			143.6	%
Operating expenses		59,871			41,002			18,869			46.0	%
Depreciation and amortization expense		18,018			15,082			2,936			19.5	%
General and administrative expenses		2,652			2,845			(193	)		(6.8	%)

Operating income (loss)	$	1,777		$	(25,130	)		26,907			n/m

International Offshore:
Number of rigs (as of end of period)		10			9
Revenue	$	18,048		$	77,119		$	(59,071	)		(76.6	%)
Operating expenses		24,127			33,828			(9,701	)		(28.7	%)
Depreciation and amortization expense		12,341			13,300			(959	)		(7.2	%)
General and administrative expenses		2,429			(2,683	)		5,112			n/m

Operating income (loss)	$	(20,849	)	$	32,674			(53,523	)		n/m

Inland:
Number of barges (as of end of period)		17			17
Revenue	$	4,333		$	5,502		$	(1,169	)		(21.2	%)
Operating expenses		5,679			7,030			(1,351	)		(19.2	%)
Depreciation and amortization expense		3,209			4,621			(1,412	)		(30.6	%)
General and administrative expenses		43			230			(187	)		(81.3	%)

Operating loss	$	(4,598	)	$	(6,379	)		1,781			(27.9	%)

Domestic Liftboats:
Number of liftboats (as of end of period)		40			41
Revenue	$	10,431		$	10,631		$	(200	)		(1.9	%)
Operating expenses		8,480			9,864			(1,384	)		(14.0	%)
Depreciation and amortization expense		3,787			3,641			146			4.0	%
General and administrative expenses		486			495			(9	)		(1.8	%)

Operating loss	$	(2,322	)	$	(3,369	)		1,047			(31.1	%)

International Liftboats:
Number of liftboats (as of end of period)		23			24
Revenue	$	28,189		$	32,327		$	(4,138	)		(12.8	%)
Operating expenses		13,080			14,657			(1,577	)		(10.8	%)
Depreciation and amortization expense		4,990			4,498			492			10.9	%
General and administrative expenses		1,550			1,571			(21	)		(1.3	%)

Operating income	$	8,569		$	11,601			(3,032	)		(26.1	%)


	Three Months Ended
	March 31,
	2012			2011			Change			% Change
	(Dollars in thousands)
Total Company:
Revenue	$	143,319		$	159,378		$	(16,059	)		(10.1	%)
Operating expenses		111,237			106,381			4,856			4.6	%
Depreciation and amortization		42,978			41,793			1,185			2.8	%
General and administrative		17,674			12,826			4,848			37.8	%

Operating loss		(28,570	)		(1,622	)		(26,948	)		n/m
Interest expense		(19,669	)		(18,506	)		(1,163	)		6.3	%
Other, net		1,009			(194	)		1,203			n/m

Loss before income taxes		(47,230	)		(20,322	)		(26,908	)		n/m
Income tax benefit		8,888			6,679			2,209			33.1	%

Loss from continuing operations		(38,342	)		(13,643	)		(24,699	)		n/m
Loss from discontinued operations, net of taxes		—			(576	)		576			n/m

Net loss	$	(38,342	)	$	(14,219	)	$	(24,123	)		n/m

“n/m” means not meaningful.

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


	Three Months Ended March 31, 2012
	Operating Days		Available Days		Utilization (1)			Average Revenue per Day (2)		Average Operating Expense per Day (3)
Domestic Offshore		1,471		1,638		89.8	%	$	55,961	$	36,551
International Offshore		247		637		38.8	%		73,069		37,876
Inland		137		273		50.2	%		31,628		20,802
Domestic Liftboats		1,342		3,094		43.4	%		7,773		2,741
International Liftboats		1,202		1,836		65.5	%		23,452		7,124


	Three Months Ended March 31, 2011
	Operating Days		Available Days		Utilization (1)			Average Revenue per Day (2)		Average Operating Expense per Day (3)
Domestic Offshore		788		990		79.6	%	$	42,892	$	41,416
International Offshore		582		720		80.8	%		132,507		46,983
Inland		205		270		75.9	%		26,839		26,037
Domestic Liftboats		1,330		3,420		38.9	%		7,993		2,884
International Liftboats		1,395		2,070		67.4	%		23,173		7,081

(1)	Utilization is defined as the total number of days our rigs or liftboats, as applicable, were under contract, known as operating days, in the period as a percentage of the total number of available days in the period. Days during which our rigs and liftboats

were undergoing major refurbishments, upgrades or construction, and days during which our rigs and liftboats are cold stacked, are not counted as available days. Days during which our liftboats are in the shipyard undergoing drydocking or inspection are considered available days for the purposes of calculating utilization.

(2)	Average revenue per rig or liftboat per day is defined as revenue earned by our rigs or liftboats, as applicable, in the period divided by the total number of operating days for our rigs or liftboats, as applicable, in the period.

(3)

Average operating expense per rig or liftboat per day is defined as operating expenses, excluding depreciation and amortization, incurred by our rigs or liftboats, as applicable, in the period divided by the total number of available days in the period. We use available days to calculate average operating expense per rig or liftboat per day rather than operating days, which are used to calculate average revenue per rig or liftboat per day, because we incur operating expenses on our rigs and liftboats even when they are not under contract and earning a dayrate. In addition, the operating expenses we incur on our rigs and liftboats per day when they are not under contract are typically lower than the per day expenses we incur when they are under contract.

For the Three Months Ended March 31, 2012 and 2011

Revenue

Consolidated. The decrease in consolidated revenue is described below.

Domestic Offshore. The rigs acquired from Seahawk contributed to $33.6 million of the increase in revenue from our Domestic Offshore segment. Excluding the revenue from the rigs acquired from Seahawk, revenue increased $14.9 million due to increased operating days for the legacy Hercules rigs to 934 days during the Current Quarter from 788 days during the Comparable Quarter, which contributed to an approximate $8 million increase. In addition, an increase in average dayrates for the legacy Hercules rigs, $52,143 in the Current Quarter compared to $42,892 in the Comparable Quarter, contributed to an approximate $7 million increase in revenue during the Current Quarter as compared to the Comparable Quarter.

International Offshore. Revenue for our International Offshore segment decreased due to the following:

•

$15.0 million decrease from Hercules 258 as it was warm stacked during most of the Current Quarter;

•

$9.7 million decrease from Hercules 260 as it operated at a lower dayrate in the Current Quarter than in the Comparable Quarter and did not provide marine package services as were provided under the contract in the Comparable Period;

•

$12.8 million decrease from Hercules 261 and $7.3 million decrease from Hercules 262 as they were in the shipyard in the Current Quarter preparing for new contracts;

•

$12.0 million decrease from Hercules 208 as the rig was preparing for a new contract in Indonesia during the Current Quarter.

Inland. The decrease in revenue from our Inland segment was driven primarily by fewer operating days in the Current Quarter as compared to the Comparable Quarter.

Domestic Liftboats. The decrease in revenue from our Domestic Liftboats segment resulted primarily from a slight decline in average revenue per liftboat per day in the Current Quarter as compared to the Comparable Quarter.

International Liftboats. The decrease in revenue from our International Liftboats segment resulted primarily from fewer operating days in the Current Quarter as compared to the Comparable Quarter.

Operating Expenses

Consolidated. The increase in consolidated operating expenses is described below.

Domestic Offshore. The increase in operating expenses for our Domestic Offshore segment was due primarily to approximately $22 million related to the rigs acquired from Seahawk. Excluding the operating expenses related to the rigs acquired from Seahawk, operating expenses decreased approximately $4 million driven by a decrease in equipment rentals, insurance costs and workers’ compensation costs of $1.7 million, $1.7 million and $2.8 million, respectively, offset by an increase in labor costs of $2.3 million.

International Offshore. Hercules 261 contributed a $4.0 million decrease in the Current Quarter as compared to the Comparable Quarter primarily due to the deferral of costs as it was in the shipyard in the Current Quarter preparing for a new contract. Additionally, Hercules 258 contributed a $3.3 million decrease as it only worked 12 days in the Current Quarter before it was warm stacked.

Inland. The decrease in operating expenses for our Inland segment due to a decrease in labor costs, equipment rentals, and workers’ compensation costs of $0.5 million, $0.4 million and $0.4 million, respectively.

Domestic Liftboats. The decrease in operating expenses for our Domestic Liftboats segment related to the $1.8 million gain recognized on the loss of the Starfish recovered from insurance underwriters in excess of the net book value.

International Liftboats. The decrease in operating expenses for our International Liftboats segment related to the $1.6 million gain recognized on the loss of the Mako recovered from insurance underwriters in excess of the net book value.

Depreciation and Amortization

The increase in depreciation and amortization expense resulted primarily from the addition of the rigs acquired from Seahawk in the second quarter of 2011.

General and Administrative Expenses

The increase in general and administrative expenses is related to an increase in bad debt expense in the Current Quarter as compared to the Comparable Quarter which included a $5.0 million recovery from one international customer.

Interest Expense

The increase in interest expense was primarily due to an increase in the term loan rate after the March 2011 amendment to the prior credit agreement.

Income Tax Benefit

Our income tax effective rate of 18.8% during the Current Quarter, compared to an effective rate of 32.9% for the Comparable Quarter, decreased primarily due to mix of earnings (losses) from different jurisdictions. In some cases our income tax is based on gross revenues or deemed profits under local tax laws rather than income before taxes. In addition, our assets move between taxing jurisdictions and operating structures with differing tax rates. As a result, variations in our effective tax rate from period to period may have limited correlation with pre-tax income or loss.

Non-GAAP Financial Measures

Regulation G, General Rules Regarding Disclosure of Non-GAAP Financial Measures and other SEC regulations define and prescribe the conditions for use of certain Non-Generally Accepted Accounting Principles (“Non-GAAP”) financial measures. We use various Non-GAAP financial measures such as adjusted operating income (loss), adjusted net income (loss) from continuing operations, adjusted diluted earnings (loss) per share from continuing operations, EBITDA and Adjusted EBITDA. EBITDA is defined as net income plus interest expense, income taxes, depreciation and amortization. We believe that in addition to GAAP based financial information, Non-GAAP amounts are meaningful disclosures for the following reasons: i) each are components of the measures used by our board of directors and management team to evaluate and analyze our operating performance and historical trends, ii) each are components of the measures used by our management team to make day-to-day operating decisions, iii) under certain scenarios the Credit Agreement requires us to maintain compliance with a maximum secured leverage ratio, which contains Non-GAAP adjustments as components, iv) each are components of the measures used by our management to facilitate internal comparisons to competitors’ results and the shallow-water drilling and marine services industry in general, v) results excluding certain costs and expenses provide useful information for the understanding of the ongoing operations without the impact of significant special items, and vi) the payment of certain bonuses to members of our management is contingent upon, among other things, the satisfaction by the Company of financial targets, which may contain Non-GAAP measures as components. We acknowledge that there are limitations when using Non-GAAP measures. The measures below are not recognized terms under GAAP and do not purport to be an alternative to net income as a measure of operating performance or to cash flows from operating activities as a measure of liquidity. EBITDA and Adjusted EBITDA are not intended to

be a measure of free cash flow for management’s discretionary use, as it does not consider certain cash requirements such as tax payments and debt service requirements. Because all companies do not use identical calculations, the amounts below may not be comparable to other similarly titled measures of other companies.

The following table presents a reconciliation of the GAAP financial measure to the corresponding adjusted financial measure (in thousands):


	For the Three Months Ended March 31,
	2012			2011
Loss from Continuing Operations	$	(38,342	)	$	(13,643	)
Interest expense		19,669			18,506
Income tax benefit		(8,888	)		(6,679	)
Depreciation and amortization		42,978			41,793

EBITDA	$	15,417		$	39,977

CRITICAL ACCOUNTING POLICIES

Critical accounting policies are those that are important to our results of operations, financial condition and cash flows and require management’s most difficult, subjective or complex judgments. Different amounts would be reported under alternative assumptions. We have evaluated the accounting policies used in the preparation of the unaudited consolidated financial statements and related notes appearing elsewhere in this quarterly report. We apply those accounting policies that we believe best reflect the underlying business and economic events, consistent with accounting principles generally accepted in the United States. We believe that our policies are generally consistent with those used by other companies in our industry. We base our estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates.

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. During recent periods, there has been substantial volatility and a decline in natural gas prices. This decline may adversely impact the business of our customers, and in turn our business. This could result in changes to estimates used in preparing our financial statements, including the assessment of certain of our assets for impairment.

We believe that our more critical accounting policies include those related to business combinations, property and equipment, equity investments, derivatives, revenue recognition, percentage-of-completion, income tax, allowance for doubtful accounts, deferred charges, stock-based compensation and cash and cash equivalents. Inherent in such policies are certain key assumptions and estimates. For additional information regarding our critical accounting policies, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies” in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2011 and Item 1 of Part I of this Quarterly Report on Form 10-Q.

OUTLOOK

Offshore

Demand for our oilfield services is driven by our Exploration and Production customers’ capital spending, which can experience significant fluctuations depending on current commodity prices and their expectations of future price levels, among other factors.

Drilling activity levels in the shallow-water U.S. Gulf of Mexico are dependent on crude oil and natural gas prices, as well as our customers’ ability to obtain necessary drilling permits to operate in the region. Although natural gas has historically accounted for a greater percentage of hydrocarbon production in the U.S. Gulf of Mexico, our domestic offshore customers appear to be increasingly focused on drilling activities that contain higher concentrations of crude oil and condensates. We expect this trend to continue, given the current high price for crude oil. Further, it is our understanding that much of the crude oil produced from the U.S. Gulf of Mexico

is sold at Louisiana Light Sweet (“LLS”) posted prices, which trades at a premium to other crude benchmarks, such as West Texas Intermediate (“WTI”). As of April 19, 2012, the spot price for LLS crude was $120.52 per barrel, compared to WTI spot price of $102.27 per barrel.

In the wake of the Macondo well blowout incident, new regulations for offshore drilling imposed by the former U.S. Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”) in June 2010 have resulted in our customers experiencing significant delays in obtaining necessary permits to operate in the U.S. Gulf of Mexico. While we believe that the current state of the permit approval process appears to have improved since the advent of these new regulations, and the number of permits issued by the Bureau of Safety and Environmental Enforcement over the past quarter has increased from prior periods, it is likely that our customers will continue to experience some degree of delay in obtaining drilling permits for the foreseeable future.

The supply of marketed jackup rigs in the U.S. Gulf of Mexico has declined significantly since the financial crisis starting in 2008 and again with the imposition of new regulations during 2010. Drilling contractors such as ourselves and some of our competitors have elected to cold stack, or no longer actively market, a number of rigs in the region, while other competitors have mobilized rigs out of the U.S. Gulf of Mexico. As a result, the number of existing, actively marketed jackup rigs in the U.S. Gulf of Mexico, excluding rigs scheduled to move to international locations, has declined from 63 rigs in late 2008 to 40 rigs as of April 19, 2012, of which we estimate that approximately 37 rigs are contracted.

We are encouraged by the reduction in the marketed supply of jackup rigs in the U.S. Gulf of Mexico, the relatively limited supply of uncontracted rigs, and the high price of crude oil, all contributing to a rising dayrate environment. Tempering these positive developments in the U.S. Gulf of Mexico is the market expectation for a prolonged period of low natural gas prices. In addition, any new regulatory or legislative changes that would affect shallow-water drilling activity in the U.S. Gulf of Mexico could have a material impact on Domestic Offshore’s financial results. Based on the improved backdrop of drilling activity in the U.S. Gulf of Mexico and worldwide, as well as robust onshore drilling activity in the U.S., there has been a tightening of skilled labor across the oilfield service industry. These factors lead us to believe that labor costs are likely to experience upward pressure in 2012.

Demand for rigs in our International Offshore segment is primarily dependent on crude oil prices. Strong crude oil prices, capital budget announcements by National and International Oil Companies, as well as what appears to be an increase in the number of international tenders for drilling rigs, leads us to believe that international capital spending and demand for drilling rigs overseas will increase in 2012. Our expectation for greater international rig demand is tempered by the current number of idle jackup rigs and the anticipated growth in supply from newly constructed rigs. As of April 19, 2012, there were 375 jackup rigs actively marketed in international regions, of which 34 rigs were uncontracted. Further, there are an estimated 84 new jackup rigs either under construction, on order, or planned for delivery globally through 2014, of which 64 were without contracts. All of the jackup rigs under construction have higher specifications than the rigs in our existing fleet. We expect that increased market demand will absorb a significant portion of the incremental supply of newbuild drilling rigs.

Our international drilling fleet consists of nine jackup rigs, including the recently acquired Hercules 266, and one platform rig. Four of our rigs and our platform rig are under long term (multi-year) contracts. The Hercules 266 is in preparation to mobilize from the Gulf of Mexico to a shipyard in the Middle East, where it will undergo capital upgrade work, before commencing on a three year contract. We anticipate contract commencement in December 2012, based on timely execution at the shipyard and customer acceptance of the rig. One of our jackup rigs, Hercules 185, is currently estimated to be out of service through early May 2012. We believe that the improving fundamentals in the international jackup market will be beneficial as we seek contract work for our idle rigs or rigs that have contract terms scheduled to expire within 2012.

Activity for inland barge drilling in the U.S. generally follows similar drivers as drilling in the U.S. Gulf of Mexico Shelf, with activity following operators’ expectations of prices for natural gas and crude oil. The predominance of smaller independent operators active in inland waters adds to the volatility of this region. Inland barge drilling activity has slowed dramatically since 2008, as a number of key operators have curtailed or ceased activity in the inland market for various reasons, including lack of funding, lack of drilling success and reallocation of capital to other onshore basins. Inland activity levels stabilized in 2010, but remain depressed relative to historical levels. As of April 16, 2012, we estimate there were 25 marketed barge rigs, of which 21 were contracted. We expect industry activity levels to remain relatively flat into 2012, barring a significant increase in natural gas prices and/or property transfers to new operators that may spur drilling activity in this region.

Liftboats

Demand for liftboats is typically a function of our customers’ demand for platform inspection and maintenance, well maintenance, well plugging and abandonment, offshore construction and other related activities. Although activity levels for liftboats are not as closely correlated to commodity prices as our drilling segments, commodity prices are still a key driver of liftboat demand. In addition, liftboat demand in the U.S. Gulf of Mexico typically experiences seasonal fluctuations, due in large part to the operating limitations of liftboats in rough waters, which tend to occur during the winter months. On occasion, domestic liftboat demand will experience a sharp increase due to the occurrence of exogenous events such as hurricanes or maritime incidents that result in extraordinary damage to offshore infrastructure or require coastal restoration work.

On September 15, 2010, the Department of Interior issued the Notice to Lessees Number 2010-G05, which provides federal guidelines for the plugging and abandonment of wells and decommissioning of offshore platforms in the U.S. Gulf of Mexico. Since the issuance of this mandate, our Domestic Liftboat segment has experienced an increased shift in revenue mix to plugging and abandonment services. Further increases in plugging and abandonment related services are uncertain, although we expect such services will provide a relatively stable base of activity for our domestic liftboats over the next several years.

Our International Liftboat segment is driven by our customers’ demand for production, platform maintenance and support activities in West Africa and the Middle East. While international rates for liftboats typically exceed those in the U.S., operating costs are also higher, and we expect this dynamic to continue through the foreseeable future. Utilization can and has been negatively impacted by local labor disputes and regional conflicts, particularly in West Africa. In the near term, we expect the liftboat market in West Africa to potentially be impacted by additional vessels mobilizing into the region, which may place pressure on utilization and pricing for our liftboat fleet, while the Middle East market will benefit from an increase in construction and well servicing activity. Over the long term, we believe that international liftboat demand will benefit from: (i) the aging offshore infrastructure and maturing offshore basins, (ii) desire by our international customers to economically produce from these mature basins and service their infrastructure and (iii) the cost advantages of liftboats to perform these services relative to alternatives. Tempering this demand outlook is (i) our expectation of increased competition from newly constructed liftboats and mobilizations of existing liftboats primarily from the U.S. Gulf of Mexico to international markets, as well as (ii) the risk of recurring political and social unrest, principally in West Africa.

LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses of Cash

Sources and uses of cash for the three month period ended March 31, 2012 are as follows (in millions):


Net Cash Used in Operating Activities	$	(1.9	)
Net Cash Provided by (Used in) Investing Activities:
Acquisition of Assets		(40.0	)
Additions of Property and Equipment		(16.6	)
Deferred Drydocking Expenditures		(3.2	)
Insurance Proceeds Received		13.1
Proceeds from Sale of Assets, Net		3.3
Increase in Restricted Cash		(3.6	)

Total		(47.0	)
Net Cash Provided by (Used in) Financing Activities:
Long-term Debt Repayments		(17.6	)
Common Stock Issuance		97.1
Other		0.1

Total		79.6

Net Increase in Cash and Cash Equivalents	$	30.7

Sources of Liquidity and Financing Arrangements

Our liquidity is comprised of cash on hand, cash from operations and availability under our revolving credit facility. We also maintain a shelf registration statement covering the future issuance from time to time of various types of securities, including debt and equity securities. If we issue any debt securities off the shelf or otherwise incur debt, we would generally be required to allocate the proceeds of such debt to repay or refinance existing debt. We currently believe we will have adequate liquidity to fund our operations. However, to the extent we do not generate sufficient cash from operations we may need to raise additional funds through debt, equity offerings or the sale of assets. Furthermore, we may need to raise additional funds through debt or equity offerings or asset sales to refinance existing debt or for general corporate purposes. In June 2013, we may be required to settle our 3.375% Convertible Senior Notes. As of March 31, 2012, the notional amount of these notes outstanding was $95.9 million. We intend to meet these obligations through one or more of the following: our unrestricted cash balance, cash flow from operations, asset sales, and future debt or equity offerings.

Cash Requirements and Contractual Obligations

Recent Notes Issuances and Changes to Existing Debt Balances

On April 3, 2012, we made the following changes to our debt structure:

•

Issued $300.0 million aggregate principal amount of 7.125% Senior Secured Notes due 2017;

•

Issued $200.0 million aggregate principal amount of 10.25% Senior Notes due 2019;

•

Entered into a new Credit Agreement that provides for a $75.0 million senior secured revolving credit facility, with a $25.0 million sublimit for the issuance of letters of credit;

•

Terminated our prior credit agreement dated July 11, 2007, as amended to date, which included an undrawn $140.0 million revolving credit facility and a term loan (“prior secured credit facility”) balance of $435.3 million as of March 31, 2012;

•

Repaid in full all outstanding indebtedness under the prior secured credit facility, and the liens securing such obligations were terminated; and

•

On April 3, 2012, and in connection with the aforementioned notes issuances and the repayment of the prior secured credit facility, our secured indebtedness was reduced below the defined threshold (as established in the indenture governing the 10.5% Senior Notes), whereby, all the liens securing the 10.5% Senior Notes were released.

Debt

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

We had a $575.3 million credit facility, consisting of a $435.3 million term loan facility and a $140.0 million revolving credit facility as of March 31, 2012. As of March 31, 2012, no amounts were outstanding and no standby letters of credit had been issued under the revolving credit facility. The interest rate on the amount outstanding under the term loan facility was 7.5% and the annualized effective rate of interest was 7.86% for the three months ended March 31, 2012 after giving consideration to revolver fees.

Under the prior credit agreement, as amended, which governed the prior secured credit facility, we had to, among other things, make certain mandatory prepayments of debt outstanding under the credit facility. Accordingly, in addition to our scheduled payments, in January 2012, we used the net proceeds from asset sales to retire $17.6 million of the outstanding balance of our term loan facility as required under the prior credit agreement.

On April 3, 2012, we entered into a new Credit Agreement, which governs the new credit facility (the “Credit Agreement”), which provides for a $75.0 million senior secured revolving credit facility, with a $25.0 million sublimit for the issuance of letters of credit. In connection with these events, we terminated our prior credit agreement dated July 11, 2007, as amended to date. On April 3, 2012, we repaid in full all outstanding indebtedness under the prior secured credit facility, and the liens securing such obligations were terminated. There were no termination penalties incurred by us in connection with the termination of the prior secured credit facility.

We may prepay borrowings under the new revolving credit facility at any time without premium or penalty (other than customary LIBOR breakage costs), subject to certain notice requirements. The Credit Agreement requires mandatory prepayments of amounts

outstanding thereunder with the net proceeds of certain asset sales, casualty events, preferred stock issuances and debt issuances, but these mandatory prepayments do not require any reduction of the lenders' commitments under the Credit Agreement. All borrowings under the new revolving credit facility mature on April 3, 2017.

Borrowings under the Credit Agreement bear interest, at the Company's option, at either (i) the Alternate Base Rate (“ABR”) (the highest of the administrative agent's corporate base rate of interest, the federal funds rate plus 0.5%, or the one-month Eurodollar rate (as defined in the Credit Agreement) plus 1%), plus an applicable margin that ranges between 3.0% and 4.5%, depending on our leverage ratio, or (ii) the Eurodollar rate plus an applicable margin that ranges between 4.0% and 5.5%, depending on our leverage ratio. We will pay a per annum fee on all letters of credit issued under the Credit Agreement, which fee will equal the applicable margin for loans accruing interest based on the Eurodollar rate, and we will pay a commitment fee of 0.75% per annum on the unused availability under the Credit Agreement.

The Credit Agreement contains covenants that, among other things, limit our ability to:

•

incur additional indebtedness or issue certain preferred stock;

•

pay dividends or make other distributions;

•

make other restricted payments or investments;

•

sell assets;

•

create liens;

•

enter into agreements that restrict dividends and other payments by restricted subsidiaries;

•

engage in transactions with affiliates; and

•

consolidate, merge or transfer all or substantially all of its assets.

In addition, during any period of time that outstanding letters of credit under the Credit Agreement exceed $10 million or there are any revolving borrowings outstanding under the Credit Agreement, we will have to maintain compliance with a maximum secured leverage ratio (as defined in the Credit Agreement, being generally computed as the ratio of secured indebtedness to consolidated cash flow). The maximum secured leverage ratio is as follows:

Period

Maximum Secured
Leverage Ratio

April 1, 2012

—

September 30, 2012

4.25 to 1.00

October 1, 2012 and thereafter

3.50 to 1.00

Our obligations under the new revolving credit facility are guaranteed by substantially all of our current domestic subsidiaries (collectively, the “Guarantors”), and the obligations of the Company and the Guarantors are secured by liens on substantially all of the vessels owned by the Company and the Guarantors, together with certain accounts receivable, equity of subsidiaries, equipment and other assets.

7.125% Senior Secured Notes due 2017

On April 3, 2012, we completed the issuance and sale of $300.0 million aggregate principal amount of senior secured notes at a coupon rate of 7.125% (“7.125% Senior Secured Notes”) with maturity in April 2017. These notes were sold at par and we received net proceeds from the offering of the notes of approximately $293.8 million after deducting the initial purchasers' discounts and estimated offering expenses. Interest on the notes will accrue from and including April 3, 2012 at a rate of 7.125% per year and is payable semi-annually in arrears on April 1 and October 1 of each year, beginning October 1, 2012.

The 7.125% Senior Secured Notes are guaranteed by each of the Guarantors that guarantee our obligations under our new revolving credit facility that was executed on April 3, 2012. The notes are secured by liens on all collateral that secures our obligations under our secured credit facility, subject to limited exceptions. The liens securing the notes share on an equal and ratable first priority basis with liens securing our credit facility. Under the intercreditor agreement the collateral agent for the lenders under our secured credit facility is generally entitled to sole control of all decisions and actions.

The indenture governing the notes contains covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to:

•

incur additional indebtedness or issue certain preferred stock;

•

pay dividends or make other distributions;

•

make other restricted payments or investments;

•

sell assets;

•

create liens;

•

enter into agreements that restrict dividends and other payments by restricted subsidiaries;

•

engage in transactions with affiliates; and

•

consolidate, merge or transfer all or substantially all of its assets.

The notes provide that we may, at our option, redeem all or part of the notes, at any time prior to April 1, 2014 at a redemption price equal to 100% of the aggregate principal amount of the notes to be redeemed, plus the Secured Applicable Premium as of, and accrued and unpaid interest, if any, to, the applicable redemption date. The term "Secured Applicable Premium" means, with respect to any note on any applicable redemption date, the greater of:

•

1% of the principal amount of such note, and

•

The excess, if any, of:

(b) the principal amount of such note.

On or after April 1, 2014, we may redeem all or part of the notes at the redemption prices set forth below, together with accrued and unpaid interest, if any, to the redemption date, if redeemed during the 12-month period beginning April 1 of the years indicated:


Year	Optional Redemption Price
2014		105.344	%
2015		102.672	%
2016 and thereafter		100.000	%

If we experience certain kinds of changes of control, holders of the notes will be entitled to require us to purchase all or any portion of the notes for a cash price equal to 101.0% of the principal amount of the applicable notes, plus accrued and unpaid interest, if any, to the date of purchase.

The indenture governing the notes contains customary events of default. The indenture governing the notes also contains a provision under which an event of default by us or by any restricted subsidiary on any other indebtedness exceeding $25.0 million would be considered an event of default under the indenture if such default: a) is caused by failure to pay the principal at final maturity, or b) results in the acceleration of such indebtedness prior to maturity.

10.25% Senior Notes due 2019

On April 3, 2012, we completed the issuance and sale of $200.0 million aggregate principal amount of senior notes at a coupon rate of 10.25% (“10.25% Senior Notes”) with maturity in April 2019. These notes were sold at par and we received net proceeds from the offering of the notes of approximately $195.8 million after deducting the initial purchasers’ discounts and estimated offering expenses. Interest on the notes will accrue from and including April 3, 2012 at a rate of 10.25% per year and is payable semi-annually in arrears on April 1 and October 1 of each year, beginning October 1, 2012.

The 10.25% Senior Notes are guaranteed by each of the Guarantors that guarantee our obligations under our new revolving credit facility that was executed on April 3, 2012.

The indenture governing the notes contains covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to:

•

incur additional indebtedness or issue certain preferred stock;

•

pay dividends or make other distributions;

•

make other restricted payments or investments;

•

sell assets;

•

create liens;

•

enter into agreements that restrict dividends and other payments by restricted subsidiaries;

•

engage in transactions with affiliates; and

•

consolidate, merge or transfer all or substantially all of its assets.

The notes provide that we may, at our option, redeem all or part of the notes, at any time prior to April 1, 2015 at a redemption price equal to 100% of the aggregate principal amount of the notes to be redeemed, plus the Senior Applicable Premium as of, and accrued and unpaid interest, if any, to, the applicable redemption date. The term "Senior Applicable Premium" means, with respect to any note on any applicable redemption date, the greater of:

•

1% of the principal amount of such note, and

•

The excess, if any, of:

(b) the principal amount of such note.

On or after April 1, 2015, we may redeem all or part of the notes at the redemption prices set forth below, together with accrued and unpaid interest, if any, to the redemption date, if redeemed during the 12-month period beginning April 1 of the years indicated:


Year	Optional Redemption Price
2015		107.688	%
2016		105.125	%
2017		102.563	%
2018 and thereafter		100.000	%

10.5% Senior Notes due 2017 (Formerly Secured prior to April 3, 2012)

On October 20, 2009, we completed an offering of $300.0 million of senior secured notes at a coupon rate of 10.5% with maturity in October 2017. The interest on the 10.5% Senior Notes is payable in cash semi-annually in arrears on April 15 and October 15 of each year, to holders of record at the close of business on April 1 or October 1. Interest on the notes will be computed on the basis of a 360-day year of twelve 30-day months. The notes were sold at 97.383% of their face amount to yield 11.0% and were recorded at their discounted amount, with the discount to be amortized over the life of the notes. As of March 31, 2012, $300.0 million notional amount of the 10.5% Senior Notes was outstanding.

The indenture governing the 10.5% Senior Notes provides that all the liens securing the notes may be released if our total amount of secured indebtedness, other than the 10.5% Senior Notes, does not exceed the lesser of $375.0 million and 15.0% of our consolidated tangible assets. We refer to such a release as a "collateral suspension." When a collateral suspension is in effect, the 10.5% Senior Notes due 2017 become unsecured. Following the closing of the recent transactions and the use of proceeds thereof to repay in full the prior secured credit facility, the liens securing the 10.5% Senior Notes were released on April 3, 2012. The indenture governing the 10.5% Senior Notes also provides that if, after any such collateral suspension, the aggregate principal amount of our total secured indebtedness, other than the 10.5% Senior Notes due 2017, were to exceed the greater of $375.0 million and 15.0% of our consolidated tangible assets, as defined in such indenture, then the collateral obligations of the Company and guarantors thereunder will be reinstated and must be complied with within 30 days of such event.

The 10.5% Senior Notes are guaranteed by each of the Guarantors that guarantee our obligations under our new revolving credit facility that was executed on April 3, 2012.

The indenture governing the notes contains covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to:

•

incur additional indebtedness or issue certain preferred stock;

•

pay dividends or make other distributions;

•

make other restricted payments or investments;

•

sell assets;

•

create liens;

•

enter into agreements that restrict dividends and other payments by restricted subsidiaries;

•

engage in transactions with affiliates; and

•

consolidate, merge or transfer all or substantially all of its assets.

3.375% Convertible Senior Notes due 2038

On June 3, 2008, we completed an offering of $250.0 million convertible senior notes at a coupon rate of 3.375% (“3.375% Convertible Senior Notes”) with a maturity in June 2038. As of March 31, 2012, $95.9 million notional amount of the $250.0 million 3.375% Convertible Senior Notes was outstanding. The net carrying amount of the 3.375% Convertible Senior Notes was $91.2 million at March 31, 2012.

The 3.375% Convertible Senior Notes will be convertible under certain circumstances into shares of our common stock (“Common Stock”) at an initial conversion rate of 19.9695 shares of Common Stock per $1,000 principal amount of notes, which is equal to an initial conversion price of approximately $50.08 per share. Upon conversion of a note, a holder will receive, at our election, shares of Common Stock, cash or a combination of cash and shares of Common Stock. At March 31, 2012, the number of conversion shares potentially issuable in relation to the 3.375% Convertible Senior Notes was 1.9 million.

The indenture governing the notes contains customary events of default. The indenture governing the 3.375% Convertible Senior Notes contains a provision under which an event of default by us or by any subsidiary on any other indebtedness exceeding $25.0 million would be considered an event of default under the indenture if such default: a) is caused by failure to pay the principal at final maturity, or b) results in the acceleration of such indebtedness prior to maturity.

We determined that upon maturity or redemption we have the intent and ability to settle the principal amount of our 3.375% Convertible Senior Notes in cash, and any additional conversion consideration spread (the excess of conversion value over face value) in shares of our Common Stock.

The fair value of our 3.375% Convertible Senior Notes, 10.5% Senior Notes and term loan facility is estimated based on quoted prices in active markets. The fair value of our 7.375% Senior Notes is estimated based on discounted cash flows using inputs from quoted prices in active markets for similar debt instruments. The inputs used to determine fair value are considered level two inputs in the fair value hierarchy. The following table provides the carrying value and fair value of our long-term debt instruments:


	March 31, 2012				December 31, 2011
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(in millions)
Term Loan Facility, due July 2013	$	435.3	$	434.5	$	452.9	$	442.0
10.5% Senior Notes, due October 2017		293.9		315.9		293.7		291.2
3.375% Convertible Senior Notes, due June 2038		91.2		94.7		90.2		84.7
7.375% Senior Notes, due April 2018		3.5		3.1		3.5		2.8

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

We maintain insurance coverage that includes coverage for physical damage, third party liability, workers’ compensation and employer’s liability, general liability, vessel pollution and other coverages.

In April 2011, we completed the annual renewal of all of our key insurance policies. Our primary marine package provides for hull and machinery coverage for substantially all of our rigs and liftboats up to a scheduled value of each asset. The total maximum amount of coverage for these assets is $1.6 billion, including the acquired Seahawk units. The marine package includes protection and indemnity and maritime employer’s liability coverage for marine crew personal injury and death and certain operational liabilities, with primary coverage (or self-insured retention for maritime employer’s liability coverage) of $5.0 million per occurrence with excess liability coverage up to $200.0 million. The marine package policy also includes coverage for personal injury and death of third parties with primary and excess coverage of $25 million per occurrence with additional excess liability coverage up to $200 million, subject to a $250,000 per-occurrence deductible. The marine package also provides coverage for cargo and charterer’s legal liability. The marine package includes limitations for coverage for losses caused in U.S. Gulf of Mexico named windstorms, including an annual aggregate limit of liability of $75.0 million for property damage and removal of wreck liability coverage. We also procured an additional $75.0 million excess policy for removal of wreck and certain third-party liabilities incurred in U.S. Gulf of Mexico named windstorms. Deductibles for events that are not caused by a U.S. Gulf of Mexico named windstorm are 12.5% of the insured drilling rig values per occurrence, subject to a minimum of $1.0 million, and $1.0 million per occurrence for liftboats. The deductible for drilling rigs and liftboats in a U.S. Gulf of Mexico named windstorm event is $25.0 million. Vessel pollution is covered under a Water Quality Insurance Syndicate policy (“WQIS Policy”) providing limits as required by applicable law, including the Oil Pollution Act of 1990. The WQIS Policy covers pollution emanating from our vessels and drilling rigs, with primary limits of $5 million (inclusive of a $3.0 million per-occurrence deductible) and excess liability coverage up to $200 million.

Control-of-well events generally include an unintended flow from the well that cannot be contained by equipment on site (e.g., a blow-out preventer), by increasing the weight of the drilling fluid or that does not naturally close itself off through what is typically described as bridging over. We carry a contractor’s extra expense policy with $25.0 million primary liability coverage for well control costs, expenses incurred to redrill wild or lost wells and pollution, with excess liability coverage up to $200 million for pollution liability that is covered in the primary policy. The policies are subject to exclusions, limitations, deductibles, self-insured retention and other conditions. In addition to the marine package, we have separate policies providing coverage for onshore foreign and domestic general liability, employer’s liability, auto liability and non-owned aircraft liability, with customary deductibles and coverage.

Our drilling contracts provide for varying levels of indemnification from our customers and in most cases, may require us to indemnify our customers for certain liabilities. Under our drilling contracts, liability with respect to personnel and property is customarily assigned on a “knock-for-knock” basis, which means that we and our customers assume liability for our respective personnel and property, regardless of how the loss or damage to the personnel and property may be caused. Our customers typically assume responsibility for and agree to indemnify us from any loss or liability resulting from pollution or contamination, including clean-up and removal and third-party damages arising from operations under the contract and originating below the surface of the water, including as a result of blow-outs or cratering of the well (“Blowout Liability”). The customer’s assumption for Blowout Liability may, in certain circumstances, be limited or could be determined to be unenforceable in the event of our gross negligence, willful misconduct or other egregious conduct. We generally indemnify the customer for the consequences of spills of industrial waste or other liquids originating solely above the surface of the water and emanating from our rigs or vessels.

In 2011, in connection with the renewal of certain of our insurance policies, we entered into an agreement to finance a portion of our annual insurance premiums. Approximately $25.8 million was financed through this arrangement with an interest rate of 3.59%. There was no amount outstanding as of March 31, 2012.

Insurance Claims

In September 2011, we were conducting a required annual spud can inspection on the Hercules 185 in protected waters offshore Angola. While conducting the inspection, it was determined that the spud can on the starboard leg had detached from the leg. While preparing the rig for heavy-lift transport to a shipyard in Pascagoula, Mississippi to conduct the spud can repairs, additional leg damage was identified. The rig recently arrived back in Angola after undergoing repairs. We currently estimate that the rig will be back in service in early May 2012. While the rig was being repaired and during its mobilization back to Angola, the rig has been on zero dayrate pursuant to its contract with Cabinda Gulf Oil Company. We expect to be insured for damage to the rig up to the insured value of $35.0 million, subject to a $3.5 million deductible and other customary limitations and exclusions. We recorded expenses up to the deductible amount of $3.5 million during the year ended December 31, 2011 related to rig repairs, inspections and other costs and have recorded an insurance claims receivable of $13.4 million and $6.4 million as of March 31, 2012 and December 31, 2011, respectively, for cumulative costs incurred through each of those dates in excess of the deductible, which is included in Other on the Consolidated Balance Sheets.

In September 2011, the Starfish, a 140 class liftboat, was en route to a project in the Gulf of Mexico when it was hit by a series of waterspouts and capsized. The vessel was salvaged and the underwriters determined that the vessel was a constructive total loss and, therefore, we received the full insured value of $2.5 million and recognized a gain of $1.8 million during the three months ended March 31, 2012, which is included in Operating Expenses in the Consolidated Statements of Operations. Additionally, we received reimbursement of costs incurred in excess of our deductible for the salvage operation.

In January 2012, the Mako, a 175 class liftboat in Nigeria, was engulfed by a fire that originated on a third-party rig, the KS Endeavor. Our underwriters determined that the vessel was a constructive total loss and, therefore, we received the full insured value of $8.0 million and recognized a gain of $1.6 million during the three months ended March 31, 2012, which is included in Operating Expenses in the Consolidated Statements of Operations.

Capital Expenditures

We currently expect capital expenditures and drydocking during the remainder of 2012 to approximate $130 million including upgrade and contract preparation capital costs associated with the recently acquired Hercules 266. Planned capital expenditures include items related to general maintenance, regulatory, refurbishment and upgrades to our rigs and liftboats. Planned capital expenditures include contract specific requirements related to various international rigs. Should we elect to reactivate cold stacked rigs or upgrade and refurbish additional selected rigs or liftboats, our capital expenditures may increase. Reactivations, upgrades and refurbishments are subject to our discretion and will depend on our view of market conditions and our cash flows.

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

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

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 acquire additional assets, we would expect that our ongoing capital expenditures 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.

Off-Balance Sheet Arrangements

Guarantees

Substantially all of our domestic subsidiaries guarantee the obligations under the credit facility, the 7.125% Senior Secured Notes, the 10.25% Senior Notes and the 10.5% Senior Notes.

Our obligations under the Credit Agreement and 7.125% Senior Secured Notes are secured by liens on a majority of our vessels and substantially all of our other personal property.

As a result of the closing of the recent transactions and the use of proceeds thereof to repay in full the prior secured credit facility, the liens securing the 10.5% Senior Notes were released on April 3, 2012.

Bank Guarantees, Letters of Credit, and Surety Bonds

We execute bank guarantees, letters of credit and surety bonds in the normal course of business. While these obligations are not normally called, these obligations could be called by the beneficiaries at any time before the expiration date should we breach certain contractual or payment obligations. As of March 31, 2012, we had $18.3 million of bank guarantees, letters of credit and surety bonds outstanding, consisting of $1.0 million in unsecured bank guarantees, a $0.1 million unsecured outstanding letter of credit, $3.6 million in cash collateralized letters of credit and $13.6 million outstanding in surety bonds that guarantee our performance as it relates to our drilling contracts and other obligations in Mexico and the U.S. If the beneficiaries called the bank guarantees, letters of credit and surety bonds, the called amount would become an on-balance sheet liability, and we would be required to settle the liability with cash on hand or through borrowings under our available line of credit. As of March 31, 2012, we have restricted cash of $13.3 million to support letters of credit and surety bonds related to our drilling operations.

Contractual Obligations

Our contractual obligations and commitments principally include obligations associated with our outstanding indebtedness, certain income tax liabilities, bank guarantees, surety bonds, letters of credit, future minimum operating lease obligations, purchase commitments and management compensation obligations. Except for the following, during the first three months of 2012, there were no material changes outside the ordinary course of business in the specified contractual obligations.

•

Settled $5.2 million of insurance notes payable outstanding at December 31, 2011;

•

Repaid $17.6 million of our term loan facility outstanding at December 31, 2011.

In April 2012, we (i) issued $300.0 million aggregate principal amount of 7.125% Senior Secured Notes due 2017; (ii) issued $200.0 million aggregate principal amount of 10.25% Senior Notes due 2019; and (iii) entered into a new credit agreement that provides for a $75.0 million senior secured revolving credit facility, with a $25.0 million sublimit for the issuance of letters of credit. We used the proceeds from the offering of these notes to repay the outstanding balance of $435.3 million on our prior secured credit facility and terminated such facility.

For additional information about our contractual obligations as of December 31, 2011, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources— Contractual Obligations” in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2011.

Accounting Pronouncements

See Note 14 to our condensed consolidated financial statements included elsewhere in this report.

FORWARD-LOOKING STATEMENTS

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

•

our levels of indebtedness, covenant compliance and access to capital under current market conditions;

•

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

•

our ability to renew or extend our international contracts, or enter into new contracts, when such contracts expire;

•

demand for our rigs and our liftboats;

•

activity levels of our customers and their expectations of future energy prices and ability to obtain drilling permits;

•

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

•

levels of reserves for accounts receivable;

•

success of our plans to dispose of certain assets;

•

expected completion times for our repair, refurbishment and upgrade projects, including the upgrade project for the Hercules 266, which we recently acquired;

•

our ability to effectively reactivate rigs that we have stacked;

•

the timing of shipyard projects and refurbishments and the return of the idle rigs to work;

•

our plans to increase international operations;

•

expected useful lives of our rigs and liftboats;

•

future capital expenditures and refurbishment, reactivation, transportation, repair and upgrade costs;

•

liabilities and restrictions under coastwise and other laws of the United States and regulations protecting the environment;

•

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

•

expectations regarding offshore drilling activity and dayrates, market conditions, demand for our rigs and liftboats, operating revenue, operating and maintenance expense, insurance coverage, insurance expense and deductibles, interest expense, debt levels and other matters with regard to outlook and future earnings.

We have based these statements on our assumptions and analyses in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. Forward-looking statements by their nature involve substantial risks and uncertainties that could significantly affect expected results, and actual future results could differ materially from those described in such statements. Although it is not possible to identify all factors, we continue to face many risks and uncertainties. Among the factors that could cause actual future results to differ materially are the risks and uncertainties described under “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2011 and Item 1A of Part II of this quarterly report and the following:

•

the ability of our customers in the U.S. Gulf of Mexico to obtain drilling permits in an efficient manner or at all;

•

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

•

levels of oil and gas exploration and production spending;

•

demand for and supply of offshore drilling rigs and liftboats;

•

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

•

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

•

the impact of governmental laws and regulations, including new laws and regulations in the U.S. Gulf of Mexico arising out of the Macondo well blowout incident;

•

the adequacy and costs of sources of credit and liquidity;

•

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

•

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

•

the availability of skilled personnel and rising cost of labor;

•

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

•

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

•

the effect of litigation, investigations 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 except as required by applicable law.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Interest Rate Exposure

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

As of March 31, 2012, the long-term borrowings that were outstanding subject to fixed interest rate risk consisted of the 7.375% Senior Notes due April 2018, the 3.375% Convertible Senior Notes due June 2038 and the 10.5% Senior Notes due October 2017 with a carrying amount of $3.5 million, $91.2 million and $293.9 million, respectively.

As of March 31, 2012, the interest rate for the $435.3 million outstanding under the term loan was 7.5%. If the interest rate averaged 1% more for 2012 than the rates as of March 31, 2012, annual interest expense would increase by approximately $4.4 million. This sensitivity analysis assumes there are no changes in our financial structure and excludes the impact of our interest rate derivatives, if any. In April 2012, we completed the offering of $300.0 million of senior secured notes at a coupon rate of 7.125% and the offering of $200.0 million of senior notes at a coupon rate of 10.25%, the proceeds from this offering was used to repay the term loan in full (See Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations- “Recent Developments”).


	March 31, 2012				December 31, 2011
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(in millions)
Term Loan Facility, due July 2013	$	435.3	$	434.5	$	452.9	$	442.0
10.5% Senior Notes, due October 2017		293.9		315.9		293.7		291.2
3.375% Convertible Senior Notes, due June 2038		91.2		94.7		90.2		84.7
7.375% Senior Notes, due April 2018		3.5		3.1		3.5		2.8

Fair Value of Warrants and Derivative Asset

At March 31, 2012, the fair value of derivative instruments was $2.8 million. We estimate the fair value of these instruments using a Monte Carlo simulation which takes into account a variety of factors including the strike price, the target price, the stock value, the expected volatility, the risk-free interest rate, the expected life of warrants, and the number of warrants. We are required to revalue this asset each quarter. We believe that the assumption that has the greatest impact on the determination of fair value is the closing price of Discovery Offshore’s stock. The following table illustrates the potential effect on the fair value of the derivative asset from changes in the assumptions made:


	Increase/(Decrease)
	(In thousands)
25% increase in stock price	$	1,606
50% increase in stock price		3,444
10% increase in assumed volatility		779
25% decrease in stock price		(1,339	)
50% decrease in stock price		(2,266	)
10% decrease in assumed volatility		(846	)

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our chief executive officer and our chief financial officer, evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Our chief executive officer and chief financial officer evaluated whether our disclosure controls and procedures as of the end of the period covered by this report were designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is (1) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (2) accumulated and communicated to our management, including our chief executive officer and our chief financial officer, as appropriate to allow timely decisions regarding required disclosure. Based on their evaluation, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures were effective to achieve the foregoing objectives as of the end of the period covered by this report.

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

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The information set forth under the caption “Legal Proceedings” in Note 13 of the Notes to Unaudited Consolidated Financial Statements in Item 1 of Part 1 of this report is incorporated by reference in response to this item.

ITEM 1A. RISK FACTORS

Except for the additional and updated disclosures set forth below, for additional information about our risk factors, see Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2011.

Our debt instruments impose significant additional costs and operating and financial restrictions on us, which may prevent us from capitalizing on business opportunities and taking certain actions.

Our debt instruments impose significant additional costs and operating and financial restrictions on us. These restrictions limit our ability to, among other things:

•

make certain types of loans and investments;

•

pay dividends, redeem or repurchase stock, prepay, redeem or repurchase other debt or make other restricted payments;

•

incur or guarantee additional indebtedness;

•

use proceeds from asset sales, new indebtedness or equity issuances for general corporate purposes or investment into our current business;

•

invest in certain new joint ventures;

•

create or incur liens;

•

place restrictions on our subsidiaries’ ability to make dividends or other payments to us;

•

sell our assets or consolidate or merge with or into other companies;

•

engage in transactions with affiliates; and

•

enter into new lines of business.

Our compliance with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures, finance our acquisitions, equipment purchases and development expenditures, or withstand the present or any future downturn in our business.

If we are unable to comply with the restrictions and covenants in our debt instruments, there could be a default, which could result in an acceleration of repayment of funds that we have borrowed.

Our debt instruments require that we meet certain financial ratios and tests. Our ability to comply with these financial covenants and restrictions can be affected by events beyond our control. Continued reduced activity levels in the oil and natural gas industry could adversely impact our ability to comply with such covenants in the future. Our failure to comply with such covenants would result in an event of default under our new revolving credit facility. An event of default could prevent us from borrowing under our new revolving credit facility, which could in turn have a material adverse effect on our available liquidity. In addition, an event of default could result in our having to immediately repay all outstanding indebtedness and in foreclosure of liens on our assets.

Acquisitions and integrating such acquisitions create certain risk and may affect our operating results.

We have completed acquisitions and will consider pursuing acquisitions (including the acquisition of individual rigs) in order to continue to grow and increase profitability. However, acquisitions involve numerous risks and uncertainties, including intense competition for suitable acquisition targets, the potential unavailability of financial resources necessary to consummate acquisitions, difficulties in identifying suitable acquisition targets or in completing any transactions identified on sufficiently favorable terms.

In addition to the risks involved in identifying and completing acquisitions described above, even when acquisitions are completed, integration of acquired entities and assets can involve significant difficulties, such as:

•

failure to achieve cost savings or other financial or operating objectives with respect to an acquisition;

•

inability to perform under drilling contracts due to various operational factors, including unscheduled repairs, maintenance, operational delays, health, safety and environmental incidents, weather events and our new customers seeking to cancel or renegotiate our contracts for various reasons;

•

strain on the operational and managerial controls of our business;

•

managing geographically separated organizations, systems and facilities;

•

difficulties in the integration and retention of customers or personnel and the integration and effective deployment of operations or technologies;

•

assumption of unknown material liabilities or regulatory non-compliance issues;

•

possible adverse short-term effects on our cash flows or operating results; and

•

diversion of management’s attention from the ongoing operations of our business.

Failure to manage these acquisition risks could have a material adverse effect on our results of operations, financial condition and cash flows. There can be no assurance that we will be able to consummate any acquisitions or expansions, successfully integrate acquired entities, or generate positive cash flow at any acquired company or expansion project.

Our liquidity depends upon cash on hand, cash from operations and availability under the new revolving credit facility.

Our liquidity depends upon cash on hand, cash from operations and availability under our new revolving credit facility. We currently believe we will have adequate liquidity to fund our operations for the foreseeable future. However, to the extent we do not

generate sufficient cash from operations, we may need to raise additional funds through public or private debt or equity offerings to fund operations. Furthermore, we may need to raise additional funds through public or private debt or equity offerings or asset sales to avoid a breach of our financial covenants in our new revolving credit facility to refinance our indebtedness, to fund capital expenditures or for general corporate purposes.

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

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

Period

Total Number
of Shares
Purchased (1)

Average Price
Paid per Share

Total Number of
Shares Purchased as
Part of a Publicly
Announced Plan (2)

Maximum Number
of Shares That May
Yet Be Purchased
Under Plan (2)

January 1-31, 2012

—

N/A

February 1-29, 2012

101,348

5.35

N/A

March 1-31, 2012

78,043

4.66

N/A

Total

179,391

5.05

N/A

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

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

ITEM 6. EXHIBITS

1.1

Underwriting Agreement, dated March 22, 2012, by and between Hercules Offshore, Inc. and Credit Suisse Securities (USA) LLC, Goldman, Sachs & Co. and Deutsche Bank Securities Inc., as representatives of the underwriters named in Schedule A thereto (incorporated by reference to Exhibit 1.1 to the Current Report on Form 8-K dated March 28, 2012).

3.1	Second Amended and Restated Bylaws of Hercules Offshore, Inc. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K dated February 16, 2012 (the “February 2012 8-K”)).

4.1	Second Amendment to Rights Agreement, dated as of February 13, 2012, between Hercules and American Stock Transfer & Trust Company, as rights agent (incorporated by reference to Exhibit 4.1 to the February 2012 8-K).

10.1	Second Amendment to Hercules Offshore, Inc. Amended and Restated 2004 Long-Term Incentive Plan dated February 13, 2012 (incorporated by reference to Exhibit 10.1 to the February 2012 8-K).

10.2	Form of Restricted Stock Agreement for Executive Officers (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated March 2, 2012 (the “March 2012 8-K”)).

10.3	Form of Stock Option Award Agreement for Executive Officers (incorporated by reference to Exhibit 10.2 to the March 2012 8-K).

10.4	Form of Restricted Stock Agreement for Non-Executive Employees and Consultants (incorporated by reference to Exhibit 10.3 to the March 2012 8-K).

10.5	Form of Stock Option Award Agreement for Non-Executive Employees and Consultants (incorporated by reference to Exhibit 10.4 to the March 2012 8-K).

10.6	Amended and Restated Executive Employment Agreement, dated February 28, 2012, between the Company and John T. Rynd (incorporated by reference to Exhibit 10.5 to the March 2012 8-K).

10.7	Amended and Restated Executive Employment Agreement, dated February 28, 2012, between the Company and James W. Noe (incorporated by reference to Exhibit 10.6 to the March 2012 8-K).

10.8	Amended and Restated Executive Employment Agreement, dated February 28, 2012, between the Company and Stephen M. Butz (incorporated by reference to Exhibit 10.7 to the March 2012 8-K).

10.9	Amended and Restated Executive Employment Agreement, dated February 28, 2012, between the Company and Terrell L. Carr (incorporated by reference to Exhibit 10.8 to the March 2012 8-K).

10.10

Amended and Restated Executive Employment Agreement, dated February 28, 2012, between the Company and Troy L. Carson (incorporated by reference to Exhibit 10.9 to the March 2012 8-K).

10.11

Purchase Agreement, dated March 27, 2012, by and among Hercules Offshore, Inc., the guarantors party thereto, Deutsche Bank Securities Inc., Credit Suisse Securities (USA) LLC, Goldman, Sachs & Co. and UBS Securities LLC, as representatives of the initial purchasers named in Schedule I thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated March 30, 2012).

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.

101.INS*

XBRL Instance Document

101.SCH*

XBRL Schema Document

101.CAL*

XBRL Calculation Linkbase Document

101.LAB*

XBRL Label Linkbase Document

101.PRE*

XBRL Presentation Linkbase Document

Attached as Exhibit 101 to this report are documents formatted in XBRL (Extensible Business Reporting Language). Users of this data are advised pursuant to Rule 406T of Regulation S-T that the interactive data filed is deemed not filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, and otherwise not subject to liability under these sections. The financial information contained in the XBRL-related documents is “unaudited” or “unreviewed.”

*	Filed herewith

SIGNATURES

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


HERCULES OFFSHORE, INC.

By:		/s/ John T. Rynd
		John T. Rynd
		Chief Executive Officer and President
		(Principal Executive Officer)

By:		/s/ Stephen M. Butz
		Stephen M. Butz
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer)

By:		/s/ Troy L. Carson
		Troy L. Carson
		Chief Accounting Officer
		(Principal Accounting Officer)

Date: April 26, 2012