Form 10-Q

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10-Q 1 d361286d10q.htm FORM 10-Q Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 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 (§ 232.405 of this chapter) 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.


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 July 23, 2012
		158,568,251

HERCULES OFFSHORE, INC.

INDEX


	Page No.
PART I. FINANCIAL INFORMATION

Item 1. Financial Statements:
Consolidated Balance Sheets as of June 30, 2012 and December 31, 2011		3
Consolidated Statements of Operations for the three and six months ended June 30, 2012 and 2011		4
Consolidated Statements of Cash Flows for the six months ended June 30, 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		21
Item 3. Quantitative and Qualitative Disclosures about Market Risk		44
Item 4. Controls and Procedures		45

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		46
Item 1A. Risk Factors		46
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		46
Item 6. Exhibits		46

Signatures		48

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except par value)


	June 30, 2012			December 31, 2011
	(Unaudited)
ASSETS
Current Assets:
Cash and Cash Equivalents	$	175,473		$	134,351
Marketable Securities		30,000			—
Restricted Cash		8,011			9,633
Accounts Receivable, Net of Allowance for Doubtful Accounts of $2,050 and $11,460 as of June 30, 2012 and December 31, 2011, Respectively		140,773			153,688
Prepaids		36,723			16,352
Current Deferred Tax Asset		15,543			15,543
Other		20,559			20,435

		427,082			350,002
Property and Equipment, Net		1,546,435			1,591,791
Equity Investment		34,359			34,735
Other Assets, Net		40,641			30,176

	$	2,048,517		$	2,006,704

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term Debt and Current Portion of Long-term Debt	$	65,605		$	22,130
Accounts Payable		65,409			49,370
Accrued Liabilities		64,958			70,421
Interest Payable		17,277			9,899
Insurance Notes Payable		24,149			5,218
Other Current Liabilities		24,038			18,366

		261,436			175,404
Long-term Debt, Net of Current Portion		797,588			818,146
Deferred Income Taxes		54,225			83,503
Other Liabilities		22,051			21,098
Commitments and Contingencies
Stockholders’ Equity:
Common Stock, $0.01 Par Value; 300,000 and 200,000 Shares Authorized, Respectively; 160,648 and 139,798 Shares Issued, Respectively; 158,568 and 137,899 Shares Outstanding, Respectively		1,606			1,398
Capital in Excess of Par Value		2,156,607			2,057,824
Treasury Stock, at Cost, 2,080 Shares and 1,899 Shares, Respectively		(53,098	)		(52,184	)
Retained Deficit		(1,191,898	)		(1,098,485	)

		913,217			908,553

	$	2,048,517		$	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 June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Revenue	$	178,951		$	170,201		$	322,270		$	329,579
Costs and Expenses:
Operating Expenses		121,089			114,328			232,326			220,709
Asset Impairment		47,523			—			47,523			—
Depreciation and Amortization		42,395			43,011			85,373			84,804
General and Administrative		6,513			16,820			24,187			29,646

		217,520			174,159			389,409			335,159

Operating Loss		(38,569	)		(3,958	)		(67,139	)		(5,580	)
Other Income (Expense):
Interest Expense		(20,293	)		(20,140	)		(39,962	)		(38,646	)
Loss on Extinguishment of Debt		(9,156	)		—			(9,156	)		—
Other, Net		(921	)		(1,474	)		88			(1,668	)

Loss Before Income Taxes		(68,939	)		(25,572	)		(116,169	)		(45,894	)
Income Tax Benefit		13,868			11,269			22,756			17,948

Loss from Continuing Operations		(55,071	)		(14,303	)		(93,413	)		(27,946	)
Loss from Discontinued Operations, Net of Taxes		—			(9,127	)		—			(9,703	)

Net Loss	$	(55,071	)	$	(23,430	)	$	(93,413	)	$	(37,649	)

Basic and Diluted Loss Per Share:
Loss from Continuing Operations	$	(0.35	)	$	(0.11	)	$	(0.63	)	$	(0.23	)
Loss from Discontinued Operations		—			(0.07	)		—			(0.08	)

Net Loss	$	(0.35	)	$	(0.18	)	$	(0.63	)	$	(0.31	)

Basic and Diluted Weighted Average Shares Outstanding		158,515			131,208			148,861			123,057

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

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Six Months Ended June 30,
	2012			2011
Cash Flows from Operating Activities:
Net Loss	$	(93,413	)	$	(37,649	)
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities:
Depreciation and Amortization		85,373			86,460
Stock-Based Compensation Expense		3,274			2,748
Deferred Income Taxes		(30,308	)		(36,332	)
Benefit for Doubtful Accounts Receivable		(7,625	)		(4,200	)
Amortization of Deferred Financing Fees		1,727			1,871
Amortization of Original Issue Discount		2,249			2,170
Gain on Insurance Settlement		(3,400	)		—
(Gain) Loss on Disposal of Assets and Businesses, Net		(5,507	)		11,002
Non-Cash Portion of Loss on Extinguishment of Debt		2,738			—
Asset Impairment		47,523			—
Other		(94	)		996
(Increase) Decrease in Operating Assets —
Accounts Receivable		20,540			(6,579	)
Prepaid Expenses and Other		(11,141	)		14,283
Increase (Decrease) in Operating Liabilities —
Accounts Payable		16,039			(2,925	)
Insurance Notes Payable		(11,167	)		(8,343	)
Other Current Liabilities		6,942			3,629
Other Liabilities		866			10,744

Net Cash Provided by Operating Activities		24,616			37,875
Cash Flows from Investing Activities:
Acquisition of Assets		(40,000	)		(25,000	)
Investments in Marketable Securities, Net		(30,000	)		—
Additions of Property and Equipment		(47,478	)		(25,821	)
Deferred Drydocking Expenditures		(7,285	)		(8,661	)
Cash Paid for Equity Investment		—			(21,894	)
Insurance Proceeds Received		20,639			—
Proceeds from Sale of Assets and Businesses, Net		10,405			38,917
Decrease in Restricted Cash		1,622			1,532

Net Cash Used in Investing Activities		(92,097	)		(40,927	)
Cash Flows from Financing Activities:
Long-term Debt Borrowings		500,000			—
Long-term Debt Repayments		(452,909	)		(16,231	)
Redemption of 3.375% Convertible Senior Notes		(27,606	)		—
Common Stock Issuance		96,696			—
Payment of Debt Issuance Costs		(7,717	)		(2,109	)
Other		139			2,500

Net Cash Provided by (Used in) Financing Activities		108,603			(15,840	)

Net Increase (Decrease) in Cash and Cash Equivalents		41,122			(18,892	)
Cash and Cash Equivalents at Beginning of Period		134,351			136,666

Cash and Cash Equivalents at End of Period	$	175,473		$	117,774

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 11). At June 30, 2012, the Company owned a fleet of 42 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 for fair presentation. 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 and six months ended June 30, 2012 are not necessarily indicative of the results expected for the full year.

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 ($4.86 net of underwriting discounts). 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 the 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.

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.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

2. Supplemental Financial Information

Supplemental Consolidated Balance Sheet Information is as follows:


	As of June 30, 2012		As of December 31, 2011
	(in thousands)
Other:
Insurance Claims Receivable	$	6,600	$	9,567
Deferred Expense-Current Portion		9,056		3,811
Other		4,903		7,057

	$	20,559	$	20,435

Other Current Liabilities:
Deferred Revenue-Current Portion	$	11,239	$	8,461
Taxes Payable		7,825		4,763
Other		4,974		5,142

	$	24,038	$	18,366

3. 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 6.3 million and 6.1 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 and six months ended June 30, 2012, respectively. Stock equivalents of 6.9 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 both the three and six months ended June 30, 2011.

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 June 30, 2011			Six Months Ended June 30, 2011
	(In millions, except per share amounts)
Revenue	$	178.4		$	363.0
Net Loss		(22.0	)		(36.2	)
Basic loss per share		(0.16	)		(0.26	)
Diluted loss per share		(0.16	)		(0.26	)

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

The amount of revenue and net income related to the net assets acquired from Seahawk included in the Company’s Consolidated Statements of Operations for the three and six months ended June 30, 2011 is as follows:


	April 27, 2011 through June 30, 2011
	(in millions)
Revenue	$	17.3
Net income		0.8

The Company incurred transaction costs in the amount of $1.6 million and $3.1 million for the three and six months ended June 30, 2011 related to the Seahawk Transaction of which $1.4 million and $2.9 million, respectively are included in General and Administrative on the Consolidated Statements of Operations. The remaining $0.2 million in transaction costs are included in Operating Expenses on the Consolidated Statements of Operations for the three and six months ended June 30, 2011, respectively.

5. Dispositions and Discontinued Operations

Dispositions

From time to time the Company enters into agreements to sell assets. The following table provides information related to the sale of several of the Company’s assets, excluding other miscellaneous asset sales that occur in the normal course of business, during the six months ended June 30, 2012 and 2011:


Rig	Segment	Period of Sale	Proceeds		Gain/(Loss)
			(in thousands)
2012:
Hercules 2501	Domestic Offshore	June 2012	$	7,000	$	5,465

			$	7,000	$	5,465

2011:
Hercules 78	Domestic Offshore	May 2011	$	1,700	$	20
Various(a)	Delta Towing	May 2011		30,000		(13,359	)

			$	31,700	$	(13,339	)

(a)	The Company completed the sale of substantially all of Delta Towing’s assets and certain liabilities (“The Delta Towing Sale”).

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

Discontinued Operations

The results of operations of the Delta Towing segment are reflected in the Consolidated Statements of Operations for the three and six months ended June 30, 2011 as discontinued operations.

Operating results of the Delta Towing segment were as follows:


	Three Months Ended June 30, 2011			Six Months Ended June 30, 2011
	(in thousands)
Revenue	$	2,954		$	9,822

Loss Before Income Taxes	$	(14,823	)	$	(15,787	)
Income Tax Benefit		5,696			6,084

Loss from Discontinued Operations, Net of Taxes	$	(9,127	)	$	(9,703	)

The three and six months ended June 30, 2011 include a loss of $13.4 million, or $8.2 million net of taxes, in connection with the Delta Towing Sale.

6. Debt

Debt is comprised of the following:


	June 30, 2012		December 31, 2011
	(in thousands)
Term Loan Facility, due July 2013	$	—	$	452,909
7.125% Senior Secured Notes, due April 2017		300,000		—
10.5% Senior Notes, due October 2017		294,077		293,676
10.25% Senior Notes, due April 2019		200,000		—
3.375% Convertible Senior Notes, due June 2038		65,605		90,180
7.375% Senior Notes, due April 2018		3,511		3,511

Total Debt		863,193		840,276
Less Short-term Debt and Current Portion of Long-term Debt		65,605		22,130

Total Long-term Debt, Net of Current Portion	$	797,588	$	818,146

Senior Secured Credit Agreement

The Company previously had a $575.3 million credit facility, consisting of a $435.3 million term loan facility and a $140.0 million revolving credit facility, which was repaid and terminated on April 3, 2012. 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

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

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. In connection with the termination of the prior secured credit facility, the Company recognized a pretax charge of $1.4 million, $0.9 million, net of tax, which is included in Loss on Extinguishment of Debt in the Consolidated Statements of Operations for the three and six months ended June 30, 2012, for the write off of unamortized issuance costs related to the term loan. Additionally, the Company recognized a pretax charge of $6.4 million, $4.2 million net of tax, which is included in Loss on Extinguishment of Debt in the Consolidated Statements of Operations for the three and six months ended June 30, 2012, related to the Company’s debt refinancing. As of June 30, 2012, no amounts were outstanding and $0.5 million in letters of credit had been issued under the senior secured revolving credit facility, therefore the remaining availability under this facility was $74.5 million.

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.

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.

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 $293.0 million after deducting the initial purchasers’ discounts and 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 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.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

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 $195.4 million after deducting the initial purchasers’ discounts and 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.

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 Credit Agreement as well as the indentures governing the 7.125% Senior Secured Notes, 10.25% Senior Notes, 10.5% Senior Notes and 3.375% Convertible Senior Notes contain customary events of default. In addition, the Credit Agreement as well as the indentures governing the 7.125% Senior Secured Notes, 10.25% Senior Notes, 10.5% Senior Notes and 3.375% Convertible Senior Notes also contain 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 Credit Agreement and indentures 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.

The Credit Agreement as well as the indentures governing the 7.125% Senior Secured Notes, 10.25% Senior Notes and 10.5% Senior Notes contain 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

During the quarter ended June 30, 2012, the Company repurchased $27.6 million aggregate principal amount of the 3.375% Convertible Senior Notes, resulting in a loss of $1.3 million that is included in Loss on Extinguishment of Debt in the Consolidated Statements of Operations for the three and six months ended June 30, 2012. In accordance with ASC 470-20 Debt – Debt with Conversion and Other Options, the settlement consideration was allocated to the extinguishment of the liability component in an amount equal to the fair value of that component immediately prior to extinguishment with the difference between this allocation and the net carrying amount of the liability component and unamortized debt issuance costs recognized as a gain or loss on debt extinguishment. If there would have been any remaining settlement consideration, it would have been allocated to the reacquisition of the equity component and recognized as a reduction of stockholders’ equity.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

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 June 30, 2012, Discovery Offshore’s stock price was 9.5 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:


	June 30, 2012		December 31, 2011
Balance Sheet Classification	Fair Value		Fair Value
	(in thousands)
Derivatives:
Warrants	$	1,991	$	1,758

Other Assets, Net	$	1,991	$	1,758

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


	Three Months Ended June 30,							Six Months Ended June 30,
		2012			2011				2012		2011
Derivatives	I.	II.						I.	II.
		(in thousands)							(in thousands)
Warrants	Other Income (Expense)	$	(815	)	$	(1,390	)	Other Income (Expense)	$	233	$	(1,220	)

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.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

As of June 30, 2012, the fair value of the warrants issued by Discovery Offshore was $2.0 million. The fair value of the warrants was determined using a Monte Carlo simulation based on the following assumptions:


	June 30, 2012
Strike Price (NOK)		11.50
Target Price (NOK)		23.00
Stock Value (NOK)		9.50
Expected Volatility (%)		50.0	%
Risk-Free Interest Rate (%)		0.50	%
Expected Life of Warrants (5.0 years at inception with 3.60 years remaining)		3.60
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 June 30, 2012. The strike price, target price, expected life and number of warrants are all contractual based on the terms of the warrant agreement.

The following table represents the Company’s assets measured at fair value on a recurring basis as of June 30, 2012:


	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)
	(in thousands)
Warrants	$	1,991	$	—	$	1,991	$	—
Marketable Securities - Commercial Paper	$	30,000	$	30,000	$	—	$	—

The following table represents the Company’s assets measured at fair value on a recurring basis as of December 31, 2011:


	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)
	(in thousands)
Warrants	$	1,758	$	—	$	1,758	$	—

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

The following table represents the Company’s Property and Equipment, Net measured at fair value on a non-recurring basis for which an impairment measurement was made as of June 30, 2012:


	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)		Total Gain (Loss)
	(in thousands)
June 30, 2012	$	1,500	$	—	$	—	$	1,500	$	(42,916	)

In April 2012, during the return mobilization from the U.S. Gulf of Mexico to Angola, the Hercules 185 experienced extensive damage to various portions of the rig’s legs (See Note 12). The Company currently believes it is unfeasible to repair the damage and return the rig to service and has recorded an impairment charge of $42.9 million ($27.9 million, net of tax) to write the rig down to salvage value. In addition, the Company incurred $4.6 million ($3.0 million, net of tax) related to the write-off of the unamortized deferred costs associated with the Hercules 185 contract.

The carrying value and fair value of the Company’s equity investment in Discovery Offshore was $34.4 million and $29.3 million at June 30, 2012, respectively, and $34.7 million and $26.1 million at December 31, 2011, respectively. The fair value at June 30, 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, 10.25% Senior Notes, 10.5% Senior Notes and 7.125% Senior Secured Notes 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:


	June 30, 2012				December 31, 2011
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in millions)
7.125% Senior Secured Notes, due April 2017	$	300.0	$	290.6		n/a		n/a
10.5% Senior Notes, due October 2017		294.1		295.9		293.7		291.2
10.25% Senior Notes, due April 2019		200.0		187.1		n/a		n/a
3.375% Convertible Senior Notes, due June 2038		65.6		67.9		90.2		84.7
7.375% Senior Notes, due April 2018		3.5		2.8		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 June 30, 2012, approximately 5.7 million shares were available for grant or award under the 2004 Plan, as amended.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

During the six months ended June 30, 2012, the Company granted the following equity awards:

•

Time-based awards – The Company granted 0.7 million time-based restricted stock awards which vest 1/3 per year and 0.2 million time-based restricted stock awards to the Company’s Directors which vest on the date of the Company’s 2013 Annual Meeting of Stockholders with a grant-date fair value per share equal to the closing stock price on the grant date of $5.23 and $4.11, respectively.

•

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. A portion of these awards are payable in shares of the Company’s stock and vest 1/3 per year. If the highest market-based and Company-based performance objectives are met, a portion of these awards are payable in cash and cliff vest at the first anniversary of the grant date.

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:


	June 30, 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	$	3.54		$	3.54
Fair Value	$	1.19		$	3.54

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 June 30, 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

10. 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 2011 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 2011.

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 $7.8 million at June 30, 2012 and $4.8 million at December 31, 2011, which is included in Other Current Liabilities on the Consolidated Balance Sheets.

11. 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 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.

In March 2012, the Company acquired an offshore jackup drilling rig, the Hercules 266, 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, other contract specific refurbishments to the rig and to mobilize the rig from the Gulf of Mexico to the Middle East, of which approximately $7 million has been spent as of June 30, 2012. The Company expects the rig to commence work under the contract in December 2012.

The Kingfish, a 230 class liftboat, was moved to the Middle East from the U.S. Gulf of Mexico where it will undergo upgrades prior to becoming reactivated. The vessel is anticipated to be available for work early in the fourth quarter of 2012.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

Information regarding reportable segments is as follows:


	Three Months Ended June 30, 2012							Six Months Ended June 30, 2012
	Revenue		Income (Loss) from Operations			Depreciation & Amortization		Revenue		Income (Loss) from Operations			Depreciation & Amortization
	(in thousands)							(in thousands)
Domestic Offshore	$	90,068	$	15,098		$	18,253	$	172,386	$	16,875		$	36,271
International Offshore (a)		30,072		(51,634	)		12,386		48,120		(72,483	)		24,727
Inland		8,211		(3,665	)		3,208		12,544		(8,263	)		6,417
Domestic Liftboats		16,242		583			3,853		26,673		(1,739	)		7,640
International Liftboats		34,358		11,940			4,063		62,547		20,509			9,053

		178,951		(27,678	)		41,763		322,270		(45,101	)		84,108
Corporate		—		(10,891	)		632		—		(22,038	)		1,265

Total Company	$	178,951	$	(38,569	)	$	42,395	$	322,270	$	(67,139	)	$	85,373

(a) Income (Loss) from Operations for the Company’s International Offshore segment includes a $47.5 million asset impairment charge for the three and six months ended June 30, 2012 (See Note 8).


	Three Months Ended June 30, 2011							Six Months Ended June 30, 2011
	Revenue		Income (Loss) from Operations			Depreciation & Amortization		Revenue		Income (Loss) from Operations			Depreciation & Amortization
	(in thousands)							(in thousands)
Domestic Offshore	$	48,643	$	(17,167	)	$	16,861	$	82,442	$	(42,297	)	$	31,943
International Offshore		70,047		18,207			13,256		147,166		50,881			26,556
Inland		7,625		(2,193	)		3,407		13,127		(8,572	)		8,028
Domestic Liftboats		16,860		1,910			3,860		27,491		(1,459	)		7,501
International Liftboats		27,026		5,960			4,976		59,353		17,561			9,474

		170,201		6,717			42,360		329,579		16,114			83,502
Corporate		—		(10,675	)		651		—		(21,694	)		1,302

Total Company	$	170,201	$	(3,958	)	$	43,011	$	329,579	$	(5,580	)	$	84,804


	Total Assets
	June 30,		December 31,
	2012		2011
	(in thousands)
Domestic Offshore	$	977,507	$	890,339
International Offshore		673,056		705,831
Inland		112,061		119,356
Domestic Liftboats		79,142		82,234
International Liftboats		149,249		154,974
Corporate		57,502		53,970

Total Company	$	2,048,517	$	2,006,704

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

12. Commitments and Contingencies

Legal Proceedings

The Company is involved in various claims and lawsuits in the normal course of business. As of June 30, 2012, management did not believe any accruals were necessary in accordance with FASB ASC 450-20, Contingencies – Loss Contingencies.

Shareholder Derivative Suits

Say-on-Pay Litigation

In June 2011, 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 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. On June 11, 2012, the plaintiff in the Harris County action voluntarily dismissed his action.

The Company does not expect the ultimate outcome of any of the remaining 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 and Indemnity

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 2012, 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. 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

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

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.

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 2012, 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 $30.1 million was financed through this arrangement with an interest rate of 3.54% and a maturity date of March 2013, of which $24.1 million was outstanding as insurance notes payable as of June 30, 2012. The $5.2 million outstanding in insurance notes payable as of December 31, 2011 was fully paid by the maturity date of March 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. Subsequently, additional leg damage was identified. The rig underwent repairs related to this damage and was mobilized back to Angola. The Company has an insurance claims receivable of $5.6 million as of June 30, 2012 related to repair costs incurred in excess of the deductible. During the return mobilization from the U.S. Gulf of Mexico to Angola, the Hercules 185 experienced additional damage to its legs. The Company conducted a survey of the rig’s legs above and below the water line and discovered extensive damage to various portions of the rig’s legs. At this time, the Company believes that it is unfeasible to repair the damage and return the rig to service. The Company has notified its customer regarding the condition of the rig and the Company intends on negotiating with the customer regarding the appropriate resolution of the existing contract for the rig. Additionally, the Company has notified its insurance underwriters of the additional damage and will make a claim under the Company’s insurance policies once the full extent of the damage has been identified. While the Company believes the damage to the rig is covered by its insurance policies, until a full investigation into the incidents and the damage is completed, it is difficult to predict the amount of any insurance recovery. The rig has an insured value of $35 million.

Sales and Use Tax Audits

Certain of the Company’s legal entities are under audit by various taxing authorities for several prior-year periods. These audits are ongoing and the Company is working to resolve all relevant issues. The Company has an accrual of $11.6 million and $6.5 million related to these sales and use tax matters, which is included in Accrued Liabilities on the Consolidated Balance Sheets as of June 30, 2012 and December 31, 2011.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

UNAUDITED

13. 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.

ITEM 2.

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

The following discussion and analysis should be read in conjunction with the accompanying unaudited consolidated financial statements as of June 30, 2012 and for the three and six months ended June 30, 2012 and June 30, 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, Item 1A of Part II of our quarterly report on Form 10-Q for the quarter ended March 31, 2012 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 42 jackup rigs, sixteen 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.

In March 2012, we acquired an offshore jackup drilling rig, the Hercules 266, for $40.0 million. We 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, other contract specific refurbishments to the rig and to mobilize the rig from the Gulf of Mexico to the Middle East, of which approximately $7 million has been spent as of June 30, 2012. We expect the rig to commence work under the contract in December 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 backlog at July 18, 2012 totaled approximately $585.9 million for our executed contracts. Approximately $219.4 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 may be different than the backlog disclosed or expected due to various factors. Downtime due to certain 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.

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 ($4.86, net of underwriting discounts). 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.

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 periods with the corresponding 2011 periods.

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


	Three Months Ended
	June 30,
	2012			2011			Change			% Change
	(dollars in thousands)
Domestic Offshore:
Number of rigs (as of end of period)		35			44
Revenue	$	90,068		$	48,643		$	41,425			85.2	%
Operating expenses		55,532			46,204			9,328			20.2	%
Depreciation and amortization expense		18,253			16,861			1,392			8.3	%
General and administrative expenses		1,185			2,745			(1,560	)		(56.8	%)

Operating income (loss)	$	15,098		$	(17,167	)		32,265			(187.9	%)

International Offshore:
Number of rigs (as of end of period)		10			9
Revenue	$	30,072		$	70,047		$	(39,975	)		(57.1	%)
Operating expenses		28,750			36,877			(8,127	)		(22.0	%)
Asset impairment		47,523			—			47,523			n/m
Depreciation and amortization expense		12,386			13,256			(870	)		(6.6	%)
General and administrative expenses		(6,953	)		1,707			(8,660	)		n/m

Operating income (loss)	$	(51,634	)	$	18,207			(69,841	)		n/m

Inland:
Number of barges (as of end of period)		17			17
Revenue	$	8,211		$	7,625		$	586			7.7	%
Operating expenses		8,535			6,128			2,407			39.3	%
Depreciation and amortization expense		3,208			3,407			(199	)		(5.8	%)
General and administrative expenses		133			283			(150	)		(53.0	%)

Operating loss	$	(3,665	)	$	(2,193	)		(1,472	)		67.1	%

Domestic Liftboats:
Number of liftboats (as of end of period)		39			41
Revenue	$	16,242		$	16,860		$	(618	)		(3.7	%)
Operating expenses		11,150			10,554			596			5.6	%
Depreciation and amortization expense		3,853			3,860			(7	)		(0.2	%)
General and administrative expenses		656			536			120			22.4	%

Operating income	$	583		$	1,910			(1,327	)		(69.5	%)

International Liftboats:
Number of liftboats (as of end of period)		24			24
Revenue	$	34,358		$	27,026		$	7,332			27.1	%
Operating expenses		17,122			14,565			2,557			17.6	%
Depreciation and amortization expense		4,063			4,976			(913	)		(18.3	%)
General and administrative expenses		1,233			1,525			(292	)		(19.1	%)

Operating income	$	11,940		$	5,960			5,980			100.3	%


	Three Months Ended
	June 30,
	2012			2011			Change			% Change
	(dollars in thousands)
Total Company:
Revenue	$	178,951		$	170,201		$	8,750			5.1	%
Operating expenses		121,089			114,328			6,761			5.9	%
Asset impairment		47,523			—			47,523			n/m
Depreciation and amortization		42,395			43,011			(616	)		(1.4	%)
General and administrative		6,513			16,820			(10,307	)		(61.3	%)

Operating loss		(38,569	)		(3,958	)		(34,611	)		n/m
Interest expense		(20,293	)		(20,140	)		(153	)		0.8	%
Loss on extinguishment of debt		(9,156	)		—			(9,156	)		n/m
Other, net		(921	)		(1,474	)		553			(37.5	%)

Loss before income taxes		(68,939	)		(25,572	)		(43,367	)		n/m
Income tax benefit		13,868			11,269			2,599			23.1	%

Loss from continuing operations		(55,071	)		(14,303	)		(40,768	)		n/m
Loss from discontinued operations, net of taxes		—			(9,127	)		9,127			n/m

Net loss	$	(55,071	)	$	(23,430	)	$	(31,641	)		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 June 30, 2012
	Operating Days		Available Days		Utilization (1)			Average Revenue per Day (2)		Average Operating Expense per Day (3)
Domestic Offshore		1,483		1,638		90.5	%	$	60,734	$	33,902
International Offshore		329		637		51.6	%		91,404		45,133
Inland		267		273		97.8	%		30,753		31,264
Domestic Liftboats		1,893		2,959		64.0	%		8,580		3,768
International Liftboats		1,379		1,826		75.5	%		24,915		9,377


	Three Months Ended June 30, 2011
	Operating Days		Available Days		Utilization (1)			Average Revenue per Day (2)		Average Operating Expense per Day (3)
Domestic Offshore		1,059		1,453		72.9	%	$	45,933	$	31,799
International Offshore		564		728		77.5	%		124,197		50,655
Inland		272		273		99.6	%		28,033		22,447
Domestic Liftboats		2,100		3,215		65.3	%		8,029		3,283
International Liftboats		1,270		2,093		60.7	%		21,280		6,959

(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 June 30, 2012 and 2011

Revenue

Consolidated. The increase in consolidated revenue is described below.

Domestic Offshore. The rigs acquired from Seahawk on April 27, 2011 contributed to $15.4 million of the increase in revenue from our Domestic Offshore segment. Excluding the revenue from the rigs acquired from Seahawk, revenue increased approximately $17.0 million due to increased operating days for the legacy Hercules rigs to 975 days during the Current Quarter from 693 days during the Comparable Quarter. In addition, the average dayrates for the legacy Hercules rigs increased from $45,284 in the Comparable Quarter to $58,909 in the Current Quarter, which contributed to an approximate $9 million increase in revenue.

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

•

$11.1 million decrease from Hercules 258 as it was warm stacked during the Current Quarter;

•

$11.7 million decrease from Hercules 262 as it was in the shipyard in the Current Quarter preparing for a new contract;

•

$6.8 million decrease from Hercules 261 primarily due to it operating at a lower dayrate in the Current Quarter than in the Comparable Quarter;

•

$4.9 million decrease from Hercules 185 as it was not working in the Current Quarter;

•

$3.5 million decrease from Hercules 208 primarily due to it operating at a lower dayrate in the Current Quarter than in the Comparable Quarter;

•

$2.2 million decrease from Hercules 260 due to it operating at a lower average dayrate in the Current Quarter than in the Comparable Quarter as it did not provide marine package services as were provided under the contract in the Comparable Quarter.

Inland. The increase in revenue from our Inland segment was driven primarily by an increase in average dayrates 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 decline in operating days in the Current Quarter as compared to the Comparable Quarter.

International Liftboats. Revenue from our International Liftboats segment increased due to higher average revenue per liftboat per day as well as additional operating days in the Current Quarter as compared to the Comparable Quarter, which contributed to an increase in revenue of approximately $4 million and $3 million, respectively.

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 driven primarily by an increase in labor costs.

International Offshore. The decrease in operating expenses for our International Offshore segment was primarily due to an approximate $8 million in costs incurred in the Comparable Quarter for the permanent importation of Platform 3.

Inland. The increase in operating expenses for our Inland segment was primarily due to accrued sales and use tax expense related to several multi-year sales and use tax audits.

Domestic Liftboats. The increase in operating expenses for our Domestic Liftboats segment was primarily due to accrued sales and use tax expense related to several multi-year sales and use tax audits.

International Liftboats. The increase in operating expenses for our International Liftboats segment primarily related to the $1.0 million of incremental costs associated with the mobilization of the Kingfish to the Middle East as well as an increase in workers’ compensation costs of $0.8 million.

Asset Impairment

We recorded an asset impairment charge of $47.5 million of which $42.9 million related to the write-down of Hercules 185 to salvage value and $4.6 million related to the write off of unamortized deferred costs associated with the rig’s contract.

Depreciation and Amortization

The decrease in depreciation and amortization expense resulted primarily from a reduction in amortization of drydock expenditures.

General and Administrative Expenses

The decrease in general and administrative expenses is primarily related to a $9.6 million reduction in bad debt expense in the Current Quarter as compared to the Comparable Quarter primarily due to the Company’s additional recovery from one international customer. Additionally, the Comparable Quarter included approximately $1.4 million of transaction costs in its Domestic Offshore segment associated with the Seahawk transaction.

Loss on Extinguishment of Debt

During the Current Quarter, we expensed $6.4 million related to the April 2012 debt refinancing and wrote off $1.4 million of unamortized debt issuance costs associated with the April 2012 termination of our prior term loan. Additionally, in May 2012, we repurchased a portion of our 3.375% Convertible Senior Notes, resulting in a loss of $1.3 million.

Income Tax Benefit

Our income tax effective rate of 20.1% during the Current Quarter, compared to an effective rate of 44.1% for the Comparable Quarter, decreased primarily due to mix of earnings (losses) from different jurisdictions as well as discrete items recorded in the current quarter. 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.

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


	Six Months Ended
	June 30,
	2012			2011			Change			% Change
	(dollars in thousands)
Domestic Offshore:
Number of rigs (as of end of period)		35			44
Revenue	$	172,386		$	82,442		$	89,944			109.1	%
Operating expenses		115,403			87,206			28,197			32.3	%
Depreciation and amortization expense		36,271			31,943			4,328			13.5	%
General and administrative expenses		3,837			5,590			(1,753	)		(31.4	%)

Operating income (loss)	$	16,875		$	(42,297	)		59,172			(139.9	%)

International Offshore:
Number of rigs (as of end of period)		10			9
Revenue	$	48,120		$	147,166		$	(99,046	)		(67.3	%)
Operating expenses		52,877			70,705			(17,828	)		(25.2	%)
Asset impairment		47,523			—			47,523			n/m
Depreciation and amortization expense		24,727			26,556			(1,829	)		(6.9	%)
General and administrative expenses		(4,524	)		(976	)		(3,548	)		n/m

Operating income (loss)	$	(72,483	)	$	50,881			(123,364	)		n/m

Inland:
Number of barges (as of end of period)		17			17
Revenue	$	12,544		$	13,127		$	(583	)		(4.4	%)
Operating expenses		14,214			13,158			1,056			8.0	%
Depreciation and amortization expense		6,417			8,028			(1,611	)		(20.1	%)
General and administrative expenses		176			513			(337	)		(65.7	%)

Operating loss	$	(8,263	)	$	(8,572	)		309			(3.6	%)

Domestic Liftboats:
Number of liftboats (as of end of period)		39			41
Revenue	$	26,673		$	27,491		$	(818	)		(3.0	%)
Operating expenses		19,630			20,418			(788	)		(3.9	%)
Depreciation and amortization expense		7,640			7,501			139			1.9	%
General and administrative expenses		1,142			1,031			111			10.8	%

Operating loss	$	(1,739	)	$	(1,459	)		(280	)		19.2	%

International Liftboats:
Number of liftboats (as of end of period)		24			24
Revenue	$	62,547		$	59,353		$	3,194			5.4	%
Operating expenses		30,202			29,222			980			3.4	%
Depreciation and amortization expense		9,053			9,474			(421	)		(4.4	%)
General and administrative expenses		2,783			3,096			(313	)		(10.1	%)

Operating income	$	20,509		$	17,561			2,948			16.8	%


	Six Months Ended
	June 30,
	2012			2011			Change			% Change
	(dollars in thousands)
Total Company:
Revenue	$	322,270		$	329,579		$	(7,309	)		(2.2	%)
Operating expenses		232,326			220,709			11,617			5.3	%
Asset impairment		47,523			—			47,523			n/m
Depreciation and amortization		85,373			84,804			569			0.7	%
General and administrative		24,187			29,646			(5,459	)		(18.4	%)

Operating loss		(67,139	)		(5,580	)		(61,559	)		n/m
Interest expense		(39,962	)		(38,646	)		(1,316	)		3.4	%
Loss on extinguishment of debt		(9,156	)		—			(9,156	)		n/m
Other, net		88			(1,668	)		1,756			(105.3	%)

Loss before income taxes		(116,169	)		(45,894	)		(70,275	)		n/m
Income tax benefit		22,756			17,948			4,808			26.8	%

Loss from continuing operations		(93,413	)		(27,946	)		(65,467	)		n/m
Loss from discontinued operations, net of taxes		—			(9,703	)		9,703			n/m

Net loss	$	(93,413	)	$	(37,649	)	$	(55,764	)		n/m

“n/m” means not meaningful.

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


	Six Months Ended June 30, 2012
	Operating Days		Available Days		Utilization			Average Revenue per Day		Average Operating Expense per Day
Domestic Offshore		2,954		3,276		90.2	%	$	58,357	$	35,227
International Offshore		576		1,274		45.2	%		83,542		41,505
Inland		404		546		74.0	%		31,050		26,033
Domestic Liftboats		3,235		6,053		53.4	%		8,245		3,243
International Liftboats		2,581		3,662		70.5	%		24,234		8,247


	Six Months Ended June 30, 2011
	Operating Days		Available Days		Utilization			Average Revenue per Day		Average Operating Expense per Day
Domestic Offshore		1,847		2,443		75.6	%	$	44,636	$	35,696
International Offshore		1,146		1,448		79.1	%		128,417		48,829
Inland		477		543		87.8	%		27,520		24,232
Domestic Liftboats		3,430		6,635		51.7	%		8,015		3,077
International Liftboats		2,665		4,163		64.0	%		22,271		7,019

For the Six Months Ended June 30, 2012 and 2011

Revenue

Consolidated. The decrease in consolidated revenue is described below.

Domestic Offshore. The rigs acquired from Seahawk contributed to $49.0 million of the increase in revenue from our Domestic Offshore segment. Excluding the revenue from the rigs acquired from Seahawk, revenue increased approximately $24.0 million due to increased operating days for the legacy Hercules rigs to 1,908 days during the Current Period from 1,481 days during the Comparable Period. In addition, an increase in average dayrates for the legacy Hercules rigs, $55,628 in the Current Period compared to $44,011 in the Comparable Period, contributed to an approximate $17 million increase in revenue.

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

•

$26.1 million decrease from Hercules 258 as it was warm stacked during most of the Current Period;

•

$19.6 million decrease from Hercules 261 as it was in the shipyard preparing for a new contract a portion of the year which contributed to an approximate $10 million decrease and it operated at a lower average dayrate which contributed to an approximate $10 million decrease;

•

$19.0 million decrease from Hercules 262 as it was in the shipyard preparing for a new contract a portion of the year which contributed to an approximate $9 million decrease and it operated at a lower average dayrate which contributed to an approximate $10 million decrease;

•

$15.5 million decrease from Hercules 208 as it was preparing for a new contract in Indonesia during the first Quarter which contributed to an approximate $9 million decrease and it operated at a lower average dayrate which contributed to an approximate $6 million decrease;

•

$11.9 million decrease from Hercules 260 as it operated at a lower dayrate in the Current Period than in the Comparable Period and did not provide marine package services as were provided under the contract in the Comparable Period;

•

$8.4 million decrease from Hercules 185 as it was not working in the Current Period;

Inland. The decrease in revenue from our Inland segment resulted from a decline in operating days in the Current Period as compared to the Comparable Period which contributed to an approximate $2 million decrease in revenue. Partially offsetting this decrease, average dayrates increased in the Current Period as compared to the Comparable Period contributing to an approximate $1 million increase in revenue.

Domestic Liftboats. The decrease in revenue from our Domestic Liftboats segment resulted from an approximate $2 million decrease in revenue due to a decline in operating days in the Current Period as compared to the Comparable Period. Partially offsetting this decrease, average revenue per liftboat per day increased in the Current Period as compared to the Comparable Period contributing to an approximate $1 million increase in revenue.

International Liftboats. The increase in revenue from our International Liftboats segment resulted from an increase in average revenue per liftboat per day in the Current Period as compared to the Comparable Period contributing to an approximate $5 million increase in revenue. Partially offsetting this increase was an approximate $2 million decrease in revenue due to a decline in operating days in the Current Period as compared to the Comparable Period.

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 $26 million related to the rigs acquired from Seahawk. Excluding the operating expenses related to the rigs acquired from Seahawk, operating expenses increased approximately $2 million driven by an increase in labor costs of $7.2 million, fewer gains on asset sales of $2.8 million in the Current Period as compared to the Comparable Period, as well as current period accrued sales and use tax expense of $2.3 million related to several multi-year sales and use tax audits. These increases were partially offset by a decrease in costs associated with workers’ compensation, equipment rentals, and insurance premiums of $5.2 million, $3.1 million and $2.1 million, respectively.

International Offshore. Platform 3 contributed a $9.3 million decrease to operating expenses in the Current Period as compared to the Comparable Period primarily due to the approximate $8 million of costs incurred in the Comparable Period for the permanent importation of the rig. Additionally, Hercules 258 contributed a $8.6 million decrease in operating expenses as it only worked twelve days in the Current Period before it was warm stacked.

Inland. The increase in operating expenses for our Inland segment is due to current period accrued sales and use tax expense of $2.3 million related to several multi-year sales and use tax audits offset by $0.8 million of additional gains on asset sales in the Current Period as compared to the Comparable period.

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, partially offset by an increase in workers’ compensation costs of $1.0 million.

International Liftboats. The increase in operating expenses for our International Liftboats segment related primarily to the $1.0 million of incremental costs associated with the mobilization of the Kingfish to the Middle East as well as an increase in workers’ compensation costs of $0.8 million. Partially offsetting these increases is a $1.6 million gain recognized on the loss of the Mako recovered from insurance underwriters in excess of the net book value.

Asset Impairment

General and Administrative Expenses

The decrease in general and administrative expenses is primarily related to a $3.4 million reduction in bad debt expense in the Current Period as compared to the Comparable Period primarily due to the Company’s recovery of $10 million in the Current Period, of which $8.8 million was recognized as a benefit to bad debt expense and $1.2 million was recognized as revenue, compared to $5 million in the Comparable Period from one international customer. Additionally, the Comparable Period included $2.9 million of transaction costs in its Domestic Offshore segment associated with the Seahawk transaction.

Interest Expense

The increase in interest expense is primarily related to the increase in interest rates and total amount of debt outstanding after the issuance of the 7.125% Senior Secured Notes and 10.25% Senior Notes and termination of the Term Loan.

Other Income (Expense), net

The increase in other income is primarily due to the gain recognized in the Current Period for the change in the fair value of our warrants issued from Discovery Offshore as compared to a loss on the same in the Comparable Period.

Loss on Extinguishment of Debt

During the second quarter of 2012, we expensed $6.4 million related to the April 2012 debt refinancing and wrote off $1.4 million of unamortized debt issuance costs associated with the April 2012 termination of our prior term loan. Additionally, in May 2012, we repurchased a portion of our 3.375% Convertible Senior Notes, resulting in a loss of $1.3 million.

Income Tax Benefit

Our income tax effective rate of 19.6% during the Current Period, compared to an effective rate of 39.1% for the Comparable Period, decreased primarily due to mix of earnings (losses) from different jurisdictions as well as discrete items recorded in the current period. 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, except per share amounts):


	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2012			2011			2012			2011
Operating Loss	$	(38,569	)	$	(3,958	)	$	(67,139	)	$	(5,580	)
Adjustments:
Asset impairment		47,523			—			47,523			—

Total adjustments		47,523			—			47,523			—

Adjusted Operating Income (Loss)	$	8,954		$	(3,958	)	$	(19,616	)	$	(5,580	)

Loss from Continuing Operations	$	(55,071	)	$	(14,303	)	$	(93,413	)	$	(27,946	)
Adjustments:
Asset impairment		47,523			—			47,523			—
Loss on extinguishment of debt		9,156			—			9,156			—
Tax impact of adjustments		(19,838	)		—			(19,838	)		—

Total adjustments		36,841			—			36,841			—

Adjusted Loss from Continuing Operations	$	(18,230	)	$	(14,303	)	$	(56,572	)	$	(27,946	)

Diluted Loss per Share from Continuing Operations	$	(0.35	)	$	(0.11	)	$	(0.63	)	$	(0.23	)
Adjustments:
Asset impairment		0.30			—			0.32			—
Loss on extinguishment of debt		0.06			—			0.06			—
Tax impact of adjustments		(0.13	)		—			(0.13	)		—

Total adjustments		0.23			—			0.25			—

Adjusted Diluted Loss per Share from Continuing Operations	$	(0.12	)	$	(0.11	)	$	(0.38	)	$	(0.23	)

Loss from Continuing Operations	$	(55,071	)	$	(14,303	)	$	(93,413	)	$	(27,946	)
Interest expense		20,293			20,140			39,962			38,646
Income tax benefit		(13,868	)		(11,269	)		(22,756	)		(17,948	)
Depreciation and amortization		42,395			43,011			85,373			84,804

EBITDA		(6,251	)		37,579			9,166			77,556

Adjustments:
Asset impairment		47,523			—			47,523			—
Loss on extinguishment of debt		9,156			—			9,156			—

Total adjustments		56,679			—			56,679			—

Adjusted EBITDA	$	50,428		$	37,579		$	65,845		$	77,556

CRITICAL ACCOUNTING POLICIES

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 July 18, 2012, the spot price for LLS crude was $105.97 per barrel, compared to WTI spot price of $89.87 per barrel. Crude oil prices have experienced a sharp decline since late March 2012, before partially rebounding in July. During this period of oil price volatility, we have not experienced a reduction in demand for our services and we believe current oil prices remain supportive of a continuation of recent activity levels.

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 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 trend in 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 have elected to cold stack, or no longer actively market, a number of rigs in the region, and in other instances 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 approximately 63 rigs in late 2008 to 39 rigs as of July 18, 2012, of which we estimate that 37 rigs are contracted.

We are encouraged by the reduction in the marketed supply of jackup rigs in the U.S. Gulf of Mexico, and the relatively limited supply of uncontracted rigs. Crude oil prices are also encouraging as they remain high from a historical perspective, despite the recent pull back since March 2012. These factors have contributed to maintaining a healthy level of rig demand and pricing in the region. Tempering these positive conditions in the U.S. Gulf of Mexico is the market expectation for a prolonged period of low natural gas prices. We are also experiencing higher labor costs in 2012, as strong drilling activity in the U.S. has led to a tightening of skilled labor across the oilfield service industry. 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.

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 July 18, 2012, there were 381 existing jackup rigs, excluding cold staked rigs, that are actively marketed in international regions, of which only 27 rigs were uncontracted. However, there are approximately 24 cold stacked jackup rigs in the international markets. In addition, globally, there are an estimated 93 new jackup rigs either under construction, on order, or planned for delivery globally through 2015, of which 68 are 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. One of these rigs, Hercules 185, is not expected to return to service, due to extensive leg damage which will prevent the rig from recommencement of its multi-year contract. The Hercules 266 is currently undergoing contract specific 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.

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 July 16, 2012, we estimate there were 25 marketed barge rigs, of which 22 were contracted. We expect industry activity levels to remain relatively flat through 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. We expect our utilization for the second half of 2012 to follow similar seasonal trends, with possible modest pricing improvement relative to year ago levels. 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. In the Middle East, we expect healthy multi-year demand for liftboats to support increases in construction and well servicing activity levels. This has led us to mobilize one of our liftboats from the U.S., the Kingfish, to the Middle East, which we expect will be available for hire in late 2012, after it undergoes capital upgrade work to meet local market demand.

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 six month period ended June 30, 2012 are as follows (in millions):


Net Cash Provided by Operating Activities	$	24.6
Net Cash Provided by (Used in) Investing Activities:
Acquisition of Assets		(40.0	)
Investments in Marketable Securities, Net		(30.0	)
Additions of Property and Equipment		(47.5	)
Deferred Drydocking Expenditures		(7.3	)
Insurance Proceeds Received		20.7
Proceeds from Sale of Assets and Businesses, Net		10.4
Decrease in Restricted Cash		1.6

Total		(92.1	)
Net Cash Provided by (Used in) Financing Activities:
Long-term Debt Borrowings		500.0
Long-term Debt Repayments		(452.9	)
Redemption of 3.375% Convertible Senior Notes		(27.6	)
Common Stock Issuance		96.7
Payment of Debt Issuance Costs		(7.7	)
Other		0.1

Total		108.6

Net Increase in Cash and Cash Equivalents	$	41.1

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, in certain instances we would 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 June 30, 2012, the notional amount of these notes outstanding was $68.3 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

Debt

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

We previously had a $575.3 million credit facility, consisting of a $435.3 million term loan facility and a $140.0 million revolving credit facility, which was repaid and terminated on April 3, 2012. 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. In connection with the termination of the prior secured credit facility, we recognized a pretax charge of $1.4 million, $0.9 million, net of tax, which is included in Loss on Extinguishment of Debt in the Consolidated Statements of Operations for the three and six months ended June 30, 2012, for the write off of unamortized issuance costs related to the term loan. Additionally, we recognized a pretax charge of $6.4 million, $4.2 million net of tax, which is included in Loss on Extinguishment of Debt in the Consolidated Statements of Operations for the three and six months ended June 30, 2012, related to our debt refinancing. As of June 30, 2012, no amounts were outstanding and $0.5 million in letters of credit had been issued under the senior secured revolving credit facility, therefore, the remaining availability under this facility was $74.5 million.

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 our 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.

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:

Maximum Secured

Period

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 $293.0 million after deducting the initial purchasers’ discounts and 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.

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 $195.4 million after deducting the initial purchasers’ discounts and 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.

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 June 30, 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.

•

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 June 30, 2012, $68.3 million notional amount of the $250.0 million 3.375% Convertible Senior Notes was outstanding.

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 June 30, 2012, the number of conversion shares potentially issuable in relation to the 3.375% Convertible Senior Notes was 1.4 million.

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.

During the quarter ended June 30, 2012, we repurchased $27.6 million aggregate principal amount of the 3.375% Convertible Senior Notes, resulting in a loss of $1.3 million that is included in Loss on Extinguishment of Debt in the Consolidated Statements of Operations for the three and six months ended June 30, 2012. The settlement consideration was allocated to the extinguishment of the liability component in an amount equal to the fair value of that component immediately prior to extinguishment with the difference between this allocation and the net carrying amount of the liability component and unamortized debt issuance costs recognized as a gain or loss on debt extinguishment. If there would have been any remaining settlement consideration, it would have been allocated to the reacquisition of the equity component and recognized as a reduction of stockholders’ equity.

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 2012, 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. 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 2012, 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 $30.1 million was financed through this arrangement with an interest rate of 3.54% and a maturity date of March 2013, of which $24.1 million was outstanding as insurance notes payable as of June 30, 2012. The $5.2 million outstanding in insurance notes payable as of December 31, 2011 was fully paid by the maturity date of March 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. Subsequently, additional leg damage was identified. The rig underwent repairs related to this damage and was mobilized back to Angola. We have an insurance claims receivable of $5.6 million as of June 30, 2012 related to repair costs incurred in excess of the deductible. During the return mobilization from the U.S. Gulf of Mexico to Angola, the Hercules 185 experienced additional damage to its legs. We conducted a survey of the rig’s legs above and below the water line and discovered extensive damage to various portions of the rig’s legs. At this time, we believe that it is unfeasible to repair the damage and return the rig to service. We have notified our customer regarding the condition of the rig and we intend on negotiating with the customer regarding the appropriate resolution of the existing contract for the rig. Additionally, we have notified our insurance underwriters of the additional damage and will make a claim under our insurance policies once the full extent of the damage has been identified. While we believe the damage to the rig is covered by our insurance policies, until a full investigation into the incidents and the damage is completed, it is difficult to predict the amount of any insurance recovery. The rig has an insured value of $35 million.

Capital Expenditures

We currently expect capital expenditures and drydocking during the second half of 2012 to range between $100 to $110 million. Planned capital expenditures include items related to general maintenance, regulatory, refurbishment and upgrades to our rigs and liftboats. Planned capital expenditures also reflect contract specific requirements related primarily to various international rigs, including the Hercules 266, which was acquired in March 2012 and is currently undergoing extensive upgrade and preparation work prior to the rig’s multi-year contract commencement. Changes in timing of certain planned capital expenditure projects may result in a shift of spending levels beyond 2012. 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.

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.

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 six 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;

•

Financed $30.1 million related to the renewal of certain of our insurance policies;

•

Retired $27.6 million aggregate principal amount of the 3.375% Convertible Senior Notes;

•

Repaid $452.9 million of our prior secured credit facility outstanding at December 31, 2011 and terminated such facility;

•

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.

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 13 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;

•

the existence of insurance coverage and the extent of recovery from our insurance underwriters for claims made under our insurance policies; 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 rate borrowings. 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.

Fair Value of Warrants and Derivative Asset

At June 30, 2012, the fair value of derivative instruments was $2.0 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	$	1,258
50% increase in stock price		2,744
10% increase in assumed volatility		686
25% decrease in stock price		(993	)
50% decrease in stock price		(1,664	)
10% decrease in assumed volatility		(719	)

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 12 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

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 and Item 1A of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2012.

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

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

Period

Total Number
of Shares
Purchased (1)

Average Price
Paid per Share

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

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

April 1-30, 2012

103

4.68

N/A

May 1-31, 2012

1,633

4.75

N/A

June 1-30, 2012

221

3.50

N/A

Total

1,957

4.61

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

3.1	Amended and Restated Certificate of Incorporation of Hercules Offshore, Inc. filed on May 15, 2012 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K dated May 18, 2012).

4.1	Indenture dated as of April 3, 2012, by and among Hercules Offshore, Inc., the Guarantors named therein and U.S. Bank National Association as Trustee and Collateral Agent (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed April 6, 2012 (the “April 2012 Form 8-K”)).

4.2	Form of 7.125% Senior Secured Note due 2017 (incorporated by reference to and included as Exhibit A to Exhibit 4.1 of the April 2012 Form 8-K).

4.3	Indenture dated as of April 3, 2012, by and among Hercules Offshore, Inc., the Guarantors named therein and U.S. Bank National Association as Trustee (incorporated by reference to Exhibit 4.3 to the April 2012 Form 8-K).

4.4	Form of 10.25% Senior Note due 2019 (incorporated by reference to and included as Exhibit A to Exhibit 4.4 of the April 2012 Form 8-K).

4.5

Credit Agreement dated as of April 3, 2012, among Hercules Offshore, Inc., the Guarantors named therein, the lenders party thereto, Deutsche Bank Trust Company Americas, as administrative agent, collateral agent and issuing bank, and the other agents party thereto (incorporated by reference to Exhibit 4.5 to the April 2012 Form 8-K).

10.1

Representative Supplement No. 1 dated as of April 3, 2012, among Hercules Offshore, Inc., the subsidiaries party thereto as guarantors, Deutsche Bank Trust Company Americas, as Controlling Agent for the Senior Secured Parties and Authorized Representative for the Senior Loan Secured Parties, and U.S. Bank National Association, as New Representative (incorporated by reference to Exhibit 10.1 to the April 2012 Form 8-K).

10.2

Joinder, Resignation and Acknowledgment dated as of April 3, 2012, among Hercules Offshore, Inc., the subsidiaries party thereto, UBS AG, Stamford Branch, as resigning Bank Collateral Agent and as resigning Controlling Agent, and Deutsche Bank Trust Company Americas, as Authorized Representative for new Senior Loan Secured Parties, as new Bank Collateral Agent, and as new Controlling Agent (incorporated by reference to Exhibit 10.2 to the April 2012 Form 8-K).

10.3*

Form of Phantom Stock Agreement for Chief Executive Officer.

10.4*

Form of Phantom Stock Agreement for Employees.

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.DEF*

XBRL Definition 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: July 27, 2012