Exhibit 99.1

Item 6. Selected Financial Data

     As further discussed in Note 1 to our consolidated financial statements, in May 2011, we completed the sale of substantially all of Delta Towing’s assets and certain liabilities. As a result of this sale, we have recast certain information included in our consolidated financial statements as of and for the twelve months ended December 31, 2010.

     We have derived the following condensed consolidated financial information as of December 31, 2010 and 2009 and for the years ended December 31, 2010, 2009 and 2008 from our audited consolidated financial statements included in Item 8 of this report. The condensed consolidated financial information as of December 31, 2008 and for the year ended December 31, 2007 was derived from our audited consolidated financial statements included in Item 8 of our annual report on Form 10-K for the year ended December 31, 2009 adjusting the financial information for the year ended December 31, 2007 for the discontinued operations of our Delta Towing segment. The condensed consolidated financial information as of December 31, 2007 and for the year ended December 31, 2006 was derived from our audited consolidated financial statements included in Item 8 of our annual report on Form 10-K for the year ended December 31, 2008, as amended by our current report on Form 8-K filed on September 23, 2009. The condensed consolidated financial information as of December 31, 2006 was derived from our audited consolidated financial statements included in Item 8 of our annual report on Form 10-K, as amended, for the year ended December 31, 2006.

     We were formed in July 2004 and commenced operations in August 2004. From our formation to December 31, 2010, we completed the acquisition of TODCO and several significant asset acquisitions that impact the comparability of our historical financial results. Our financial results reflect the impact of the TODCO business and the asset acquisitions from the dates of closing.

     The selected consolidated financial information below should be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this annual report and our audited consolidated financial statements and related notes included in Item 8 of this annual report. In addition, the following information may not be deemed indicative of our future operations.

		Year Ended				Year Ended				Year Ended				Year Ended				Year Ended
		December 31,				December 31,				December 31,				December 31,				December 31,
		2010(a)				2009(b)				2008(c)				2007				2006
		(In thousands, except per share data)
Statement of Operations Data:
Revenue		$	624,827			$	718,601			$	1,053,479			$	694,357			$	344,312
Operating income (loss)			(143,427	)			(79,469	)			(1,040,848	)			215,380				158,057
Income (loss) from continuing operations			(132,093	)			(81,047	)			(997,893	)			130,537				119,050
Earnings (loss) per share from continuing operations:
Basic		$	(1.15	)		$	(0.83	)		$	(11.29	)		$	2.22			$	3.80
Diluted			(1.15	)			(0.83	)			(11.29	)			2.19				3.70
Balance Sheet Data (as of end of period):
Cash and cash equivalents		$	136,666			$	140,828			$	106,455			$	212,452			$	72,772
Working capital			182,276				144,813				224,785				367,117				110,897
Total assets			1,995,309				2,277,476				2,590,895				3,643,948				605,581
Long-term debt, net of current portion			853,166				856,755				1,015,764				890,013				91,850
Total stockholders’ equity			853,132				978,512				925,315				2,011,433				394,851
Cash dividends per share			—				—				—				—				—

		Year Ended				Year Ended				Year Ended				Year Ended				Year Ended
		December 31,				December 31,				December 31,				December 31,				December 31,
		2010				2009				2008				2007				2006
		(In thousands)
Other Financial Data:
Net cash provided by (used in):
Operating activities		$	24,420			$	137,861			$	269,727			$	175,741			$	124,241
Investing activities			(21,306	)			(60,510	)			(515,787	)			(825,007	)			(149,983	)
Financing activities			(7,276	)			(42,978	)			140,063				788,946				50,939
Capital expenditures			22,018				76,141				585,084	(a)			155,390				204,456
Deferred drydocking expenditures			15,040				15,646				17,269				20,772				12,544

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

     The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the accompanying consolidated financial statements as of December 31, 2010 and 2009 and for the years ended December 31, 2010, 2009 and 2008 included in Item 8 of this annual report. The following discussion and analysis contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of certain factors, including those set forth under “Risk Factors” in Item 1A and elsewhere in this annual report. See “Forward-Looking Statements”.

     As further discussed in Note 1 to our consolidated financial statements, in May 2011, we completed the sale of substantially all of Delta Towing’s assets and certain liabilities. As a result of this sale, we have recast certain information included in our consolidated financial statements as of and for the twelve months ended December 31, 2010.

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. As of February 16, 2011, we owned a fleet of 30 jackup rigs, 17 barge rigs, three submersible rigs, one platform rig, a fleet of marine support vessels and 60 liftboat vessels. In addition, we operate five liftboat vessels owned by a third party. We own two retired jackup rigs, Hercules 190 and Hercules 254, located in the U.S. Gulf of Mexico, for which we have an agreement to sell and we expect to close in the first quarter of 2011. Our diverse fleet is capable of providing services such as oil and gas exploration and development drilling, well service, platform inspection, maintenance and decommissioning operations in several key shallow water provinces around the world.

     We report our business activities in six business segments, which as of February 16, 2011, included the following:

     Domestic Offshore — includes 22 jackup rigs and three submersible rigs in the U.S. Gulf of Mexico that can drill in maximum water depths ranging from 85 to 350 feet. Ten of the jackup rigs are either working on short-term contracts or available for contracts, one is in the shipyard and eleven are cold-stacked. All three submersibles are cold-stacked.

     International Offshore — includes eight jackup rigs and one platform rig outside of the U.S. Gulf of Mexico. We have two jackup rigs working offshore in each of India and Saudi Arabia. We have one jackup rig contracted offshore in Malaysia, one jackup rig contracted in Angola and one platform rig under contract in Mexico. In addition, we have one jackup rig warm-stacked and one jackup rig cold-stacked in Bahrain.

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

     Domestic Liftboats — includes 41 liftboats in the U.S. Gulf of Mexico. Thirty-eight are operating or available for contracts and three are cold-stacked.

     International Liftboats — includes 24 liftboats. Twenty-one are operating or available for contracts offshore West Africa, including five liftboats owned by a third party, one is cold-stacked offshore West Africa and two are operating or available for contracts in the Middle East region.

     Delta Towing — our Delta Towing business operates a fleet of 29 inland tugs, 10 offshore tugs, 34 crew boats, 46 deck barges, 16 shale barges and five spud barges along and in the U.S. Gulf of Mexico and from time to time along the Southeastern coast and in Mexico. Of these vessels, 26 crew boats, 11 inland tugs, three offshore tugs, one deck barge and one spud barge are cold-stacked, and the remaining are working, being repaired or available for contracts.

     In May 2011, we completed the sale of substantially all of Delta Towing’s assets and certain liabilities for aggregate consideration of $30 million in cash (the “Delta Towing Sale”) and recognized a loss on the sale of approximately $13 million. We retained the working capital of the Delta Towing business, which was valued at approximately $6 million at the date of sale. As a result of the Delta Towing Sale, we have recast certain information to classify the results of operations of the Delta Towing assets as discontinued operations.

     In December 2009, we entered into an agreement with First Energy Bank B.S.C. (“MENAdrill”) whereby we would market, manage and operate two Friede & Goldman Super M2 design new-build jackup drilling rigs, Hull 109 and Hull 110 (also known as MENAdrill Hercules 1 and 2, respectively), each with a maximum water depth of 300 feet. We received a notice of termination from MENAdrill with respect to Hull 109 in December 2010, and MENAdrill paid us a termination fee of $250,000 due under the contract on the date of termination. It is our understanding that Hull 110 has independently secured a contract in Mexico and we therefore, expect to receive an additional termination fee of $250,000.

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

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

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

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

     The most significant costs for our Domestic Liftboats and International Liftboats segments are the wages paid to crews and the amortization of regulatory drydocking costs. Unlike our Domestic Offshore, International Offshore and Inland segments, a significant portion of the expenses incurred with operating each liftboat are paid for or reimbursed by the customer under contractual terms and

prices. This includes catering, fuel, oil, rental equipment, crane overtime and other items. We record reimbursements from customers as revenue and the related expenses as operating costs. Our liftboats are required to undergo regulatory inspections every year and to be drydocked two times every five years; the drydocking expenses and length of time in drydock vary depending on the condition of the vessel. All costs associated with regulatory inspections, including related drydocking costs, are deferred and amortized over a period of twelve months.

RECENT DEVELOPMENTS

Investment

     In January 2011, we paid $10 million to purchase 5.0 million shares, an investment in approximately eight percent of the total outstanding equity of a new entity incorporated in Luxembourg, Discovery Offshore S.A. (“Discovery Offshore”), which investment was used by Discovery Offshore towards funding the down payments on two new-build ultra high specification harsh environment jackup drilling rigs (the “Rigs”). The Rigs, Keppel FELS “Super A” design, are being constructed by Keppel FELS in its Singapore shipyard and have a maximum water depth rating of 400 feet, two million pound hook load capacity, and are capable of drilling up to 35,000 feet deep. The two Rigs are expected to be delivered in the second and fourth quarter of 2013, respectively. Discovery Offshore also holds options to purchase two additional rigs of the same specifications, which must be exercised by the third and fourth quarter of 2011, with delivery dates expected in the second quarter and fourth quarter of 2014, respectively.

     We also executed a construction management agreement (the “Construction Management Agreement”) and a services agreement (the “Services Agreement”) with Discovery Offshore with respect to each of the Rigs. Under the Construction Management Agreement, we will plan, supervise and manage the construction and commissioning of the Rigs in exchange for a fixed fee of $7.0 million per Rig, which we received in February 2011. Pursuant to the terms of the Services Agreement, we will market, manage, crew and operate the Rigs and any other rigs that Discovery Offshore subsequently acquires or controls, in exchange for a fixed daily fee of $6,000 per Rig plus five percent of Rig-based EBITDA (EBITDA excluding SG&A expense) generated per day per Rig, which commences once the Rigs are completed and operating. Under the Services Agreement, Discovery Offshore will be responsible for operational and capital expenses for the Rigs. We are entitled to a minimum fee of $5 million per Rig in the event Discovery Offshore terminates a Services Agreement in the absence of a breach of contract by Hercules Offshore.

     In addition to the $10 million investment, we received 500,000 additional shares worth $1.0 million to cover our costs incurred and efforts expended in forming Discovery Offshore. We were issued warrants to purchase up to 5.0 million additional shares of Discovery Offshore stock at a strike price equivalent to $2.00 which is exercisable in the event that the Discovery stock price reaches an average equal to or higher than 23 Norwegian Kroner per share, which approximated $4.00 per share as of March 3, 2011, for 30 consecutive trading days. We have no other financial obligations or commitments with respect to the Rigs or our ownership in Discovery Offshore. Two of our officers are on the Board of Directors of Discovery Offshore.

Alliance Agreement

     In January 2011, we entered into an agreement with China Oilfield Services Limited (“COSL”) whereby we will market and operate a Friede & Goldman JU2000E jackup drilling rig with a maximum water depth of 400 feet. The agreement is limited to a specified opportunity in Angola.

Asset Purchase Agreement

     In February 2011, we entered into an asset purchase agreement (the “Asset Purchase Agreement”) with Seahawk Drilling, Inc. and certain of its subsidiaries (“Seahawk”), pursuant to which Seahawk agreed to sell us 20 jackup rigs and related assets, accounts receivable and cash and certain Seahawk liabilities in a transaction pursuant to Section 363 of the U.S. Bankruptcy Code. In connection with the Asset Purchase Agreement, Seahawk filed voluntary Chapter 11 petitions before the U.S. Bankruptcy Court for the Southern District of Texas, Corpus Christi Division.

     The purchase consideration is approximately $105 million (the “Consideration”), as valued at the date of the Asset Purchase Agreement, preliminarily consisting of $25.0 million in cash plus 22.3 million shares of our common stock, par value $0.01 per share (the “Stock Consideration”), subject to adjustment as further described. The cash consideration is subject to increase at the request of Seahawk up to an additional $20.0 million, if required for the purpose of paying Seahawk’s debt, and if the cash consideration is increased, the number of shares comprising the Stock Consideration shall be reduced by an amount equal to such increase, divided by $3.36. In addition, the Consideration is subject to certain other adjustments, including a working capital adjustment.

     Our Board of Directors, and our lenders through the 2011 Credit Amendment, have approved the transaction. Closing of the transaction remains subject to bankruptcy court approval as well as regulatory approvals and other customary conditions. Assuming such conditions are achieved, the transaction is expected to close during the second quarter of 2011.

Credit Agreement Amendment

     In March 2011, we amended our Credit Agreement for our term loan and revolving credit facility (See the information set forth

under the caption “Cash Requirements and Contractual Obligations” in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources).

RESULTS OF OPERATIONS

     Generally, domestic drilling industry conditions were mixed in 2010. While first half 2010 activity levels rebounded from the lows experienced in late 2009, second half 2010 activity was negatively impacted by the new regulations in the wake of the Macondo well blowout incident for offshore drilling imposed by BOEMRE, which resulted in our customers experiencing significant delays in obtaining necessary permits to operate in the U.S. Gulf of Mexico. Conversely, our Domestic Liftboat and Delta Towing segments realized increased activity levels due to our response to the clean up efforts related to the Macondo well blowout incident.

     From an international perspective, our International Offshore segment experienced lower demand and increased jackup supply in 2010 as compared to 2009, which contributed to fewer operating days in 2010. However, our International Liftboats segment benefited from increased dayrates and significantly higher operating days in 2010 as compared to 2009.

     Our domestic liftboat operations generally are affected by the seasonal weather patterns in the U.S. Gulf of Mexico. These seasonal patterns may result in increased operations in the spring, summer and fall periods and a decrease in the winter months. The rainy weather, tropical storms, hurricanes and other storms prevalent in the U.S. Gulf of Mexico during the year affect our domestic liftboat operations. During such severe storms, our liftboats typically leave location and cease to earn a full dayrate. Under U.S. Coast Guard guidelines, the liftboats cannot return to work until the weather improves and seas are less than five feet. Demand for our domestic rigs may decline during hurricane season, which is generally considered June 1 through November 30, as our customers may reduce drilling activity. Accordingly, our operating results may vary from quarter to quarter, depending on factors outside of our control.

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

		Year Ended December 31,
		2010				2009				2008
		(Dollars in thousands)
Domestic Offshore:
Number of rigs (as of end of period)			25				24				27
Revenue		$	124,063			$	140,889			$	382,358
Operating expenses			147,715				175,473				227,884
Impairment of goodwill			—				—				507,194
Impairment of property and equipment			84,744				—				174,613
Depreciation and amortization expense			68,335				60,775				66,850
General and administrative expenses			5,663				6,496				4,673
Operating loss		$	(182,394	)		$	(101,855	)		$	(598,856	)
International Offshore:
Number of rigs (as of end of period)			9				10				12
Revenue		$	291,516			$	393,797			$	327,983
Operating expenses			130,460				169,418				147,899
Impairment of goodwill			—				—				150,886
Impairment of property and equipment			37,973				26,882				—
Depreciation and amortization expense			58,275				63,808				37,865
General and administrative expenses			7,930				35,694				2,980
Operating income (loss)		$	56,878			$	97,995			$	(11,647	)
Inland:
Number of barges (as of end of period)			17				17				27
Revenue		$	21,922			$	19,794			$	162,487
Operating expenses			27,702				44,593				125,656
Impairment of goodwill			—				—				205,474
Impairment of property and equipment			—				—				202,055
Depreciation and amortization expense			23,516				32,465				43,107
General and administrative expenses			(1,420	)			1,831				8,347
Operating loss		$	(27,876	)		$	(59,095	)		$	(422,152	)
Domestic Liftboats:
Number of liftboats (as of end of period)			41				41				45
Revenue		$	70,710			$	75,584			$	94,755
Operating expenses			42,073				48,738				54,474
Depreciation and amortization expense			14,698				20,267				21,317
General and administrative expenses			1,850				2,039				2,386
Operating income		$	12,089			$	4,540			$	16,578
International Liftboats:
Number of liftboats (as of end of period)			24				24				20
Revenue		$	116,616			$	88,537			$	85,896
Operating expenses			55,879				48,240				39,122
Depreciation and amortization expense			17,711				12,880				9,912
General and administrative expenses			5,815				4,990				5,990
Operating income		$	37,211			$	22,427			$	30,872

		Year Ended December 31,
		2010				2009				2008
		(Dollars in thousands)
Total Company:
Revenue		$	624,827			$	718,601			$	1,053,479
Operating expenses			403,829				486,462				595,035
Impairment of goodwill			—				—				863,554
Impairment of property and equipment			122,717				26,882				376,668
Depreciation and amortization expense			185,712				193,504				181,968
General and administrative expenses			55,996				91,222				77,102
Operating loss			(143,427	)			(79,469	)			(1,040,848	)
Interest expense			(80,482	)			(75,431	)			(61,671	)
Expense of credit agreement fees			—				(15,073	)			—
Gain on early retirement of debt, net			—				12,157				26,345
Other, net			3,876				3,955				3,267
Loss before income taxes			(220,033	)			(153,861	)			(1,072,907	)
Income tax benefit			87,940				72,814				75,014
Loss from continuing operations			(132,093	)			(81,047	)			(997,893	)
Loss from discontinued operations, net of taxes			(2,501	)			(10,687	)			(85,497	)
Net loss		$	(134,594	)		$	(91,734	)		$	(1,083,390	)

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

		Year Ended December 31, 2010
																		Average
														Average				Operating
		Operating				Available								Revenue				Expense
		Days				Days				Utilization (1)				per Day (2)				per Day (3)
Domestic Offshore			3,321				4,086				81.3	%		$	37,357			$	36,151
International Offshore			2,106				3,344				63.0	%			138,422				39,013
Inland			986				1,095				90.0	%			22,233				25,299
Domestic Liftboats			9,641				13,870				69.5	%			7,334				3,033
International Liftboats			5,100				8,546				59.7	%			22,866				6,539

		Year Ended December 31, 2009
																		Average
														Average				Operating
		Operating				Available								Revenue				Expense
		Days				Days				Utilization (1)				per Day (2)				per Day (3)
Domestic Offshore			2,676				4,544				58.9	%		$	52,649			$	38,616
International Offshore			3,100				3,714				83.5	%			127,031				45,616
Inland			651				1,578				41.3	%			30,406				28,259
Domestic Liftboats			9,535				14,804				64.4	%			7,927				3,292
International Liftboats			4,293				7,209				59.6	%			20,624				6,692

		Year Ended December 31, 2008
																		Average
														Average				Operating
		Operating				Available								Revenue				Expense
		Days				Days				Utilization (1)				per Day (2)				per Day (3)
Domestic Offshore			5,907				8,166				72.3	%		$	64,730			$	27,906
International Offshore			2,753				3,005				91.6	%			119,137				49,218
Inland			4,048				5,885				68.8	%			40,140				21,352
Domestic Liftboats			10,343				15,785				65.5	%			9,161				3,451
International Liftboats			5,028				6,501				77.3	%			17,084				6,018

2010 Compared to 2009

Revenue

     Consolidated. Total revenue for 2010 was $624.8 million compared with $718.6 million for 2009, a decrease of $93.8 million, or 13%. This decrease is further described below.

     Domestic Offshore. Revenue for our Domestic Offshore segment was $124.1 million for 2010 compared with $140.9 million for 2009, a decrease of $16.8 million, or 12%. This decrease resulted primarily from a 29% decline in average dayrates which contributed to an approximate $41 million decrease during 2010 as compared to 2009. Partially offsetting this decrease was an increase in operating days to 3,321 days during 2010 from 2,676 days during 2009, which contributed to an approximate $24 million increase in revenue. Average utilization was 81.3% in 2010 compared with 58.9% in 2009.

     International Offshore. Revenue for our International Offshore segment was $291.5 million for 2010 compared with $393.8 million for 2009, a decrease of $102.3 million, or 26%. Approximately $26 million of this decrease related to Hercules 156 and Hercules 170, which did not work in 2010, approximately $55 million was associated with a decline in revenue from mobilizing Hercules 205 and Hercules 206 to the U.S. Gulf of Mexico, and approximately $27 million related to Hercules 185 not meeting revenue recognition criteria in 2010. Partially offsetting these decreases was an approximate $8 million increase for Hercules 260 primarily due to downtime in 2009 for leg repairs.

     Inland. Revenue for our Inland segment was $21.9 million for 2010 compared with $19.8 million for 2009, an increase of $2.1 million, or 11%. This increase resulted from a 51% increase in operating days, 986 in 2010 compared to 651 in 2009, which contributed to an approximate $7 million increase in revenue. Partially offsetting this increase, average dayrates declined 27% which contributed to an approximate $5 million decrease in revenue.

     Domestic Liftboats. Revenue for our Domestic Liftboats segment was $70.7 million for 2010 compared with $75.6 million in 2009, a decrease of $4.9 million, or 6%. Approximately $8 million of this decrease resulted from the transfer of four vessels to West Africa in the fourth quarter of 2009, offset in part by increased operating days for the remaining vessels. Operating days increased slightly to 9,641 days during 2010 as compared to 9,535 days during 2009 due in part to increased activity associated with the Macondo well blowout incident remediation efforts, largely offset by the impact of the transfer of four vessels. Average revenue per vessel per day was $7,334 in 2010 compared with $7,927 in 2009, a decrease of $593 per day due to both weaker dayrates on our smaller class vessels and a shift in the mix of vessel class as we mobilized four larger class vessels to West Africa in the fourth quarter of 2009.

     International Liftboats. Revenue for our International Liftboats segment was $116.6 million for 2010 compared with $88.5 million in 2009, an increase of $28.1 million, or 32%. Approximately $34 million of this increase resulted from the transfer of four vessels from the U.S. Gulf of Mexico. Average revenue per liftboat per day increased to $22,866 in 2010 compared with $20,624 in 2009 and operating days increased to 5,100 days in 2010 as compared to 4,293 in 2009.

Operating Expenses

     Consolidated. Total operating expenses for 2010 were $403.8 million compared with $486.5 million in 2009, a decrease of $82.6

million, or 17%. This decrease is further described below.

     Domestic Offshore. Operating expenses for our Domestic Offshore segment were $147.7 million in 2010 compared with $175.5 million in 2009, a decrease of $27.8 million, or 16%. The decrease was driven in part by 458 fewer available days during 2010 as compared to 2009, or a 10% decline, due to our cold stacking of rigs. Our cold stacking resulted in a reduction to our labor, repairs and maintenance, and workers’ compensation expenses. Additionally, 2010 includes gains totaling $10.2 million for the sale of Hercules 155, Hercules 191 and Hercules 255. Partially offsetting these decreases are increases in insurance costs and equipment rentals of $5.1 million, accrued sales and use tax expense of approximately $3.0 million related to a multi-year state sales and use tax audit as well as a gain of $6.3 million in 2009 for an insurance settlement related to hurricane damage. Average operating expenses per rig per day were $36,151 in 2010 compared with $38,616 in 2009.

     International Offshore. Operating expenses for our International Offshore segment were $130.5 million in 2010 compared with $169.4 million in 2009, a decrease of $39.0 million, or 23%. Hercules 170 was in warm stack during all of 2010 which contributed to a decrease of $7.5 million, and Hercules 205 and Hercules 206 were transferred to the Domestic Offshore segment in the first quarter of 2010 and fourth quarter of 2009, respectively, which contributed to a decrease of $19.8 million. Additionally, Hercules 185 was on stand-by in 2010, but operated a portion of 2009 which contributed to a decrease of $8.8 million. In addition, 2009 included a charge of $4.8 million associated with a customer in our International Offshore segment ($7.3 million to fully impair the related deferred mobilization and contract preparation costs, partially offset by a $2.5 million reduction in previously accrued contract related operating costs that are not expected to be settled if the receivable is not collected). Average operating expenses per rig per day were $39,013 in 2010 compared with $45,616 in 2009.

     Inland. Operating expenses for our Inland segment were $27.7 million in 2010 compared with $44.6 million in 2009, a decrease of $16.9 million, or 38%. Our cold stacking of barges reduced our available days from 1,578 in 2009 to 1,095 in 2010. This reduction in available days coupled with the reduction in our labor force significantly reduced the segment’s variable operating costs. In addition, 2010 includes a $3.1 million gain on the sale of eight of our retired barges, while 2009 includes a $0.6 million gain of the sale of two of our retired barges. These decreases are partially offset by accrued sales and use tax expense of approximately $3.0 million related to a multi-year state sales and use tax audit. Average operating expenses per rig per day were $25,299 in 2010 compared with $28,259 in 2009.

     Domestic Liftboats. Operating expenses for our Domestic Liftboats segment were $42.1 million in 2010 compared with $48.7 million in 2009, a decrease of $6.7 million, or 14%. The transfer of four vessels to our International Liftboats segment contributed $3.3 million to this decrease. In addition, labor costs decreased $2.4 million. Available days declined to 13,870 in 2010 from 14,804 in 2009 due to the transfer of four vessels to our International Liftboats segment in the fourth quarter of 2009. Average operating expenses per vessel per day decreased to $3,033 per day during 2010 from $3,292 per day during 2009.

     International Liftboats. Operating expenses for our International Liftboats segment were $55.9 million for 2010 compared with $48.2 million in 2009, an increase of $7.6 million, or 16%. The transfer of four vessels from our Domestic Liftboats segment in the fourth quarter of 2009 contributed $4.1 million to this increase. In addition, higher expenses for equipment rentals and certain regulatory fees contributed to an increase of $2.2 million. Available days increased to 8,546 in 2010 from 7,209 in 2009 largely related to the transfer of four vessels. Average operating expenses per vessel per day decreased to $6,539 per day during 2010 from $6,692 per day during 2009.

Impairment of Property and Equipment

     In the year ended December 31, 2010, we incurred $122.7 million of impairment charges related to certain property and equipment on our Domestic Offshore and International Offshore segments, the impact of which by segment was $84.7 million and $38.0 million, respectively. In June 2009, we entered into an agreement to sell Hercules 110, which was cold stacked in Trinidad, and incurred a $26.9 million impairment charge to write-down the rig to its fair value less costs to sell.

Depreciation and Amortization

     Depreciation and amortization expense in 2010 was $185.7 million compared with $193.5 million in 2009, a decrease of $7.8 million, or 4%. This decrease resulted primarily from lower amortization of our international contract values and drydocking costs, which contributed a decrease of $3.4 million and $2.4 million, respectively, as well as reduced depreciation due to asset sales and certain assets being fully depreciated, which contributed a decrease of approximately $10 million. These decreases were partially offset by the impact of capital additions which contributed to an approximate $8 million increase.

General and Administrative Expenses

     General and administrative expenses in 2010 were $56.0 million compared with $91.2 million in 2009, a decrease of $35.2 million, or 39%. This decrease relates primarily to a $26.8 million allowance for doubtful accounts receivable that was recorded in

2009 related to a customer in our International Offshore segment. In addition, labor costs decreased in 2010 as compared to 2009 driven in part by an adjustment of approximately $2.8 million to stock-based compensation expense due to a revision of our estimated forfeiture rate during 2010 as well as the impact of headcount reductions.

Interest Expense

     Interest expense increased $5.1 million, or 7%. This increase was related to interest expense incurred on our 10.5% Senior Secured Notes issued in October 2009, partially offset by lower interest on our term loan as the increase in interest rates after the 2009 Credit Amendment were offset by lower debt balances due to the early retirement of a portion of our term loan in the third and fourth quarters of 2009. In addition, interest expense decreased on our 3.375% Convertible Senior Notes due to our second quarter 2009 retirements.

Expense of Credit Agreement Fees

     During 2009, we amended our Credit Agreement and repaid and terminated a portion of our credit facility. In doing so, we recorded the write-off of certain deferred debt issuance costs and certain fees directly related to these activities totaling $15.1 million.

Gain on Early Retirement of Debt, Net

     Gain on early retirement of debt, net was $12.2 million in 2009. During 2009, we retired a portion of our term loan facility and wrote off $1.6 million in associated unamortized issuance costs. In addition, in 2009 we retired $65.8 million aggregate principal amount of the 3.375% Convertible Senior Notes for cash and equity consideration of approximately $40.1 million, resulting in a gain of $13.7 million, net of an associated write-off of a portion of our unamortized issuance costs.

Income Tax Benefit

     Income tax benefit was $87.9 million on pre-tax loss of $220.0 million during 2010, compared to a benefit of $72.8 million on pre-tax loss of $153.9 million for 2009. The effective tax rate decreased to a tax benefit of 40.0% during 2010 as compared to a tax benefit of 47.3% during 2009. The decrease in tax benefit for 2010 results from a higher tax charge associated with a deemed repatriation of foreign earnings and a reduction in state income tax benefits, partially offset by reduced foreign tax cost when compared to 2009.

Discontinued Operations

     We had a loss from discontinued operations of $2.5 million during 2010 compared to a loss from discontinued operations of $10.7 million during 2009, a decrease of $8.2 million or 77%. The decrease is primarily related to an increase in revenue of $8.4 million, or 35% for the discontinued operations of our Delta Towing segment. The discontinued operations of our Delta Towing segment had increased operating days during 2010 as compared to 2009, due in part to activity associated with the Macondo well blowout incident remediation efforts, which contributed to an approximate $16 million increase in revenue. This increase was partially offset by the impact of a decrease in average vessel dayrates during 2010 as compared to 2009, which contributed to an approximate $7 million decrease in revenue.

2009 Compared to 2008

Revenue

     Consolidated. Total revenue for 2009 was $718.6 million compared with $1,053.5 million for 2008, a decrease of $334.9 million, or 31.8%. This decrease is further described below.

     Domestic Offshore. Revenue for our Domestic Offshore segment was $140.9 million for 2009 compared with $382.4 million for 2008, a decrease of $241.5 million, or 63.2%. This decline resulted from decreased operating days from 5,907 in 2008 to 2,676 in 2009 primarily due to an overall decrease in demand and our cold stacking of rigs, which contributed $170.1 million of the decrease, and lower average dayrates which contributed $71.4 million of the decrease. Average utilization was 58.9% in 2009 compared with 72.3% in 2008.

     International Offshore. Revenue for our International Offshore segment was $393.8 million for 2009 compared with $328.0 million for 2008, an increase of $65.8 million, or 20.1%. Approximately $154 million of this increase was due to increased operating days as a result of the commencement of the Hercules 260 in late April 2008, Hercules 258 in June 2008, Hercules 208 in August 2008, Hercules 261 in December 2008 and Hercules 262 in January 2009. These favorable increases were partially offset by a decrease of approximately $76 million related to the Hercules 156 and Hercules 170 being in warm stack, Hercules 206 being transferred to Domestic Offshore for cold stack in the fourth quarter of 2009 and Hercules 110 in cold stack during 2009 until the date

of sale, and a lower average dayrate realized on Hercules 205. In addition, the Hercules 185 contributed to an approximate $14 million decrease as it was in the shipyard for an upgrade for a portion of 2009. Average revenue per rig per day increased to $127,031 in 2009 from $119,137 in 2008 due primarily to higher average dayrates earned on Hercules 261 and Hercules 208 for a more significant portion of 2009 as well as the commencement of the Hercules 262 in January 2009, partially offset by lower average dayrates earned on Hercules 205 and Hercules 206, and Hercules 156 in warm stack a majority of the year as well as Hercules 185 which operated at a higher dayrate, but for fewer operating days.

     Inland. Revenue for our Inland segment was $19.8 million for 2009 compared with $162.5 million for 2008, a decrease of $142.7 million, or 87.8% as a result of an industry-wide decline in drilling in the transition zones. This decrease resulted primarily from decreased operating days, 651 in 2009 compared to 4,048 in 2008, an 83.9% decrease. Available days declined 73.2% during 2009 as compared to 2008 due to our cold stacking plan. Furthermore, average utilization was 41.3% on fewer available days in 2009 compared with 68.8% in 2008 as demand in the segment declined.

     Domestic Liftboats. Revenue for our Domestic Liftboats segment was $75.6 million for 2009 compared with $94.8 million in 2008, a decrease of $19.2 million, or 20.2%. This decrease resulted primarily from lower average dayrates, which contributed $12.8 million of the decrease, as well as a $6.4 million decrease due to fewer operating days in 2009. Average revenue per vessel per day was $7,927 in 2009 compared with $9,161 in 2008, a decrease of $1,234 per day due primarily to lower dayrates in all vessel classes with a slight decrease due to mix of vessel class.

     International Liftboats. Revenue for our International Liftboats segment was $88.5 million for 2009 compared with $85.9 million in 2008, an increase of $2.6 million, or 3.1%. This increase resulted from higher average dayrates, which contributed $17.8 million of the increase, significantly offset by fewer operating days, which contributed a $15.2 million decrease. The higher average dayrate was due to increased operating days on our larger class vessels, which have higher dayrates and lower utilization on the smaller class vessels which have lower dayrates.

Operating Expenses

     Consolidated. Total operating expenses for 2009 were $486.5 million compared with $595.0 million in 2008, a decrease of $108.6 million, or 18%. This decrease is further described below.

     Domestic Offshore. Operating expenses for our Domestic Offshore segment were $175.5 million in 2009 compared with $227.9 million in 2008, a decrease of $52.4 million, or 23.0%. The decrease was driven primarily by lower labor, catering, repairs and maintenance, and insurance expenses primarily as a result of our cold stacking of rigs. Available days decreased to 4,544 in 2009 from 8,166 in 2008 due to our cold stacking of rigs. Average operating expenses per rig per day were $38,616 in 2009 compared with $27,906 in 2008 due in part to shore based support and cold stacked rig costs being allocated over fewer available days.

     International Offshore. Operating expenses for our International Offshore segment were $169.4 million in 2009 compared with $147.9 million in 2008, an increase of $21.5 million, or 14.5%. Available days increased to 3,714 in 2009 from 3,005 in 2008. Average operating expenses per rig per day were $45,616 in 2009 compared with $49,218 in 2008. This decrease related primarily to the Hercules 156 and Hercules 170 being in warm stack during a portion of 2009 and the initial start-up costs incurred during 2008 related to our India and Malaysia operations, partially offset by an increase due to the commencement of Hercules 261 and Hercules 262 in December 2008 and January 2009, respectively.

     Inland. Operating expenses for our Inland segment were $44.6 million in 2009 compared with $125.7 million in 2008, a decrease of $81.1 million, or 64.5%. By mid 2009, fourteen of our seventeen barges were cold stacked which significantly reduced the segment’s variable operating costs. Average operating expenses per rig per day were $28,259 in 2009 compared with $21,352 in 2008. The increase in cost per day was driven primarily by costs associated with shore based support and cold stacked barges being allocated over fewer available days.

     Domestic Liftboats. Operating expenses for our Domestic Liftboats segment were $48.7 million in 2009 compared with $54.5 million in 2008, a decrease of $5.7 million, or 10.5% due primarily to lower labor expense, fuel and oil and insurance costs. Available days decreased to 14,804 in 2009 from 15,785 in 2008 due to four vessels that were transferred to our International Liftboats Segment, these four vessels were not marketed during the third quarter 2009 in preparation of their mobilization to our International Liftboats Segment in the fourth quarter of 2009, and due to the cold stacking of several liftboats during 2009 that were available in 2008. Average operating expenses per vessel per day had a slight decrease to $3,292 per day during 2009 from $3,451 per day during 2008.

     International Liftboats. Operating expenses for our International Liftboats segment were $48.2 million for 2009 compared with $39.1 million in 2008, an increase of $9.1 million, or 23.3%. Available days increased to 7,209 in 2009 from 6,501 in 2008 largely related to the current year availability of the Whale Shark and Amberjack, which were transferred to our International Liftboats segment from the Domestic Liftboats segment during 2008. Average operating expenses per liftboat per day were $6,692 in 2009 compared with $6,018 in 2008 due to higher repairs and maintenance expenses and costs associated with transferring and preparing the four domestic vessels to work in West Africa.

Impairment of Property and Equipment

     Impairment of property and equipment in 2009 was $26.9 million compared with $376.7 million in 2008. The 2008 impairment charges of $376.7 million related to certain property and equipment on our Domestic Offshore and Inland segments in 2008. In June 2009, we entered into an agreement to sell Hercules 110, which was cold stacked in Trinidad, and incurred a $26.9 million impairment charge to write-down the rig to its fair value less costs to sell.

Depreciation and Amortization

     Depreciation and amortization expense in 2009 was $193.5 million compared with $182.0 million in 2008, an increase of $11.5 million, or 6.3%. This increase resulted primarily from additional depreciation related to the commencement of Hercules 260 in late April 2008, Hercules 350 in June 2008, Hercules 208 in August 2008, Hercules 261 in December 2008 and Hercules 262 in January 2009. These increases are partially offset by reduced depreciation due to the impairment of certain rigs, barges and related equipment in the fourth quarter of 2008 and lower amortization of our international contract values.

General and Administrative Expenses

     General and administrative expenses in 2009 were $91.2 million compared with $77.1 million in 2008, an increase of $14.1 million, or 18.3%. This increase relates primarily to an allowance for doubtful accounts receivable of $30.8 million, net, of which approximately $26.8 million as of December 31, 2009, related to a customer in its International Offshore segment, partially offset by the cost reduction initiatives implemented in late 2008 and in 2009 in response to the significant decline in activity in several of our business segments. In addition, 2008 included $6.0 million in executive severance related costs.

Interest Expense

     Interest expense increased $13.8 million, or 22.3%. This increase was primarily related to the higher interest capitalized in 2008 and interest expense incurred on our 10.5% Senior Secured Notes issued in October 2009. In addition, the increase in interest rates after the 2009 Credit Amendment were offset by lower debt balances due to the early retirement of a portion of our term loan.

Expense of Credit Agreement Fees

     During 2009, we amended our Credit Agreement and repaid and terminated a portion of our credit facility. In doing so, we recorded the write-off of certain deferred debt issuance costs and certain fees directly related to these activities totaling $15.1 million.

Gain (Loss) on Early Retirement of Debt, Net

Gain on early retirement of debt, net was $12.2 million in 2009 compared with $26.3 million in 2008, a decrease of $14.2 million or 53.9%. During 2009, we retired a portion of our term loan facility and wrote off $1.6 million in associated unamortized issuance costs. In addition, in 2009 we retired $65.8 million aggregate principal amount of the 3.375% Convertible Senior Notes for cash and equity consideration of approximately $40.1 million, resulting in a gain of $13.7 million, net of an associated write-off of a portion of our unamortized issuance costs. In 2008, the gain on early retirement of debt in the amount of $26.3 million related to the December 2008 redemption of $73.2 million accreted principal amount ($88.2 million aggregate principal amount) of the 3.375% Convertible Senior Notes for a cost of $44.8 million, net of the related write off of $2.1 million of unamortized issuance costs.

Other Income

     Other income in 2009 was $4.0 million compared with $3.3 million in 2008, an increase of $0.7 million or 21.1%. This increase is primarily due to foreign currency exchange gains, partially offset by lower interest income.

Income Tax Benefit

     Income tax benefit was $72.8 million on pre-tax loss of $153.9 million during 2009, compared to a benefit of $75.0 million on pre-tax loss of $1,072.9 million for 2008. The effective tax rate changed to a tax benefit of 47.3% in 2009 from a tax benefit of 7.0% in 2008. The change in the effective tax rate is due to the non-deductible goodwill impairment in 2008 as well as a state tax benefit of

$13.4 million based on prior year state tax audits concluded in the fourth quarter of 2009 and a federal tax benefit of $2.5 million based on recent court cases related to alternative minimum tax positions.

Discontinued Operations

     We had a loss from discontinued operations of $10.7 million during 2009 compared to a loss from discontinued operations of $85.5 million during 2008, a decrease of $74.8 million or 88%. This decrease is primarily due to an impairment of goodwill charge for Delta Towing of $86.7 million during 2008.

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 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) the Credit Agreement contains covenants that require us to maintain a total leverage ratio and a consolidated fixed charge coverage ratio, which contain 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. In addition, the EBITDA and Adjusted EBITDA amounts presented in the following table should not be used for covenant compliance purposes as these amounts could differ materially from the amounts ultimately calculated under our Credit Agreement. 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 tables present a reconciliation of the GAAP financial measures to the corresponding adjusted financial measures (in thousands, except per share amounts):

		For the Years Ended December 31,
		2010				2009				2008
Operating Loss		$	(143,427	)		$	(79,469	)		$	(1,040,848	)
Adjustments:
Property and equipment impairment			122,717				26,882				376,668
Goodwill impairment			—				—				863,554
Executive separation and benefit related charges			—				—				6,019
Total adjustments			122,717				26,882				1,246,241
Adjusted Operating Income (Loss)		$	(20,710	)		$	(52,587	)		$	205,393
Loss from Continuing Operations		$	(132,093	)		$	(81,047	)		$	(997,893	)
Adjustments:
Property and equipment impairment			122,717				26,882				376,668
Goodwill impairment			—				—				863,554
Executive separation and benefit related charges			—				—				6,019
Gain on early retirement of debt, net			—				(12,157	)			(26,345	)
Expense of credit agreement fees			—				15,073				—
Tax impact of adjustments			(42,959	)			(14,799	)			(132,824	)
Total adjustments			79,758				14,999				1,087,072
Adjusted Income (Loss) from Continuing Operations		$	(52,335	)		$	(66,048	)		$	89,179
Diluted Loss per Share from Continuing Operations		$	(1.15	)		$	(0.83	)		$	(11.29	)
Adjustments:
Property and equipment impairment			1.07				0.28				4.26
Goodwill impairment			—				—				9.77
Executive separation and benefit related charges			—				—				0.07
Gain on early retirement of debt, net			—				(0.13	)			(0.30	)
Expense of credit agreement fees			—				0.16				—
Tax impact of adjustments			(0.38	)			(0.16	)			(1.50	)
Total adjustments			0.69				0.15				12.30
Adjusted Diluted Earnings (Loss) per Share from Continuing Operations		$	(0.46	)		$	(0.68	)		$	1.01
Loss from Continuing Operations		$	(132,093	)		$	(81,047	)		$	(997,893	)
Interest expense			80,482				75,431				61,671
Income tax benefit			(87,940	)			(72,814	)			(75,014	)
Depreciation and amortization			185,712				193,504				181,968
EBITDA			46,161				115,074				(829,268	)
Adjustments:
Property and equipment impairment			122,717				26,882				376,668
Goodwill impairment			—				—				863,554
Executive separation and benefit related charges			—				—				6,019
Gain on early retirement of debt, net			—				(12,157	)			(26,345	)
Expense of credit agreement fees			—				15,073				—
Total adjustments			122,717				29,798				1,219,896
Adjusted EBITDA		$	168,878			$	144,872			$	390,628

Critical Accounting Policies

     Critical accounting policies are those that are important to our results of operations, financial condition and cash flows and require management’s most difficult, subjective or complex judgments. Different amounts would be reported under alternative assumptions. We have evaluated the accounting policies used in the preparation of the consolidated financial statements and related notes appearing elsewhere in this annual report. We apply those accounting policies that we believe best reflect the underlying business and economic events, consistent with accounting principles generally accepted in the United States. We believe that our policies are generally consistent with those used by other companies in our industry. We base our estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for

making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates.

     We periodically update the estimates used in the preparation of the financial statements based on our latest assessment of the current and projected business and general economic environment. During recent periods, there has been substantial volatility and a decline in natural gas prices. This decline may adversely impact the business of our customers, and in turn our business. This could result in changes to estimates used in preparing our financial statements, including the assessment of certain of our assets for impairment. Our significant accounting policies are summarized in Note 1 to our consolidated financial statements. We believe that our more critical accounting policies include those related to property and equipment, revenue recognition, income tax, allowance for doubtful accounts, deferred charges, stock-based compensation, cash and cash equivalents and intangible assets. Inherent in such policies are certain key assumptions and estimates.

Cash and Cash Equivalents

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

Property and Equipment

     Property and equipment represents 82% of our total assets as of December 31, 2010. Property and equipment is stated at cost, less accumulated depreciation. Expenditures that substantially increase the useful lives of our assets are capitalized and depreciated, while routine expenditures for repairs and maintenance items are expensed as incurred, except for expenditures for drydocking our liftboats. Drydock costs are capitalized at cost as Other Assets, Net on the Consolidated Balance Sheets and amortized on the straight-line method over a period of 12 months (see “Deferred Charges”). Depreciation is computed using the straight-line method, after allowing for salvage value where applicable, over the useful life of the asset, which is typically 15 years for our rigs and liftboats. We review our property and equipment for potential impairment when events or changes in circumstances indicate that the carrying value of any asset may not be recoverable or when reclassifications are made between property and equipment and assets held for sale. Factors that might indicate a potential impairment may include, but are not limited to, significant decreases in the market value of the long-lived asset, a significant change in the long-lived asset’s physical condition, a change in industry conditions or a substantial reduction in cash flows associated with the use of the long-lived asset. For property and equipment held for use, the determination of recoverability is made based on the estimated undiscounted future net cash flows of the related asset or group of assets being reviewed. Any actual impairment charge would be recorded using the estimated discounted value of future cash flows. This evaluation requires us to make judgments regarding long-term forecasts of future revenue and costs. In turn these forecasts are uncertain in that they require assumptions about demand for our services, future market conditions and technological developments. Significant and unanticipated changes to these assumptions could require a provision for impairment in a future period. Given the nature of these evaluations and their application to specific asset groups and specific times, it is not possible to reasonably quantify the impact of changes in these assumptions.

     Supply and demand are the key drivers of rig and vessel utilization and our ability to contract our rigs and vessels at economical rates. During periods of an oversupply, it is not uncommon for us to have rigs or vessels idled for extended periods of time, which could indicate that an asset group may be impaired. Our rigs and vessels are mobile units, equipped to operate in geographic regions throughout the world and, consequently, we may move rigs and vessels from an oversupplied region to one that is more lucrative and undersupplied when it is economical to do so. As such, our rigs and vessels are considered to be interchangeable within classes or asset groups and accordingly, we perform our impairment evaluation by asset group.

     Our estimates, assumptions and judgments used in the application of our property and equipment accounting policies reflect both historical experience and expectations regarding future industry conditions and operations. Using different estimates, assumptions and judgments, especially those involving the useful lives of our rigs and liftboats and expectations regarding future industry conditions and operations, would result in different carrying values of assets and results of operations. For example, a prolonged downturn in the drilling industry in which utilization and dayrates were significantly reduced could result in an impairment of the carrying value of our assets.

     Useful lives of rigs and vessels are difficult to estimate due to a variety of factors, including technological advances that impact the methods or cost of oil and gas exploration and development, changes in market or economic conditions and changes in laws or regulations affecting the drilling industry. We evaluate the remaining useful lives of our rigs and vessels when certain events occur that directly impact our assessment of the remaining useful lives of the rigs and vessels and include changes in operating condition, functional capability and market and economic factors. We also consider major capital upgrades required to perform certain contracts and the long-term impact of those upgrades on the future marketability when assessing the useful lives of individual rigs and vessels.

     When analyzing our assets for impairment, we separate our marketable assets, those assets that are actively marketed and can be warm stacked or cold stacked for short periods of time depending on market conditions, from our non-marketable assets, those assets that have been cold stacked for an extended period of time or those assets that we currently do not reasonably expect to market in the foreseeable future.

     During the fourth quarter 2008, demand for our domestic drilling assets declined dramatically, significantly beyond our expectations. Demand in these segments is driven by underlying commodity prices which fell to levels lower than those seen in several years. The deterioration in these industry conditions in the fourth quarter of 2008 negatively impacted our outlook for 2009 and we responded by cold stacking several additional rigs in 2009. We considered these factors and our change in our outlook as an indicator of impairment and assessed the rig assets of the Inland and Domestic Offshore segments for impairment. Based on an undiscounted cash flow analysis, it was determined that the non-marketable rigs for both segments were impaired. We estimated the value of the discounted cash flows for each segment’s non-marketable rigs and we recorded an impairment charge of $376.7 million for the year ended December 31, 2008. In addition, we analyzed our other segments for impairment as of December 31, 2008 and noted that each segment had adequate undiscounted cash flows to recover their property and equipment carrying values.

     In 2009 we entered into an agreement to sell Hercules 110 and we realized approximately $26.9 million ($13.1 million, net of tax) of impairment charges related to the write-down of the rig to fair value less costs to sell during the second quarter 2009. The sale was completed in August 2009.

     During the fourth quarter 2010, we considered the continued downturn in the drilling industry as an indicator of impairment and assessed our segments for impairment as of December 31, 2010. When analyzing our Domestic Offshore, International Offshore and Delta segments for impairment, we determined five of our domestic jackup rigs, one of our international jackup rigs and several of our Delta Towing assets that had previously been considered marketable, would not be marketed in the foreseeable future and were included in the impairment analysis of non-marketable assets. This determination was based on our current estimate of reactivation costs associated with these assets which, based on current and forecasted near-term dayrates and utilization levels, are economically prohibitive, and the sustained lack of visibility in the issuance of offshore drilling permits in the U.S. Gulf of Mexico. Based on an undiscounted cash flow analysis, it was determined that the non-marketable assets were impaired. We estimated the value of the discounted cash flows for each segment’s non-marketable assets, which included management’s estimate of sales proceeds less costs to sell, and recorded an impairment charge of $125.1 million of which $2.4 million related to our Delta Towing segment and is included in Loss from Discontinued Operations, Net of Taxes in the Consolidated Statements of Operations for the year ended December 31, 2010. We analyzed our other segments and our marketable assets for impairment as of December 31, 2010 and noted that each segment had adequate undiscounted cash flows to recover its property and equipment carrying values.

Revenue Recognition

     Revenue generated from our contracts is recognized as services are performed, as long as collectability is reasonably assured. Some of our contracts also allow us to recover additional direct costs, including mobilization and demobilization costs, additional labor and additional catering costs. Additionally, some of our contracts allow us to receive fees for contract specific capital improvements to a rig. Under most of our liftboat contracts, we receive a variable rate for reimbursement of costs such as catering, fuel, oil, rental equipment, crane overtime and other items. Revenue for the recovery or reimbursement of these costs is recognized when the costs are incurred except for mobilization revenue and reimbursement for contract specific capital expenditures, which are recognized as services are performed over the term of the related contract.

Income Taxes

     Our provision for income taxes takes into account the differences between the financial statement treatment and tax treatment of certain transactions. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates is recognized as income or expense in the period that includes the enactment date.

     Our net income tax expense or benefit is determined based on the mix of domestic and international pre-tax earnings or losses, respectively, as well as the tax jurisdictions in which we operate. We operate in multiple countries through various legal entities. As a result, we are subject to numerous domestic and foreign tax jurisdictions and are taxed on various bases: income before tax, deemed profits (which is generally determined using a percentage of revenue rather than profits), and withholding taxes based on revenue. The calculation of our tax liabilities involves consideration of uncertainties in the application and interpretation of complex tax regulations in our operating jurisdictions. Changes in tax laws, regulations, agreements and treaties, or our level of operations or profitability in each taxing jurisdiction could have an impact upon the amount of income taxes that we provide during any given year.

     In March 2007, one of our subsidiaries received an assessment from the Mexican tax authorities related to our operations for the 2004 tax year. This assessment contested our right to certain deductions and also claimed the subsidiary did not remit withholding tax due on certain of these deductions. During 2010, the Company effectively reached a compromise settlement of all issues for 2004 through 2007. The Company paid $11.6 million and reversed (i) previously provided reserves and (ii) an associated tax benefit in the year which totaled $5.8 million.

     Certain of our international rigs are owned or operated, directly or indirectly, by our wholly owned Cayman Islands subsidiaries. Most of the earnings from these subsidiaries are reinvested internationally and remittance to the United States is indefinitely postponed.

Allowance for Doubtful Accounts

     Accounts receivable represents approximately 7.2% of our total assets and 43.7% of our current assets as of December 31, 2010. We continuously monitor our accounts receivable from our customers to identify any collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions and other pertinent factors. Accounts deemed uncollectable are charged to the allowance. We establish an allowance for doubtful accounts based on the actual amount we believe is not collectable. As of December 31, 2010 and 2009, there was $29.8 million and $38.5 million in allowance for doubtful accounts, respectively.

Deferred Charges

     All of our U.S. flagged liftboats are required to undergo regulatory inspections on an annual basis and to be drydocked two times every five years to ensure compliance with U.S. Coast Guard regulations for vessel safety and vessel maintenance standards. Costs associated with these inspections, which generally involve setting the vessels on a drydock, are deferred, and the costs are amortized over a period of 12 months. As of December 31, 2010 and 2009, our net deferred charges related to regulatory inspection costs totaled $5.4 million and $4.8 million, respectively. The amortization of the regulatory inspection costs was reported as part of our depreciation and amortization expense.

Stock-Based Compensation

     We recognize compensation cost for all share-based payments awarded in accordance with Financial Accounting Standards Board (“FASB”) Codification Topic 718, Compensation—Stock Compensation and in accordance with such we record the grant date fair value of share-based payments awarded as compensation expense using a straight-line method over the service period. The fair value of our restricted stock grants is based on the closing price of our common stock on the date of grant. Our estimate of compensation expense requires a number of complex and subjective assumptions and changes to those assumptions could result in different valuations for individual share awards. We estimate the fair value of the options granted using the Trinomial Lattice option pricing model using the following assumptions: expected dividend yield, expected stock price volatility, risk-free interest rate and employee exercise patterns (expected life of the options). We also estimate future forfeitures and related tax effects.

     We are estimating that the cost relating to stock options granted through December 31, 2010 will be $2.6 million over the remaining vesting period of 1.4 years and the cost relating to restricted stock granted through December 31, 2010 will be $2.3 million over the remaining vesting period of 1.2 years; however, due to the uncertainty of the level of share-based payments to be granted in the future, these amounts are estimates and subject to change.

LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses of Cash

     Sources and uses of cash for 2010 and 2009 are as follows (in millions):

		2010				2009
Net Cash Provided by Operating Activities		$	24.4			$	137.9
Net Cash Provided by (Used in) Investing Activities:
Additions of Property and Equipment			(22.0	)			(76.1	)
Deferred Drydocking Expenditures			(15.0	)			(15.6	)
Proceeds from Sale of Assets, Net			23.2				25.8
Insurance Proceeds Received			—				9.1
Increase in Restricted Cash			(7.5	)			(3.7	)
Total			(21.3	)			(60.5	)
Net Cash Provided by (Used in) Financing Activities:
Short-term Debt Repayments, Net			—				(2.5	)
Long-term Debt Borrowings			—				292.1
Long-term Debt Repayments			(7.7	)			(403.6	)
Redemption of 3.375% Convertible Senior Notes			—				(6.1	)
Common Stock Issuance			—				89.6
Excess Tax Benefit from Stock-Based Arrangements			0.4				5.6
Payment of Debt Issuance Costs			—				(18.1	)
Total			(7.3	)			(43.0	)
Net Increase (Decrease) in Cash and Cash Equivalents		$	(4.2	)		$	34.4

Sources of Liquidity and Financing Arrangements

     Our liquidity is comprised of cash on hand, cash from operations and availability under our revolving credit facility. We also maintain a shelf registration statement covering the future issuance from time to time of various types of securities, including debt and equity securities. If we issue any debt securities off the shelf or otherwise incur debt, we would generally be required to allocate the proceeds of such debt to repay or refinance existing debt. We currently believe we will have adequate liquidity to meet the minimum liquidity requirement under our Credit Agreement that governs our $475.2 million term loan and $140.0 million revolving credit facility and 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 meet certain covenants under the Credit Agreement, to refinance existing debt or for general corporate purposes. In July 2012, our $140.0 million revolving credit facility matures. To the extent we are unsuccessful in extending the maturity or entering into a new revolving credit facility, our liquidity would be negatively impacted. In June 2013, we may be required to settle our 3.375% Convertible Senior Notes. As of December 31, 2010, the notional amount of these notes outstanding was $95.9 million. Additionally, our term loan matures in July 2013 and currently requires a balloon payment of $464.1 million at maturity. We intend to meet these obligations through one or more of the following: cash flow from operations, asset sales, debt refinancing and future debt or equity offerings.

     Our Credit Agreement imposes various affirmative and negative covenants, including requirements to meet certain financial ratios and tests, which we currently meet. Our failure to comply with such covenants would result in an event of default under the Credit Agreement. Additionally, in order to maintain compliance with our financial covenants, borrowings under our revolving credit facility may be limited to an amount less than the full amount of remaining availability after outstanding letters of credit. An event of default could prevent us from borrowing under the revolving credit facility, which would in turn have a material adverse effect on our

available liquidity. Furthermore, an event of default could result in us having to immediately repay all amounts outstanding under the term loan facility, the revolving credit facility, our 10.5% Senior Secured Notes and our 3.375% Convertible Senior Notes and in the foreclosure of liens on our assets.

Cash Requirements and Contractual Obligations

Debt

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

     In July 2007, we terminated all prior facilities and entered into a $1,050.0 million credit facility with a syndicate of financial institutions, consisting of a $900.0 million term loan and a $150.0 million revolving credit facility which is governed by the Credit Agreement. In April 2008, we entered into an agreement to increase the revolving credit facility to $250.0 million and in each of July 2009 and March 2011, the terms of the Credit Agreement were amended. The substantial changes to the terms of the Credit Agreement related to the July 2009 and March 2011 amendments are further described:

July 2009 Credit Amendment

     On July 27, 2009, we amended the Credit Agreement (the “2009 Credit Amendment”). A fee of 0.50% was paid to lenders consenting to the 2009 Credit Amendment, based on their total commitment, which approximated $4.8 million.

     The 2009 Credit Amendment reduced the revolving credit facility by $75.0 million to $175.0 million. The commitment fee on the revolving credit facility increased from 0.375% to 1.00% and the letter of credit fee with respect to the undrawn amount of each letter of credit issued under the revolving credit facility increased from 1.75% to 4.00% per annum. Additionally, the 2009 Credit Amendment established a minimum London Interbank Offered Rate (“LIBOR”) of 2.00% for Eurodollar Loans, a minimum rate of 3.00% with respect to Alternative Base Rate (“ABR”) Loans, and increased the margin applicable to Eurodollar Loans and ABR Loans, subject to a grid based on the aggregate principal amount of the term loans outstanding as follows ($ in millions):

		Principal Amount Outstanding								Margin Applicable to:
		Less than or equal to:				Greater than:				Eurodollar Loans				ABR Loans
		$	882.00			$	684.25				6.50	%			5.50	%
			684.25				484.25				5.00	%			4.00	%
			484.25				—				4.00	%			3.00	%

The 2009 Credit Amendment also modified certain provisions of the Credit Agreement to, among other things:

	•		Eliminate the requirement that we comply with the total leverage ratio financial covenant for the nine month period commencing October 1, 2009 and ending on June 30, 2010.
	•		Amend the maximum total leverage ratio that we must comply with. The total leverage ratio for any test period is calculated as the ratio of consolidated indebtedness on the test date to consolidated EBITDA for the trailing twelve months, all as defined in the Credit Agreement.
	•		Require us to maintain a minimum level of liquidity, measured as the amount of unrestricted cash and cash equivalents we have on hand and availability under the revolving credit facility, of (i) $100.0 million for the period between October 1, 2009 through December 31, 2010, (ii) $75.0 million during calendar year 2011 and (iii) $50.0 million thereafter. As of December 31, 2010, as calculated pursuant to our Credit Agreement, our total liquidity was $300.2 million.
	•		Revise the consolidated fixed charge coverage ratio definition and reduce the minimum fixed charge coverage ratio that we must maintain to the following schedule:

								Fixed Charge
Period								Coverage Ratio
July 1, 2009			—			December 31, 2011			1.00 to 1.00
January 1, 2012			—			March 31, 2012			1.05 to 1.00
April 1, 2012			—			June 30, 2012			1.10 to 1.00
July 1, 2012 and thereafter									1.15 to 1.00

–

The consolidated fixed charge coverage ratio for any test period is defined as the sum of consolidated EBITDA for the test period plus an amount that may be added for the purpose of calculating the ratio for such test period, not to exceed $130.0 million in total during the term of the credit facility, to consolidated fixed charges for the test period adjusted by an amount not to exceed $110.0 million during the term of the credit facility to be deducted from capital expenditures, all as defined in the Credit Agreement. As of December 31, 2010, our fixed charge coverage ratio was 1.66 to 1.00.

•

Require mandatory prepayments of debt outstanding under the Credit Agreement with 100% of excess cash flow as defined in the Credit Agreement for the fiscal year ending December 31, 2009 and 50% of excess cash flow as defined in the Credit Agreement for the fiscal years ending December 31, 2010, 2011 and 2012, and with proceeds from:

	–		unsecured debt issuances, with the exception of refinancing;
	–		secured debt issuances;
	–		casualty events not used to repair damaged property;
	–		sales of assets in excess of $25 million annually; and
	–		unless we have achieved a specified leverage ratio, 50% of proceeds from equity issuances, excluding those for permitted acquisitions or to meet the minimum liquidity requirements.

March 2011 Credit Amendment

     On March 3, 2011, we amended our Credit Agreement (“2011 Credit Amendment”) to, among other things:

	–		Allow for the use of cash to purchase assets from Seahawk Drilling, Inc. (“Seahawk”), to the extent set forth in our previously disclosed Asset Purchase Agreement with Seahawk;
	–		Exempt the pro forma treatment of historical results from the Seahawk assets with respect to the calculation of the financial covenants in the Credit Agreement;
	–		Increase our investment basket to $50 million from $25 million; and
	–		Revise the covenant threshold levels of the Total Leverage Ratio, as defined in the Credit Agreement, to the following schedule:

				Amended Total		Amended Total
				Leverage Ratio		Leverage Ratio
				(If Seahawk		(If Seahawk
				Acquisition		Acquisition
				has been		has not been
				consummated		consummated
				during or prior to		during or prior to
				the relevant Test		the relevant Test
Test Date		Previous Total Leverage Ratio		Period)		Period)
September 30, 2010		8.00 to 1.00		No Change		No Change
December 31, 2010		7.50 to 1.00		No Change		No Change
March 31, 2011		7.00 to 1.00		No Change		No Change
June 30, 2011		6.75 to 1.00		No Change		No Change
September 30, 2011		6.00 to 1.00		7.50 to 1.00		7.50 to 1.00
December 31, 2011		5.50 to 1.00		7.75 to 1.00		7.75 to 1.00
March 31, 2012		5.25 to 1.00		7.50 to 1.00		7.75 to 1.00
June 30, 2012		5.00 to 1.00		7.25 to 1.00		7.50 to 1.00
September 30, 2012		4.75 to 1.00		6.75 to 1.00		7.00 to 1.00
December 31, 2012		4.50 to 1.00		6.25 to 1.00		6.50 to 1.00
March 31, 2013		4.25 to 1.00		6.00 to 1.00		6.25 to 1.00
June 30, 2013		4.00 to 1.00		5.75 to 1.00		6.00 to 1.00

–

At December 31, 2010, our total leverage ratio was 5.06 to 1.00.

     In addition, the interest rates on borrowings under the Credit Facility will increase to 5.50% plus LIBOR for Eurodollar Loans and 4.50% plus the Alternate Base Rate for ABR Loans, compared to prior rates of 4.00% plus LIBOR for Eurodollar Loans and 3.00% plus the Alternate Base Rate for ABR Loans. The minimum LIBOR of 2.00% for Eurodollar Loans, or a minimum base rate of 3.00% with respect to ABR Loans, which was established with the 2009 Credit Amendment, remains. We also agreed to pay consenting lenders an upfront fee of 0.25% on their commitment, or approximately $1.4 million. Including agent bank fees and expenses our total cost is approximately $2.0 million. Total commitments on the revolving credit facility, which is currently unfunded, will be reduced to $140.0 million from $175.0 million.

     At December 31, 2010, the credit facility consisted of a $475.2 million term loan which matures on July 11, 2013 and a $175.0 million revolving credit facility that matures on July 11, 2012, under which the remaining availability was $163.5 million as $11.5 million in standby letters of credit had been issued under it. As of March 3, 2011, the effective date of the 2011 Credit Amendment, the credit facility consisted of a $475.2 million term loan and a $140.0 million revolving credit facility, which had remaining availability of $129.1 million as $10.9 million in standby letters of credit were outstanding under it. The availability under the revolving credit facility must be used for working capital, capital expenditures and other general corporate purposes and cannot be used to prepay our term loan. Other than the required prepayments as outlined previously, the principal amount of the term loan amortizes in equal quarterly installments of approximately $1.2 million, with the balance due on July 11, 2013. Interest payments on both the revolving and term loan facility are due at least on a quarterly basis and in certain instances, more frequently. In addition to our scheduled payments, during the fourth quarter of 2009, we used the net proceeds from the equity issuance pursuant to the partial exercise of the underwriters’ over-allotment option and the 10.5% Senior Secured Notes due 2017, which approximated $287.5 million, as well as cash on hand to retire $379.6 million of the outstanding balance on our term loan facility. In connection with the early retirement, we recorded a pretax charge of $1.6 million, $1.0 million, net of tax, related to the write off of unamortized issuance costs. As of December 31, 2010, $475.2 million was outstanding on the term loan facility and the interest rate was 6.00%. The annualized effective interest rate was 8.29% for the year ended December 31, 2010 after giving consideration to revolver fees and derivative activity.

     Other covenants contained in the Credit Agreement restrict, among other things, asset dispositions, mergers and acquisitions, dividends, stock repurchases and redemptions, other restricted payments, debt issuances, liens, investments, convertible notes repurchases and affiliate transactions. The Credit Agreement also contains a provision under which an event of default on any other indebtedness exceeding $25.0 million would be considered an event of default under our Credit Agreement.

     In July 2007, we entered into a zero cost LIBOR collar on $300.0 million of term loan principal with a final settlement date of October 1, 2010 (which was settled on October 1, 2010 per the agreement with a cash payment of $3.4 million) with a ceiling of 5.75% and a floor of 4.99%. The counterparty was obligated to pay us in any quarter that actual LIBOR reset above 5.75% and we paid the counterparty in any quarter that actual LIBOR reset below 4.99%. The terms and settlement dates of the collar matched those of the term loan through July 27, 2009, the date of the 2009 Credit Amendment.

     As a result of the inclusion of a LIBOR floor in the Credit Agreement, we determined, as of July 27, 2009 and on an ongoing basis, that the interest rate collar (which was settled on October 1, 2010) will not be highly effective in achieving offsetting changes in cash flows attributable to the hedged interest rate risk during the period that the hedge was designated. As such, we discontinued cash flow hedge accounting for the interest rate collar as of July 27, 2009. Because cash flow hedge accounting was not applied to this instrument, changes in fair value related to the interest rate collar subsequent to July 27, 2009 have been recorded in earnings. As a result of discontinuing the cash flow hedging relationship, we recognized a decrease in fair value of $0.3 million and $1.7 million related to the hedge ineffectiveness of our interest rate collar as Interest Expense in our Consolidated Statements of Operations for the years ended December 31, 2010 and 2009, respectively. We did not recognize a gain or loss due to hedge ineffectiveness in the Consolidated Statements of Operations for the year ended December 31, 2008 related to interest rate derivative instruments. The change in the fair value of our hedging instruments resulted in a decrease in derivative liabilities of $10.3 million during the year ended December 31, 2010. We had net unrealized gains on hedge transactions of $5.8 million, net of tax of $3.1 million and $9.2 million, net of tax of $4.9 million for the years ended December 31, 2010 and 2009, respectively, and net unrealized losses on hedge transactions of $6.8 million, net of tax of $3.7 million for the year ended December 31, 2008. Overall, our interest expense was increased by $9.1 million, $18.3 million and $7.7 million during the years ended December 31, 2010, 2009 and 2008, respectively, as a result of our interest rate derivative instruments.

     On October 20, 2009, we completed an offering of $300.0 million of senior secured notes at a coupon rate of 10.5% (“10.5% Senior Secured Notes”) with a maturity in October 2017. The interest on the 10.5% Senior Secured Notes is payable in cash semi-annually in arrears on April 15 and October 15 of each year, which commenced on April 15, 2010, 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. We used the net proceeds of approximately $284.4 million from the offering to repay a portion of the indebtedness outstanding under our term loan facility. As of December 31, 2010, $300.0 million notional amount of the 10.5%

Senior Secured Notes was outstanding. The carrying amount of the 10.5% Senior Secured Notes was $292.9 million at December 31, 2010.

     The notes are guaranteed by all of our existing and future restricted subsidiaries that incur or guarantee indebtedness under a credit facility, including our existing credit facility. 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.

     All the liens securing the notes may be released if our secured indebtedness, other than these 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.” If a collateral suspension is in effect, the notes and the guarantees will be unsecured, and will effectively rank junior to our secured indebtedness to the extent of the value of the collateral securing such indebtedness. If, after any such release of liens on collateral, the aggregate principal amount of our secured indebtedness, other than these notes, exceeds the greater of $375.0 million and 15.0% of our consolidated tangible assets, as defined in the indenture, then the collateral obligations of the Company and guarantors will be reinstated and must be complied with within 30 days of such event.

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

	•		incur additional indebtedness or issue certain preferred stock;
	•		pay dividends or make other distributions;
	•		make other restricted payments or investments;
	•		sell assets;
	•		create liens;
	•		enter into agreements that restrict dividends and other payments by restricted subsidiaries;
	•		engage in transactions with our affiliates; and
	•		consolidate, merge or transfer all or substantially all of our assets.

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

     Prior to October 15, 2012, we may redeem the notes with the net cash proceeds of certain equity offerings, at a redemption price equal to 110.50% of the aggregate principal amount plus accrued and unpaid interest; provided, that (i) after giving effect to any such redemption, at least 65% of the notes originally issued would remain outstanding immediately after such redemption and (ii) we make such redemption not more than 90 days after the consummation of such equity offering. In addition, prior to October 15, 2013, we may redeem all or part of the notes at a price equal to 100% of the aggregate principal amount of notes to be redeemed, plus the applicable premium, as defined in the indenture, and accrued and unpaid interest.

     On or after October 15, 2013, we may redeem the notes, in whole or part, at the redemption prices set forth below, together with accrued and unpaid interest to the redemption date.

Year		Optional Redemption Price
2013			105.2500	%
2014			102.6250	%
2015			101.3125	%
2016 and thereafter			100.0000	%

     If we experience a change of control, as defined, we must offer to repurchase the notes at an offer price in cash equal to 101% of their principal amount, plus accrued and unpaid interest. Furthermore, following certain asset sales, we may be required to use the proceeds to offer to repurchase the notes at an offer price in cash equal to 100% of their principal amount, plus accrued and unpaid interest.

     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 December 31, 2010, $95.9 million notional amount of the $250.0 million 3.375% Convertible Senior Notes was outstanding. The net carrying amount of the 3.375% Convertible Senior Notes was $86.5 million at December 31, 2010.

     The interest on the 3.375% Convertible Senior Notes is payable in cash semi-annually in arrears, on June 1 and December 1 of each year until June 1, 2013, after which the principal will accrete at an annual yield to maturity of 3.375% per year. We will also pay contingent interest during any six-month interest period commencing June 1, 2013, for which the trading price of these notes for a

specified period of time equals or exceeds 120% of their accreted principal amount. The 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 December 31, 2010, the number of conversion shares potentially issuable in relation to our 3.375% Convertible Senior Notes was 1.9 million. We may redeem the notes at our option beginning June 6, 2013, and holders of the notes will have the right to require us to repurchase the notes on June 1, 2013 and certain dates thereafter or on the occurrence of a fundamental change.

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

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

     During December 2008 and April 2009, we repurchased $88.2 million and $20.0 million aggregate principal amount of the 3.375% Convertible Senior Notes, respectively, for a cost of $44.8 million and $6.1 million, respectively. In addition, during December 2008 and April 2009 we recognized a gain of $28.4 million and $10.7 million, respectively and expensed $2.1 million and $0.4 million of unamortized issuance costs, respectively, in connection with the retirements. In June 2009, we retired $45.8 million aggregate principal amount of our 3.375% Convertible Senior Notes in exchange for the issuance of 7,755,440 shares of Common Stock valued at $4.38 per share and payment of accrued interest, resulting in a gain of $4.4 million. In addition, we expensed $1.0 million of unamortized issuance costs in connection with the retirement. 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.

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

		December 31, 2010								December 31, 2009
		Carrying				Fair				Carrying				Fair
		Value				Value				Value				Value
		(in millions)
Term Loan Facility, due July 2013		$	475.2			$	443.7			$	482.9			$	468.4
10.5% Senior Secured Notes, due October 2017			292.9				245.1				292.3				315.8
3.375% Convertible Senior Notes, due June 2038			86.5				69.1				83.1				76.8
7.375% Senior Notes, due April 2018			3.5				2.2				3.5				3.0

     In April 2010, 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 $2.1 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 $100.0 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 $50 million primary covering liability 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 as well as a separate underlying marine package for our Delta Towing business.

     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. 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 2010, in connection with the renewal of certain of our insurance policies, we entered into agreements to finance a portion of our annual insurance premiums. Approximately $25.9 million was financed through these arrangements, and $6.0 million was outstanding at December 31, 2010. The interest rate on the $24.1 million note is 3.79% and the note is scheduled to mature in March 2011. The interest rate on the $1.8 million note is 3.54% and the note is scheduled to mature in July 2011. There was $5.5 million outstanding in insurance notes payable at December 31, 2009 which were fully paid during 2010.

     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.

Common Stock Offering

     In September 2009, we raised approximately $82.3 million in net proceeds from an underwritten public offering of 17,500,000 shares of our Common Stock. In addition, in October 2009, we sold an additional 1,313,590 shares of our Common Stock pursuant to the partial exercise of the underwriters’ over-allotment option and raised an additional $6.3 million in net proceeds. We used a portion of the net proceeds from these sales of Common Stock to repay a portion of our outstanding indebtedness under our term loan facility.

Capital Expenditures

     We expect to spend approximately $60 million on capital expenditures and drydocking during 2011. Planned capital expenditures are generally maintenance and regulatory in nature and do not include refurbishment or upgrades to our rigs, liftboats, and other marine vessels. Should we elect to reactivate cold stacked rigs or upgrade and refurbish selected rigs or liftboats our capital expenditures may increase. Reactivation, upgrades and refurbishments are subject to our discretion and will depend on our view of market conditions and our cash flows.

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

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

     From time to time, we may review possible acquisitions of rigs, liftboats or businesses, joint ventures, mergers or other business combinations, and we may have outstanding from time to time bids to acquire certain assets from other companies. We may not, however, be successful in our acquisition efforts. We are generally restricted by our Credit Agreement from making acquisitions for cash consideration, except to the extent the acquisition is funded by an issuance of our stock or cash proceeds from the issuance of

stock (with the exception of the Seahawk acquisition), or unless we are in compliance with more restrictive financial covenants than what we are normally required to meet in each respective period as defined in the 2011 Credit Amendment. If we acquire additional assets, we would expect that the ongoing capital expenditures for our company as a whole would increase in order to maintain our equipment in a competitive condition.

     Our ability to fund capital expenditures would be adversely affected if conditions deteriorate in our business.

Contractual Obligations

     Our contractual obligations and commitments principally include obligations associated with our outstanding indebtedness, certain income tax liabilities, surety bonds, letters of credit, future minimum operating lease obligations, purchase commitments and management compensation obligations.

     The following table summarizes our contractual obligations and contingent commitments by period as of December 31, 2010:

		Payments due by Period
Contractual Obligations and		Less than				1-3				4-5				After 5
Contingent Commitments		1 Year				Years				Years				Years				Total
		(In thousands)
Recorded Obligations:
Long-term debt obligations		$	4,924			$	566,155			$	—			$	303,508			$	874,587
Insurance notes payable			5,984				—				—				—				5,984
Interest on debt and notes payable(c)			6,974				—				—				—				6,974
Purchase obligations(a)			5,388				—				—				—				5,388
Other			2,756				—				—				—				2,756
Unrecorded Obligations(b):
Interest on debt and notes payable(c)			59,012				111,945				63,518				63,647				298,122
Bank guarantees			966				—				—				—				966
Letters of credit			11,568				—				—				—				11,568
Surety bonds			31,414				—				—				—				31,414
Management compensation obligations			3,538				6,808				—				—				10,346
Purchase obligations(a)			1,945				—				—				—				1,945
Operating lease obligations			4,174				4,503				4,120				4,266				17,063
Total contractual obligations		$	138,643			$	689,411			$	67,638			$	371,421			$	1,267,113

Off-Balance Sheet Arrangements

Guarantees

     Our obligations under the credit facility and 10.5% Senior Secured Notes are secured by liens on a majority of our vessels and substantially all of our other personal property. Substantially all of our domestic subsidiaries, and several of our international subsidiaries, guarantee the obligations under the credit facility and 10.5% Senior Secured Notes and have granted similar liens on the majority of their vessels and substantially all of their other personal property.

Bank Guarantees, Letters of Credit and Surety Bonds

     We execute bank guarantees, letters of credit and surety bonds in the normal course of business. While these obligations are not normally called, these obligations could be called by the beneficiaries at any time before the expiration date should we breach certain contractual or payment obligations. As of December 31, 2010, we had $44.0 million of bank guarantees, letters of credit and surety bonds outstanding, consisting of a $1.0 million unsecured bank guarantee, a $0.1 million unsecured outstanding letter of credit, $11.5 million in standby letters of credit outstanding under our revolver and $31.4 million outstanding in surety bonds that guarantee our performance as it relates to our drilling contracts and other obligations primarily in Mexico and the U.S. If the beneficiaries called the bank guarantee, letters of credit and surety bonds, the called amount would become an on-balance sheet liability, and we would be required to settle the liability with cash on hand or through borrowings under our available line of credit. As of December 31, 2010 we have restricted cash of $11.1 million to support surety bonds primarily related to the Company’s Mexico and U.S. operations.

Accounting Pronouncements

     In January 2010, the FASB issued Accounting Standards Update (“ASU”) No. 2010-06, Improving Disclosures about Fair Value Measurements (“ASU 2010-06”), which requires additional disclosures about the various classes of assets and liabilities measured at fair value, the valuation techniques and inputs used, the activity in Level 3 fair value measurements and the transfers between Levels 1, 2, and 3. The disclosures are effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements, which are effective for interim and annual reporting periods beginning after December 15, 2010. We adopted the required portions of ASU 2010-06 as of January 1, 2010 with no material impact to our consolidated financial statements and will adopt the remaining portions on January 1, 2011 with no expected material impact on our consolidated financial statements.

FORWARD-LOOKING STATEMENTS

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

	•		our 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 long-term international contracts, or enter into new contracts, at current dayrates 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 cost cutting measures and plans to dispose of certain assets;
	•		expected completion times for our refurbishment and upgrade projects;
	•		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;
	•		our ability to effectively reactivate rigs that we have stacked;
	•		liabilities and restrictions under coastwise and other laws of the United States and regulations protecting the environment;
	•		expected outcomes of litigation, claims and disputes and their expected effects on our financial condition and results of operations; and
	•		expectations regarding offshore drilling activity and dayrates, market conditions, demand for our rigs and liftboats, our earnings, operating revenue, operating and maintenance expense, insurance coverage, insurance expense and deductibles, interest expense, debt levels and other matters with regard to outlook.

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

	•		the ability of our customers in the U.S. Gulf of Mexico to obtain drilling permits;
	•		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 in view of recent reductions in our personnel;
	•		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 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 7A. 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. As of December 31, 2010, we have no derivative financial instruments outstanding. A discussion of our market risk exposure in financial instruments follows.

Interest Rate Exposure

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

     As of December 31, 2010, the long-term borrowings that were outstanding subject to fixed interest rate risk consisted of the 7.375% Senior Notes due April 2018, the 3.375% Convertible Senior Notes due June 2038 and the 10.5% Senior Secured Notes due October 2017 with a carrying amount of $3.5 million, $86.5 million, and $292.9 million, respectively.

     As of December 31, 2010 the interest rate for the $475.2 million outstanding under the term loan was 6.0%. If the interest rate averages 1% more for 2011 than the rates as of December 31, 2010, annual interest expense would increase by approximately $4.8 million. This sensitivity analysis assumes there are no changes in our financial structure and excludes the impact of our interest rate derivatives, if any.

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

		December 31, 2010								December 31, 2009
		Carrying				Fair				Carrying				Fair
		Value				Value				Value				Value
		(in millions)
Term Loan Facility, due July 2013		$	475.2			$	443.7			$	482.9			$	468.4
10.5% Senior Secured Notes, due October 2017			292.9				245.1				292.3				315.8
3.375% Convertible Senior Notes, due June 2038			86.5				69.1				83.1				76.8
7.375% Senior Notes, due April 2018			3.5				2.2				3.5				3.0

Item 8. Financial Statements and Supplementary Data

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and
Stockholders of Hercules Offshore, Inc.:

     We have audited the accompanying consolidated balance sheets of Hercules Offshore, Inc. and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity, comprehensive loss and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

     We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

     In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Hercules Offshore, Inc. and subsidiaries at December 31, 2010 and 2009, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

     As discussed in Note 1 to the consolidated financial statements, on January 1, 2009, the Company adopted Financial Accounting Standards Board (“FASB”) Staff Position No. APB 14-1, “Accounting for Convertible Debt Instruments that May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)” (codified in FASB ASC Topic 470 “Debt”) and, as required, the consolidated financial statements have been adjusted for retrospective application.

     We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Hercules Offshore Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 9, 2011 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Houston, Texas
March 9, 2011, except for the effects of discontinued operations as discussed in Note 1, as to which the date is July 7, 2011.

HERCULES OFFSHORE, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except par value)

		December 31,
		2010				2009
ASSETS
Current Assets:
Cash and Cash Equivalents		$	136,666			$	140,828
Restricted Cash			11,128				3,658
Accounts Receivable, Net of Allowance for Doubtful Accounts of $29,798 and $38,522 as of December 31, 2010 and 2009, respectively			143,796				133,662
Prepaids			17,142				13,706
Current Deferred Tax Asset			8,488				22,885
Other			11,794				6,675
			329,014				321,414
Property and Equipment, Net			1,634,542				1,923,603
Other Assets, Net			31,753				32,459
		$	1,995,309			$	2,277,476
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term Debt and Current Portion of Long-term Debt		$	4,924			$	4,952
Insurance Notes Payable			5,984				5,484
Accounts Payable			52,279				51,868
Accrued Liabilities			59,861				67,773
Interest Payable			6,974				6,624
Taxes Payable			—				5,671
Other Current Liabilities			16,716				34,229
			146,738				176,601
Long-term Debt, Net of Current Portion			853,166				856,755
Other Liabilities			6,716				19,809
Deferred Income Taxes			135,557				245,799
Commitments and Contingencies
Stockholders’ Equity:
Common Stock, $0.01 Par Value; 200,000 Shares Authorized; 116,336 and 116,154 Shares Issued, Respectively; 114,784 and 114,650 Shares Outstanding, Respectively			1,163				1,162
Capital in Excess of Par Value			1,924,659				1,921,037
Treasury Stock, at Cost, 1,552 Shares and 1,504 Shares, Respectively			(50,333	)			(50,151	)
Accumulated Other Comprehensive Loss			—				(5,773	)
Retained Deficit			(1,022,357	)			(887,763	)
			853,132				978,512
		$	1,995,309			$	2,277,476

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

HERCULES OFFSHORE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(As Adjusted (Note 1))
(In thousands, except per share data)

		Year Ended December 31,
		2010				2009				2008
Revenue		$	624,827			$	718,601			$	1,053,479
Costs and Expenses:
Operating Expenses			403,829				486,462				595,035
Impairment of Goodwill			—				—				863,554
Impairment of Property and Equipment			122,717				26,882				376,668
Depreciation and Amortization			185,712				193,504				181,968
General and Administrative			55,996				91,222				77,102
			768,254				798,070				2,094,327
Operating Loss			(143,427	)			(79,469	)			(1,040,848	)
Other Income (Expense):
Interest Expense			(80,482	)			(75,431	)			(61,671	)
Expense of Credit Agreement Fees			—				(15,073	)			—
Gain on Early Retirement of Debt, Net			—				12,157				26,345
Other, Net			3,876				3,955				3,267
Loss Before Income Taxes			(220,033	)			(153,861	)			(1,072,907	)
Income Tax Benefit			87,940				72,814				75,014
Loss from Continuing Operations			(132,093	)			(81,047	)			(997,893	)
Loss from Discontinued Operations, Net of Taxes			(2,501	)			(10,687	)			(85,497	)
Net Loss		$	(134,594	)		$	(91,734	)		$	(1,083,390	)
Basic Loss Per Share:
Loss from Continuing Operations		$	(1.15	)		$	(0.83	)		$	(11.29	)
Loss from Discontinued Operations			(0.02	)			(0.11	)			(0.97	)
Net Loss		$	(1.17	)		$	(0.94	)		$	(12.26	)
Diluted Loss Per Share:
Loss from Continuing Operations		$	(1.15	)		$	(0.83	)		$	(11.29	)
Loss from Discontinued Operations			(0.02	)			(0.11	)			(0.97	)
Net Loss		$	(1.17	)		$	(0.94	)		$	(12.26	)
Weighted Average Shares Outstanding:
Basic			114,753				97,114				88,351
Diluted			114,753				97,114				88,351

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

HERCULES OFFSHORE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In thousands)

		December 31, 2010								December 31, 2009								December 31, 2008
		Shares				Amount				Shares				Amount				Shares				Amount
Common Stock:
Balance at Beginning of Period			116,154			$	1,162				89,459			$	895				88,876			$	889
Exercise of Stock Options			11				—				—				—				478				5
Issuance of Common Stock, Net			—				—				26,569				266				—				—
Issuance of Restricted Stock			171				1				126				1				105				1
Balance at End of Period			116,336				1,163				116,154				1,162				89,459				895
Capital in Excess of Par Value:
Balance at Beginning of Period			—				1,921,037				—				1,785,462				—				1,731,882
Exercise of Stock Options			—				18				—				—				—				5,122
Issuance of Common Stock, Net			—				—				—				122,762				—				—
Issuance of Restricted Stock			—				(1	)			—				(1	)			—				(1	)
Compensation Expense Recognized			—				4,431				—				8,257				—				12,535
Adjustment due to Convertible Debt Accounting Change (See Note 1)			—				—				—				—				—				30,070
Excess Tax Benefit (Deficit) From Stock-Based Arrangements, Net			—				(826	)			—				4,571				—				5,860
Other			—				—				—				(14	)			—				(6	)
Balance at End of Period			—				1,924,659				—				1,921,037				—				1,785,462
Treasury Stock:
Balance at Beginning of Period			(1,504	)			(50,151	)			(1,483	)			(50,081	)			(19	)			(582	)
Repurchase of Common Stock			(48	)			(182	)			(21	)			(70	)			(1,464	)			(49,499	)
Balance at End of Period			(1,552	)			(50,333	)			(1,504	)			(50,151	)			(1,483	)			(50,081	)
Accumulated Other Comprehensive
Loss:
Balance at Beginning of Period			—				(5,773	)			—				(14,932	)			—				(8,117	)
Change in Unrealized Gain (Loss) on Hedge Transactions, Net of Tax of $(3,108), $(4,932) and $3,669, Respectively			—				5,773				—				9,159				—				(6,815	)
Balance at End of Period, Net of Tax of $0, $3,108 and $8,040, Respectively			—				—				—				(5,773	)			—				(14,932	)
Retained Deficit:
Balance at Beginning of Period			—				(887,763	)			—				(796,029	)			—				287,361
Net Loss			—				(134,594	)			—				(91,734	)			—				(1,083,390	)
Balance at End of Period			—				(1,022,357	)			—				(887,763	)			—				(796,029	)
Total Stockholders’ Equity			114,784			$	853,132				114,650			$	978,512				87,976			$	925,315