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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Mar. 31, 2011	Dec. 31, 2010
Current assets:
Cash and cash equivalents	$ 440,531	$ 391,085
Accounts receivable - Trade, net of allowance for uncollectible accounts of $4,445 and $4,527, respectively	190,859	177,293
Unbilled revenue	21,959	33,712
Costs in excess of billing	434	15,699
Other current assets	113,829	123,065
Total current assets	767,612	740,854
Property and equipment	4,535,834	4,486,077
Less - accumulated depreciation	(2,046,613)	(1,958,997)
Property and equipment, net	2,489,221	2,527,080
Other assets:
Equity investments	186,831	187,031
Goodwill, net	62,956	62,494
Other assets, net	70,449	74,561
Total assets	3,577,069	3,592,020
Current liabilities:
Accounts payable	126,364	159,381
Accrued liabilities	199,479	198,237
Current maturities of long-term debt	9,638	10,179
Total current liabilities	335,481	367,797
Long-term debt	1,346,469	1,347,753
Deferred income taxes	415,312	413,639
Asset retirement obligations	168,014	170,410
Other long-term liabilities	5,301	5,777
Total liabilities	2,270,577	2,305,376
Convertible preferred stock	$ 1,000	$ 1,000
Commitments and contingencies
Shareholders' equity
Common stock, no par, 240,000 shares authorized, 106,012 and 105,592 shares issued, respectively	$ 908,632	$ 906,957
Retained earnings	418,562	392,705
Accumulated other comprehensive loss	(47,510)	(39,058)
Total controlling interest shareholders' equity	1,279,684	1,260,604
Noncontrolling interests	25,808	25,040
Total equity	1,305,492	1,285,644
Total liabilities and shareholders' equity	$ 3,577,069	$ 3,592,020

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2011	Mar. 31, 2010
Net revenues:
Contracting services	$ 122,748	$ 110,855
Oil and gas	168,859	90,715
Total net revenues	291,607	201,570
Cost of sales:
Contracting services	106,907	86,248
Oil and gas	107,624	89,466
Total cost of sales	214,531	175,714
Gross profit	77,076	25,856
Gain on sale or acquisition of assets, net	16	6,247
Selling, general and administrative expenses	(24,981)	(40,501)
Income (loss) from operations	52,111	(8,398)
Equity in earnings of investments	5,650	5,055
Net interest expense	(24,236)	(15,635)
Other income (expense)	2,660	(5,585)
Income (loss) before income taxes	36,185	(24,563)
Provision (benefit) for income taxes	9,550	(7,561)
Net income (loss), including noncontrolling interests	26,635	(17,002)
Less net income applicable to noncontrolling interests	(768)	(829)
Net income (loss) applicable to Helix	25,867	(17,831)
Preferred stock dividends	(10)	(60)
Net income (loss) applicable to Helix common shareholders	$ 25,857	$ (17,891)
Earnings (loss) per share of common stock:
Basic	$ 0.24	$ (0.17)
Diluted	$ 0.24	$ (0.17)
Weighted average common shares outstanding:
Basic (in shares)	104,471	103,090
Diluted (in shares)	104,903	103,090

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2011	Mar. 31, 2010
Cash flows from operating activities:
Net income (loss), including noncontrolling interests	$ 26,635	$ (17,002)
Adjustments to reconcile net income (loss), including noncontrolling interests to net cash provided by operating activities
Depreciation and amortization	92,143	60,827
Asset impairment charge and dry hole expense	0	11,292
Amortization of deferred financing costs	1,981	1,726
Stock compensation expense	2,953	2,488
Amortization of debt discount	2,207	2,068
Deferred income taxes	9,329	(2,110)
Excess tax benefit from stock-based compensation	969	1,842
Gain on investment in Cal Dive common stock	(753)	0
Gain on sale or acquisition of assets	(16)	(6,247)
Unrealized (gain) loss on derivative contracts	(318)	3,001
Changes in operating assets and liabilities:
Accounts receivable, net	(381)	(23,823)
Other current assets	18,869	30,780
Income tax payable	(2,338)	(9,513)
Accounts payable and accrued liabilities	(58,747)	(22,027)
Oil and gas asset retirement costs	(8,160)	(12,541)
Other noncurrent, net	692	(2,324)
Net cash provided by operating activities	85,065	18,437
Cash flows from investing activities:
Capital expenditures	(34,488)	(68,428)
Distributions from equity investments, net	480	965
Proceeds from sale of Cal Dive common stock	3,588	0
Decrease (increase) in restricted cash	613	(4)
Net cash used in investing activities	(29,807)	(67,467)
Cash flows from financing activities
Repayment of Helix Term Loan	(1,082)	(1,082)
Repayment of MARAD borrowings	(2,294)	(2,403)
Loan notes repayment	(660)	(711)
Deferred financing costs	0	(2,789)
Preferred stock dividends paid	(10)	(60)
Repurchases of common stock	(927)	(976)
Excess tax benefit from stock-based compensation	(969)	(1,842)
Exercise of stock options, net	600	0
Net cash used in financing activities	(5,342)	(9,863)
Effect of exchange rate changes on cash and cash equivalents	(470)	398
Net increase (decrease) in cash and cash equivalents	49,446	(58,495)
Cash and cash equivalents:
Balance, beginning of year	391,085	270,673
Balance, end of year	$ 440,531	$ 212,178

Basis of Presentation	3 Months Ended
Basis of Presentation	Mar. 31, 2011
Notes To Financial Statements [Abstract]
Basis of Presentation	Note 1 – Basis of Presentation The accompanying condensed consolidated financial statements include the accounts of Helix Energy Solutions Group, Inc. and its majority-owned subsidiaries (collectively, "Helix" or the "Company"). Unless the context indicates otherwise, the terms "we," "us" and "our" in this report refer collectively to Helix and its majority-owned subsidiaries. All material intercompany accounts and transactions have been eliminated. These unaudited condensed consolidated financial statements have been prepared pursuant to instructions for the Quarterly Report on Form 10-Q required to be filed with the Securities and Exchange Commission (“SEC”), and do not include all information and footnotes normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles. The accompanying condensed consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles and are consistent in all material respects with those applied in our 2010 Annual Report on Form 10-K (“2010 Form 10-K”). The preparation of these financial statements requires us to make estimates and judgments that affect the amounts reported in the financial statements and the related disclosures. Actual results may differ from our estimates. Management has reflected all adjustments (which were normal recurring adjustments unless otherwise disclosed herein) that it believes are necessary for a fair presentation of the condensed consolidated balance sheets, results of operations, and cash flows, as applicable. The operating results for the three-month period ended March 31, 2011 are not necessarily indicative of the results that may be expected for the year ending December 31, 2011. Our balance sheet as of December 31, 2010 included herein has been derived from the audited balance sheet as of December 31, 2010 included in our 2010 Form 10-K. These unaudited condensed consolidated financial statements should be read in conjunction with the annual audited consolidated financial statements and notes thereto included in our 2010 Form 10-K. Certain reclassifications were made to previously reported amounts in the condensed consolidated financial statements and notes thereto to make them consistent with the current presentation format, including reclassifying the previously recorded results associated with our discontinued operations. The discontinued operations results are now reflected as a component of other income (expense) in the accompanying condensed consolidated statement of operations as such amounts are immaterial for all the periods presented in this Quarterly Report on Form 10-Q.

Company Overview	3 Months Ended
Company Overview	Mar. 31, 2011
Notes To Financial Statements [Abstract]
Company Overview	Note 2 – Company Overview We are an international offshore energy company that provides reservoir development solutions and other contracting services to the energy market as well as to our own oil and gas properties. Our Contracting Services segment utilizes our vessels, offshore equipment and methodologies to deliver services that may reduce finding and development costs and encompass the complete lifecycle of an offshore oil and gas field. Our Contracting Services are located primarily in Gulf of Mexico, North Sea, Asia Pacific and West Africa regions. Our Oil and Gas segment engages in exploration, development and production activities. Our oil and gas operations are exclusively located in the Gulf of Mexico. Contracting Services Operations We seek to provide services and methodologies which we believe are critical to finding and developing offshore reservoirs and maximizing production economics. Our “life of field” services are segregated into four disciplines: subsea construction, well operations, robotics and production facilities. We have disaggregated our contracting services operations into two reportable segments: Contracting Services and Production Facilities. Our Contracting Services business primarily includes subsea construction, deepwater pipelay, well operations and robotics activities. Our Production Facilities business includes our investments in Deepwater Gateway, L.L.C. (“Deepwater Gateway”) and Independence Hub, LLC (“Independence Hub”) as well as our majority ownership of the Helix Producer I (“HP I”) vessel. We recently developed a response system that may be utilized in future oil spill containment efforts in Gulf of Mexico (see “Events in Gulf of Mexico” below). Oil and Gas Operations We began our oil and gas operations to provide a more efficient solution to offshore abandonment, to expand our off-season utilization of our contracting services assets and to achieve incremental returns. We have evolved this business model to include not only mature oil and gas properties but also proved and unproved reserves yet to be developed and explored. This has led to the assembly of services that allows us to create value at key points in the life of a reservoir from exploration through development, life of field management and operating through abandonment. Business Strategy Over the past few years, we have focused on improving our balance sheet by increasing our liquidity through disposition of non-core business assets and reductions in our planned capital spending. At March 31, 2011, our cash on hand totaled $440.5 million and our liquidity was $836.7 million. Our capital expenditures for full year 2011 are expected to total approximately $250 million, which primarily reflects development of certain of our oil and gas properties (but is exclusive of expenditures related to our asset retirement obligations). We believe that we have sufficient liquidity to successfully implement our business plan in 2011 without incurring additional indebtedness beyond the existing capacity under the Revolving Credit Facility. In March 2010, we announced the engagement of advisors to assist us with evaluating potential alternatives for the disposition of our oil and gas business. Since that time, we have had intervening events, such as the Macondo well oil spill (discussed below in “Events in Gulf of Mexico”) and the subsequent regulatory effects associated with that event, which has resulted in a challenging environment for the sale of our entire oil and gas business. Furthermore, given the favorable commodity price environment and its positive impact on our financial condition, our focus has recently transitioned from a sale of our entire oil and gas business to building value through development of a number of our existing oil and gas properties. In 2011, our plan is to pursue development of a portion of our significant proved undeveloped reserves portfolio and to explore certain of our existing exploration prospects with a focus on crude oil prospects to generate higher cash flow. We will continue to evaluate the potential sale of properties as opportunities arise and may pursue those opportunities that we deem to be in our best interests in terms of economic returns and/or risk mitigation. Events in Gulf of Mexico In April 2010, an explosion occurred on the Deepwater Horizon drilling rig located on the site of the Macondo well at Mississippi Canyon Block 252. The resulting events included loss of life, the complete destruction of the drilling rig and an oil spill, the magnitude of which was unprecedented in U.S. territorial waters. In May 2010, the U.S. Department of Interior (“DOI”) announced a total moratorium on new drilling in the Gulf of Mexico. The drilling moratorium was partially lifted in late May 2010 (for drilling of prospects in less than 500 feet of water). In October 2010, the DOI lifted the drilling moratorium and instructed the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”) that it could resume issuing drilling permits conditioned on the requesting company’s compliance with all revised drilling, safety and environmental requirements. No deepwater drilling permits were issued in the period from October 2010 through late February 2011. In late February 2011, the BOEMRE commenced issuing deepwater permits. At the time of this filing 11 deepwater permits have been issued, six of which were issued using the Helix Fast Response System as further discussed below. We developed the Helix Fast Response System (“HFRS”) as a culmination of our experience as a responder in the Macondo oil spill response and containment efforts. The HFRS centers on two vessels, the HP I and the Q4000, both of which played a key role in the Macondo oil spill response and containment efforts and are presently operating in the Gulf of Mexico. In 2011, we signed an agreement with Clean Gulf Associates ("CGA"), a non-profit industry group, allowing, in exchange for a retainer fee, the HFRS to be named as a response resource in permit applications to federal and state agencies and making the HFRS available for a two-year term to certain CGA participants who have executed utilization agreements with us. In addition to the agreement with CGA, we currently have signed separate utilization agreements with 24 CGA participant member companies specifying the day rates to be charged should the HFRS solution be deployed in connection with a well control incident. The retainer fee for the HFRS became effective April 1, 2011 and will be a component of our Production Facilities business segment. A total of six permits have been granted to CGA participants for deepwater drilling operations identifying the HFRS to fulfill the BOERME requirement to have a spill response solution included in the submitted permit applications.

Oil and Gas Properties

3 Months Ended

Mar. 31, 2011

Oil and Gas Properties

Oil and Gas Properties

Note 4 – Oil and Gas Properties

We follow the successful efforts method of accounting for our interests in oil and gas properties. Under the successful efforts method, the costs of successful wells and leases containing productive reserves are capitalized. Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. Costs incurred relating to unsuccessful exploratory wells are charged to expense in the period in which the drilling is determined to be unsuccessful.

Depletion expense is determined on a field-by-field basis using the units-of-production method, with depletion rates for leasehold acquisition costs based on estimated total remaining proved reserves. Depletion rates for well and related facility costs are based on estimated total remaining proved developed reserves associated with each individual field. The depletion rates are changed whenever there is an indication of the need for a revision but, at a minimum, are evaluated annually. Any such revisions are accounted for prospectively as a change in accounting estimate.

Exploration and Other

As of March 31, 2011, we capitalized approximately $3.4 million of costs associated with ongoing exploration and/or appraisal activities. Such capitalized costs may be charged against earnings in future periods if management determines that commercial quantities of hydrocarbons have not been discovered or that future appraisal drilling or development activities are not likely to occur.

The following table details the components of exploration expense for the three months ended March 31, 2011 and 2010:

		Three Months Ended
		March 31,
		2011			2010
		(in thousands)
Delay rental and geological and geophysical costs	$	355		$	346
Dry hole expense		(9	)		(180	)
Total exploration expense	$	346		$	166

Impairments

No property impairments were recorded in the first quarter of 2011. In the first quarter of 2010, we recorded $7.0 million of impairment charges primarily resulting from natural gas price declines since year end 2009. The impairment charges affected three of our U.S. Gulf of Mexico properties that produce primarily natural gas. Separately, we also recorded a $4.1 million impairment charge for our only non-domestic oil and gas property (see “United Kingdom Property” below). Impairment expense is recorded as a component of depletion expense, which is reflected as cost of sales in the accompanying condensed consolidated statements of operations.

United Kingdom Property

Since 2006, we have maintained an ownership interest in the Camelot field, located offshore in the North Sea. In 2007, we sold half of our 100% working interest in Camelot to a third party with whom we agreed to jointly pursue future development and production of the field. In February 2010, we acquired this third party, including its $10.2 million of cash and thereby assumed the obligations, most notably the asset retirement obligation, related to its 50% working interest in the field. We recorded an approximate $6.0 million gain on the acquisition of the remaining working interest in Camelot (see Note 5 of 2010 Form 10-K).

Also in connection with this acquisition, we reassessed the fair value associated with our original 50% interest in the field. Based on these evaluations, it was concluded that Camelot was impaired based on the unlikely probability of our expending the additional capital necessary to further develop the field and our plans are to abandon the field in 2011 in accordance with applicable United Kingdom regulations. As a result, we recorded a $4.1 million impairment charge to fully impair the property in the first quarter of 2010.

Asset retirement obligations

The following table describes the changes in our asset retirement obligations (both long term and current) since December 31, 2010 (in thousands):

Asset retirement obligation at December 31, 2010	$	234,936
Liability incurred during the period		511
Liability settled during the period		(7,328	)
Revision in estimated cash flows		507
Accretion expense (included in depreciation and amortization)		3,786
Asset retirement obligations at March 31, 2011	$	232,412

Insurance

In September 2008, we sustained damage to certain of our oil and gas production facilities from Hurricanes Gustav and Ike. We carried comprehensive insurance on all of our operated and non-operated producing and non-producing properties. We record our hurricane-related costs as incurred. Insurance reimbursements are recorded when the realization of the claim for recovery of a loss is deemed probable. In the first quarter of 2011, we incurred $0.2 million of hurricane-related repair costs compared to $2.1 million in the first quarter of 2010. The first quarter of 2011 costs were offset by approved insurance reimbursements of $3.8 million. Expense related to our hurricane catastrophic bond windstorm coverage was immaterial for all periods presented in this Quarterly Report on Form 10-Q. See Note 4 of our 2010 Form 10-K for information regarding our settlement with the insurance underwriters in June 2009.

Equity Investments

3 Months Ended

Mar. 31, 2011

Notes To Financial Statements [Abstract]

Equity Investments

Note 6 – Equity Investments

As of March 31, 2011, we have three investments that we account for using the equity method of accounting: Deepwater Gateway, Independence Hub, and the Clough Helix Joint Venture Pty Ltd. (“Clough Helix JV”). Deepwater Gateway and Independence Hub are included in our Production Facilities segment while the Clough Helix joint venture is a component of our Contracting Services segment.

Deepwater Gateway, L.L.C. In June 2002, we, along with Enterprise Products Partners L.P. (”Enterprise”), formed Deepwater Gateway, each with a 50% interest, to design, construct, install, own and operate a tension leg platform (“TLP”) production hub primarily for Anadarko Petroleum Corporation's Marco Polo field in the Deepwater Gulf of Mexico. Our investment in Deepwater Gateway totaled $99.0 million and $99.8 million as of March 31, 2011 and December 31, 2010, respectively (including capitalized interest of $1.5 million at both March 31, 2011 and December 31, 2010). Our net distributions from Deepwater Gateway totaled $1.8 million in the first quarter of 2011.

Independence Hub, LLC. In December 2004, we acquired a 20% interest in Independence Hub, an affiliate of Enterprise. Independence Hub owns the "Independence Hub" platform located in Mississippi Canyon Block 920 in a water depth of 8,000 feet. First production through the facility commenced in July 2007. Our investment in Independence Hub was $82.1 million and $82.4 million as of March 31, 2011 and December 31, 2010, respectively (including capitalized interest of $5.2 million at March 31, 2011 and December 31, 2010). Our net distributions from Independence Hub totaled $4.4 million in the first quarter of 2011.

Clough Helix JV. In February 2010, we announced the formation of the Clough Helix JV with Australian-based engineering and construction company, Clough Projects Australia Pty Ltd (“Clough”), to provide a range of subsea services to offshore operators in the Asia Pacific region. The Clough Helix JV combines our well intervention equipment with Clough’s 12-man saturation diving system, which are deployed from the 118 meter long DP2 multiservice vessel, Normand Clough. In the first quarter of 2011, the Clough Helix JV commenced an approximate six to nine month day rate project located offshore China. Our 50% share of the earnings from the Clough Helix JV totaled $0.4 million for the three-month period ended March 31, 2011 as compared to a $1.4 million loss in the first quarter of 2010. The loss in the first quarter of 2010 primarily represented the mobilization costs of transporting the Normand Clough from the Gulf of Mexico to Singapore. Our investment in the Clough Helix JV was $5.7 million at March 31, 2011 and $4.9 million at December 31, 2010.

Long-Term Debt

3 Months Ended

Mar. 31, 2011

Notes To Financial Statements [Abstract]

Long-Term Debt

Note 7 – Long-Term Debt

Scheduled maturities of long-term debt and capital lease obligations outstanding as of March 31, 2011 were as follows (in thousands):

		Helix Term Loan			Helix Revolving Loans		Senior Unsecured Notes		Convertible Senior Notes (1)			MARAD Debt			Other(2)			Total

Less than one year	$	4,326		$	─	$	─	$	─		$	4,759		$	553		$	9,638
One to two years		4,326			─		─		─			4,997			─			9,323
Two to three years		400,707			─		─		─			5,247			─			405,954
Three to four years		─			─		─		─			5,508			─			5,508
Four to five years		─			─		550,000		─			5,783			─			555,783
Over five years		─			─		─		300,000			86,222			─			386,222
Total debt		409,359			─		550,000		300,000			112,516			553			1,372,428
Current maturities		(4,326	)		─		─		─			(4,759	)		(553	)		(9,638	)
Long-term debt, less current maturities	$	405,033		$	─	$	550,000	$	300,000		$	107,757		$	─		$	1,362,790
Unamortized debt discount (3)		─			─		─		(16,321	)		─			─			(16,321	)
Long-term debt	$	405,033		$	─	$	550,000	$	283,679		$	107,757		$	─		$	1,346,469

(1)	Beginning in December 2012, the holders may require us to repurchase the notes or we may at our own option elect to repurchase notes. Notes will mature in March 2025.

(2)	Represents the balance of the loan provided by Kommandor RØMØ to Kommandor LLC as of March 31, 2011.

(3)	The notes will increase to the $300 million face amount through accretion of non-cash interest charges through 2012.

At March 31, 2011, unsecured letters of credit issued totaled approximately $38.8 million (see “Credit Agreement” below). These letters of credit primarily guarantee various contract bidding, contractual performance, including asset retirement obligations, and insurance activities. The following table details our interest expense and capitalized interest for the three-month periods ended March 31, 2011 and 2010:

		Three Months Ended
		March 31,
		2011			2010
		(in thousands)
Interest expense	$	24,767		$	24,349
Interest income		(476	)		(198	)
Capitalized interest		(55	)		(8,516	)
Interest expense, net	$	24,236		$	15,635

Included below is a summary of certain components of our indebtedness. We were in compliance with all debt covenants and restrictions at March 31, 2011 and December 31, 2010. For additional information regarding our debt see Note 9 of our 2010 Form 10-K.

Senior Unsecured Notes

In December 2007, we issued $550 million of 9.5% Senior Unsecured Notes due 2016 (“Senior Unsecured Notes”). Interest on the Senior Unsecured Notes is payable semiannually in arrears on each January 15 and July 15, commencing July 15, 2008. The Senior Unsecured Notes are fully and unconditionally guaranteed by substantially all of our existing restricted domestic subsidiaries, except for Cal Dive I-Title XI, Inc. In addition, any future restricted domestic subsidiaries that guarantee any of our indebtedness and/or our restricted subsidiaries’ indebtedness are required to guarantee the Senior Unsecured Notes. Our foreign subsidiaries are not guarantors. We used the proceeds from the Senior Unsecured Notes to repay outstanding indebtedness under our Credit Agreement (see below).

Credit Agreement

In July 2006, we entered into a credit agreement (the “Credit Agreement”) under which we borrowed $835 million in a term loan (the “Term Loan”) and were initially able to borrow up to $300 million (the “Revolving Loans”) under a revolving credit facility (the “Revolving Credit Facility”). The Credit Agreement has been amended three times, most recently in February 2010, to address certain issues with regard to covenants, maturity and the borrowing limits under the Revolving Credit Facility. For additional information regarding the current terms of our credit facility see Note 9 of our 2010 Form 10-K.

The proceeds from the Term Loan were used to fund the cash portion of the acquisition of Remington Oil and Gas Corporation in July 2006. The Term Loan currently bears interest either at the one-, three- or six-month LIBOR at our election plus a margin of between 2.25% and 2.5% depending on current leverage ratios. Our average interest rate on the Term Loan for the three-month periods ended March 31, 2011 and 2010 was approximately 3.0% and 2.8%, respectively, including the effects of our interest rate swaps (Note 16). The Term Loan is currently scheduled to mature on July 1, 2013.

The original maturity date of the Revolving Credit Facility was July 1, 2011. In the fourth quarter of 2009, we increased the Revolving Credit Facility and extended its maturity date to November 30, 2012. As a consequence of the foregoing, the borrowing limit under the Revolving Credit Facility was increased by amendment to $435 million, effective December 31, 2009. This limit will decrease to $410 million beginning July 1, 2011 and will stay at that level through the maturity of the Revolving Credit Facility on November 30, 2012. The full amount of the Revolving Credit Facility may be used for issuances of letters of credit. At March 31, 2011, we had no amounts drawn on the Revolving Credit Facility and our availability under the Revolving Credit Facility totaled $396.2 million, net of $38.8 million of letters of credit issued.

The Revolving Loans bear interest based on one-, three- or six-month LIBOR rates or on Base Rates at our election plus an applicable margin. The margin ranges from 1.0% to 4.5%, depending on our consolidated leverage ratio. We have not borrowed any amounts under the Revolving Loans since we repaid the outstanding amount in the second quarter of 2009.

The Credit Agreement contains various covenants regarding, among other things, collateral, capital expenditures, investments, dispositions, indebtedness and financial performance that are customary for this type of financing and for companies in our industry.

As the rates for our Term Loan are subject to market influences and will vary over the term of the Credit Agreement, we may enter into various cash flow hedging interest rate swaps to stabilize cash flows relating to a portion of our interest payments for our Term Loan. In January 2010, we entered into $200 million, two-year interest rate swaps to stabilize cash flows relating to a portion of our interest payments on our Term Loan (Note 16).

Convertible Senior Notes

In March 2005, we issued $300 million of our Convertible Senior Notes at 100% of the principal amount to certain qualified institutional buyers. The Convertible Senior Notes are convertible into cash and, if applicable, shares of our common stock based on the specified conversion rate, subject to adjustment.

The Convertible Senior Notes can be converted prior to the stated maturity (March 2025) under certain triggering events specified in the indenture governing the Convertible Senior Notes. To the extent we do not have long-term financing secured to cover the conversion, the Convertible Senior Notes would be classified as a current liability in the accompanying condensed consolidated balance sheet. No conversion triggers were met during the three-month period ended March 31, 2011. The first dates for early redemption of the Convertible Senior Notes are in December 2012, with the holders of the Convertible Senior Notes being able to put them to us on December 15, 2012 and our being able to call the Convertible Senior Notes at any time after December 20, 2012 (see Note 9 of our 2010 Form 10-K). Effective January 1, 2009 we adopted certain new required accounting standards that required us to discount the principal amount of our Convertible Senior Notes. Following adoption of these accounting standards, the effective interest rate for the Convertible Senior Notes is 6.6%.

Our average share price for the both the first quarter of 2011 and 2010 was below the $32.14 per share conversion price. As a result of our share price being lower than the $32.14 per share conversion price for these periods there are no shares included in our diluted earnings per share calculation associated with the assumed conversion of our Convertible Senior Notes. In the event our average share price exceeds the conversion price, there would be a premium, payable in shares of common stock, in addition to the principal amount, which is paid in cash, and such shares would be issued on conversion. The Convertible Senior Notes are convertible into a maximum 13,303,770 shares of our common stock.

MARAD Debt

This U.S. government guaranteed financing ("MARAD Debt") is pursuant to Title XI of the Merchant Marine Act of 1936 which is administered by the Maritime Administration, and was used to finance the construction of the Q4000. The MARAD Debt is payable in equal semi-annual installments beginning in August 2002 and matures 25 years from such date. The MARAD Debt is collateralized by the Q4000, with us guaranteeing 50% of the debt, and initially bore interest at a floating rate which approximated AAA Commercial Paper yields plus 20 basis points. As provided for in the MARAD Debt agreements, in September 2005, we fixed the interest rate on the debt through the issuance of a 4.93% fixed-rate note with the same maturity date (February 2027).

Other

In accordance with our Credit Agreement and our Senior Unsecured Notes, Convertible Senior Notes and MARAD Debt agreements, we are required to comply with certain covenants, including the maintenance of minimum net worth, working capital and debt-to-equity requirements, and restrictions that limit our ability to incur certain types of additional indebtedness. As of March 31, 2011, we were in compliance with these covenants and restrictions.

Deferred financing costs of $23.8 million and $25.7 million are included in other assets, net as of March 31, 2011 and December 31, 2010, respectively, and are being amortized over the life of the respective loan agreements.

Earnings Per Share

3 Months Ended

Mar. 31, 2011

Notes To Financial Statements [Abstract]

Earnings Per Share

Note 10 – Earnings Per Share

We have shares of restricted stock issued and outstanding, some of which remain subject to certain vesting requirements. Holders of such shares of unvested restricted stock are entitled to the same liquidation and dividend rights as the holders of our outstanding common stock and are thus considered participating securities. Under applicable accounting guidance, the undistributed earnings for each period are allocated based on the participation rights of both the common shareholders and holders of any participating securities as if earnings for the respective periods had been distributed. Because both the liquidation and dividend rights are identical, the undistributed earnings are allocated on a proportionate basis. Further, we are required to compute earnings per share (“EPS”) amounts under the two class method in periods in which we have earnings from continuing operations. For periods in which we have a net loss we do not use the two class method as holders of our restricted shares are not contractually obligated to share in such losses.

The presentation of basic EPS amounts on the face of the accompanying condensed consolidated statements of operations is computed by dividing the net income available to common shareholders by the weighted average shares of outstanding common stock. The calculation of diluted EPS is similar to basic EPS, except that the denominator includes dilutive common stock equivalents and the income included in the numerator excludes the effects of the impact of dilutive common stock equivalents, if any. The computations of the numerator (Income) and denominator (Shares) to derive the basic and diluted EPS amounts presented on the face of the accompanying condensed consolidated statements of operations are as follows (in thousands):

		Three Months Ended				Three Months Ended
		March 31, 2011				March 31, 2010
		Income		Shares		Income		Shares
Basic:
Net income (loss) applicable to common shareholders	$	25,857			$	(17,891	)
Less: Undistributed net income allocable to participating securities		(338	)			─
Net income (loss) applicable to common shareholders	$	25,519		104,471	$	(17,891	)	103,090

		Three Months Ended March 31, 2011			Three Months Ended March 31, 2010
		Three Months Ended March 31, 2011			Three Months Ended March 31, 2010
		Income	Shares		Income		Shares
Diluted:
Net income (loss) per common share - Basic	$	25,519	104,471	$	(17,891	)	103,090
Effect of dilutive securities:
Stock options		─	71		─		─
Undistributed earnings reallocated to participating securities		1	─
Convertible Senior Notes		─	─		─		─
Convertible preferred stock		10	361		─		─
Net income (loss) per common share - Diluted	$	25,530	104,903	$	(17,891	)	103,090

We had a net loss from continuing operations during the three-month period ended March 31, 2010. Accordingly, we had no dilutive securities during this reporting period as their inclusion would have an anti-dilutive effect on our EPS calculation, meaning it would increase our reported EPS amount. The following table provides the effect the excluded securities would have had on our diluted shares calculation for the three-month period ended March 31, 2010 assuming we had earnings from continuing operations (in thousands):

Diluted shares (as reported)			103,090
Stock options			194
Convertible preferred stock			2,168
Total			105,452

Stock-Based Compensation Plans

3 Months Ended

Mar. 31, 2011

Notes To Financial Statements [Abstract]

Stock-Based Compensation Plans

Note 11 – Stock-Based Compensation Plans

We have two stock-based compensation plans: the 1995 Long-Term Incentive Plan, as amended (the “1995 Incentive Plan”) and the 2005 Long-Term Incentive Plan, as amended (the “2005 Incentive Plan”). As of March 31, 2011, there were 892,573 million shares available for grant under our 2005 Incentive Plan.

There were no stock option grants in the three-month periods ended March 31, 2011 and 2010.

During the three-month period ended March 31, 2011, we made the following restricted share grants to executive officers, selected management employees and non-employee members of the board of directors under the 2005 incentive plan:

Date of Grant	Shares		Market Value Per Share		Vesting Period

January 4, 2011		475,804	$	12.14	20% per year over five years
January 4, 2011		4,427		12.14	100% on January 1, 2013

Compensation cost is recognized over the respective vesting periods on a straight-line basis. For the three-month period ended March 31, 2011, $3.0 million was recognized as compensation expense related to restricted shares as compared with $2.5 million during the three-month period ended March 31, 2010.

In January 2009, we adopted the 2009 Long-Term Incentive Cash Plan (the “2009 LTI Plan”) to provide long term cash based compensation to eligible employees. Under the terms of the 2009 LTI Plan, the majority of the cash awards are fixed sum amounts payable over a five year vesting period. However, some of the cash awards are indexed to our Company common stock and the payment amount at each vesting date will fluctuate based on the common stock’s performance. This share-based component is considered a liability plan and as such is re-measured to fair value each reporting period with corresponding changes being recorded as a charge to earnings as appropriate.

The total awards made under the 2009 LTI Plan totaled $10.2 million in 2010 and $4.0 million in 2011. These grant amounts include $6.0 million in 2010 and the entire grant in 2011 that is deemed to be within the liability plan component of the 2009 LTI Plan. Total compensation expense under the 2009 LTI plan totaled $3.0 million and $1.9 million for the three-month periods ended March 31, 2011 and 2010, respectively.

For more information regarding our stock-based compensation plans, including our 2009 LTI Plan see Note 12 of our 2010 Form 10-K.

Business Segment Information

3 Months Ended

Mar. 31, 2011

Notes To Financial Statements [Abstract]

Business Segment Information (in thousands)

Note 12 – Business Segment Information

Our operations are conducted through the following lines of business: contracting services and oil and gas. We have disaggregated our contracting services operations into two reportable segments. As a result, our reportable segments consisted of the following: Contracting Services, Production Facilities and Oil and Gas. Contracting Services operations include subsea construction, deepwater pipelay, well operations and robotics. The Production Facilities segment includes our consolidated investment in the HP I and Kommandor LLC as well as our equity investments in Deepwater Gateway and Independence Hub that are accounted for under the equity method of accounting.

We evaluate our performance based on income before income taxes of each segment. Segment assets are comprised of all assets attributable to the reportable segment. All material intercompany transactions between the segments have been eliminated.

		Three Months Ended
		March 31,
		2011			2010
		(in thousands)
Revenues ─
Contracting Services	$	131,537		$	154,200
Production Facilities		15,570			1,320
Oil and Gas		168,859			90,715
Intercompany elimination		(24,359	)		(44,665	)
Total	$	291,607		$	201,570

		Three Months Ended
		March 31,
		2011			2010
		(in thousands)
Income (loss) from operations ─
Contracting Services	$	3,266		$	27,486
Production Facilities(1)		5,956			(37	)
Oil and Gas		53,240			(664	)
Corporate (2)		(10,441	)		(22,878	)
Intercompany elimination		90			(12,305	)
Total	$	52,111		$	(8,398	)

Equity in earnings of equity investments	$	5,650		$	5,055

(1)

In April 2009, Kommandor LLC commenced leasing the HP I to us under terms of a charter arrangement following the completion of the initial conversion of the vessel (Note 8 of our 2010 Form 10-K). The HP I was certified as a floating oil and gas production unit in June 2010 following the completion of installation of oil and gas processing facilities on the vessel.

(2)	Includes $13.8 million settlement of third party claim against us in March 2010 (Note 14).

	March 31, 2011		December 31, 2010
		(in thousands)
Identifiable Assets ─
Contracting Services	$	1,853,349	$	1,856,016
Production Facilities		514,086		512,990
Oil and Gas		1,209,634		1,223,014
Total	$	3,577,069	$	3,592,020

Intercompany segment revenues during the three-month periods ended March 31, 2011 and 2010 were as follows:

		Three Months Ended
		March 31,
		2011		2010
		(in thousands)
Contracting Services	$	12,869	$	43,741
Production Facilities		11,490		924
Total	$	24,359	$	44,665

Intercompany segment profits during the three-month periods ended March 31, 2011 and 2010 were as follows:

		Three Months Ended
		March 31,
		2011			2010
		(in thousands)
Contracting Services	$	(24	)	$	11,442
Production Facilities		(66	)		880
Total	$	(90	)	$	12,322

Commitments and Contingencies	3 Months Ended
Commitments and Contingencies	Mar. 31, 2011
Notes To Financial Statements [Abstract]
Commitments and Contingencies	Note 14 – Commitments and Contingencies Litigation and Claims In March 2009, we were notified of a third party’s intention to terminate an international construction contract with one of our subsidiaries based on a claimed breach of that contract. Under the terms of the contract, our potential liability was generally capped for actual damages at approximately $32 million Australian dollars (“AUD”). We asserted a counterclaim that in the aggregate approximated $12 million U.S. dollars. On March 30, 2010, an out of court settlement of these claims was reached. On April 19, 2010, pursuant to the terms of the settlement, we paid the third party $15 million AUD to settle all its damage claims against us. We also agreed not to seek any further payment of our counter claims against them. Our results for the three-month period ended March 31, 2010 included approximately $17.5 million in expenses associated with this settlement agreement, including $13.8 million for the litigation settlement payment and $3.7 million to write off our remaining trade receivable from the third party. These amounts were recorded as selling, general and administrative expenses in the accompanying condensed consolidated statements of operations. Loss Contract As discussed in Note 16 of the 2010 Form 10-K, in 2010 our Australian subsidiary contracted for a project to plug, abandon and salvage subsea wells in an oil and gas field located offshore China. As previously reported as of the year ended December 31, 2010, we had recorded an aggregate pre-tax loss of approximately $30 million related to this project which reflected the difficulty we had in plugging the wells because of certain structural issues, start-up issues with our recently repaired subsea intervention device and significant weather related delays. In the first quarter of 2011, this project ended and we recorded an additional pre-tax loss of approximately $0.2 million. Our remaining trade receivable related to this project is $6.7 million. We believe this amount is collectable, however, if we are unable to collect any of this amount any variance would increase the recorded loss for the project. Contingencies and Claims We were subcontracted to perform development work for a large gas field offshore India. Work commenced in the fourth quarter of 2007 and we completed our scope of work in the third quarter of 2009. To date we have collected approximately $303 million related to this project with an amount of trade receivables and claims yet to be collected. We have requested arbitration in India pursuant to the terms of the subcontract to pursue our claims and the prime contractor has also requested arbitration and has asserted certain counterclaims against us. If we are not successful in resolving these matters through ongoing discussions with the prime contractor, then arbitration in India remains a potential remedy. Based on number of factors associated with the ongoing negotiations with the prime contractor, in 2010 we established an allowance against our trade receivable balance that reduces its balance to an amount we believe is ultimately realizable (see Notes 16 and 18 of our 2010 Form 10-K). However, at the time of this filing no final commercial resolution of this matter has been reached. We have received value added tax (VAT) assessments from the State of Andhra Pradesh, India (the “State”) in the amount of approximately $28 million related to our subsea and diving contract entered into in December 2006 in India for the tax years 2007, 2008, 2009, and 2010. The State claims we owe unpaid taxes related to products consumed by us during the period of the contract. We are of the opinion that the State has arbitrarily assessed this VAT tax and has no foundation for the assessment and believe that we have complied with all rules and regulations as it relates to VAT in the State. We also believe that our position is supported by law and intend to vigorously defend our position. However, the ultimate outcome of this assessment and our potential liability from it, if any, cannot be determined at this time. If the current assessment is upheld, it may have a material negative effect on our consolidated results of operations while also impacting our financial position. We are involved in various legal proceedings, primarily involving claims for personal injury under the General Maritime Laws of the United States and the Jones Act based on alleged negligence. In addition, from time to time we incur other claims, such as contract disputes, in the normal course of business.

Fair Value Measurements and Recent Accounting Standards

3 Months Ended

Mar. 31, 2011

Notes To Financial Statements [Abstract]

Fair Value Measurements and Recent Accounting Standards

Note 15 – Fair Value Measurements and Recent Accounting Standards

Fair Value Measurements

Certain of our financial assets and liabilities are measured and reported at fair value on a recurring basis as required under applicable accounting requirements. These requirements establish a hierarchy for inputs used in measuring fair value. The fair value is to be calculated based on assumptions that market participants would use in pricing assets and liabilities and not on assumptions specific to the entity. The statement requires that each asset and liability carried at fair value be classified into one of the following categories:

•		Level 1. Observable inputs such as quoted prices in active markets;
•		Level 2. Inputs, other than the quoted prices in active markets, that are observable either directly or indirectly; and
•		Level 3. Unobservable inputs in which there is little or no market data, which require the reporting entity to develop its own assumptions.

Assets and liabilities measured at fair value are based on one or more of three valuation techniques as follows:

(a)	Market Approach. Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.

(b)	Cost Approach. Amount that would be required to replace the service capacity of an asset (replacement cost).

(c)	Income Approach. Techniques to convert expected future cash flows to a single present amount based on market expectations (including present value techniques, option-pricing and excess earnings models).

The following table provides additional information related to assets and liabilities measured at fair value on a recurring basis at March 31, 2011 (in thousands):

		Level 1		Level 2 (1)		Level 3		Total	Valuation Technique

Assets:
Natural gas contracts	$	–	$	2,983	$	–	$	2,983	(c)
Foreign currency forwards		–		584		–		584	(c)

Liabilities:
Oil contracts		–		43,481		–		43,481	(c)
Fair value of long term debt(2)		1,289,897		118,254		–		1,408,151	(a), (b)
Natural gas contracts		–		529		–		529	(c)
Interest rate swaps		–		1,541		–		1,541	(c)
Total net liability	$	1,289,897	$	160,238	$	–	$	1,450,135

(1)

Unless otherwise indicated, the fair value of our Level 2 derivative instruments reflects our best estimate and is based upon exchange or over-the-counter quotations whenever they are available. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, we utilize other valuation techniques or models to estimate market values. These modeling techniques require us to make estimations of future prices, price correlation and market volatility and liquidity. Our actual results may differ from our estimates, and these differences can be positive or negative.

(2)	See Note 7 for additional information regarding our long term debt. The fair value of our long term debt at March 31, 2011 is as follows:

	Fair Value		Carrying Value
Term Loan (matures July 2013)	$	407,599	$	409,359
Revolving Credit Facility (matures November 2012)	─		─
Convertible Senior Notes (matures March 2025)		300,120		283,679
Senior Unsecured Notes (matures January 2016)		581,625		550,000
MARAD Debt (matures February 2027) (a)		118,254		112,516
Loan Notes(b)		553		553
Total	$	1,408,151	$	1,356,107

(a)

The estimated fair value of all debt, other than MARAD Debt and Loan Notes, was determined using level 1 inputs using the market approach. The fair value of the MARAD debt was determined using a third party evaluation of the remaining average life and outstanding principal balance of the MARAD indebtedness as compared to other governmental obligations in the market place with similar terms. The fair value of the MARAD debt was estimated using level 2 fair value inputs using the cost approach.

(b)	The carrying value of the loan notes approximates fair value as the maturity of the notes is current.

We review long lived assets for impairment whenever events occur or changes in circumstances indicate that the carrying amount of assets may not be recoverable. In such evaluation, the estimated future undiscounted cash flows to be generated by the asset are compared with the carrying value of the asset to determine if an impairment may be required. For our oil and gas properties, the estimated future undiscounted cash flows are based on estimated crude oil and natural gas proved and probable reserves and published future market commodity prices, estimated operating costs and estimates of future capital expenditures. If the estimated undiscounted cash flows for a particular asset are not sufficient to cover the carrying value of the asset the asset is impaired and its carrying value is reduced to the current fair value. The fair value of these assets is determined using an income approach by calculating present value of future cash flows attributable to the asset based on market information (such as forward commodity prices), estimates of future costs and estimated proved and probable reserve quantities. These fair value measurements fall within Level 3 of the fair value hierarchy. In the first quarter of 2010, we impaired three of our natural gas producing properties following a significant drop in natural gas prices during the period (Note 4). The total amount of the impairment charges were $7.0 million, which reduced these properties to their then aggregate fair value of $28.2 million.

Derivative Instruments and Hedging Activities

3 Months Ended

Mar. 31, 2011

Notes To Financial Statements [Abstract]

Derivative Instruments and Hedging Activities

Note 16 – Derivative Instruments and Hedging Activities

We are currently exposed to market risk in three major areas: commodity prices, interest rates and foreign currency exchange rates. Our risk management activities involve the use of derivative financial instruments to hedge the impact of market price risk exposures primarily related to our oil and gas production, variable interest rate exposure and foreign exchange currency fluctuations. All derivatives are reflected in the accompanying condensed consolidated balance sheets at fair value unless otherwise noted.

We engage solely in cash flow hedges. Hedges of cash flow exposure are entered into to hedge a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability. Changes in the derivative fair values that are designated as cash flow hedges are deferred to the extent that they are effective and are recorded as a component of accumulated other comprehensive income (loss), a component of shareholders’ equity, until the hedged transactions occur and are recognized in earnings. The ineffective portion of a cash flow hedge’s change in fair value is recognized immediately in earnings. In addition, any change in the fair value of a derivative that does not qualify for hedge accounting is recorded in earnings in the period in which the change occurs.

For additional information regarding our accounting for derivatives see Notes 2 and 20 of our 2010 Form 10-K.

Commodity Price Risks

We currently manage commodity price risk through various financial costless collars and swap instruments covering a portion of our anticipated oil and natural gas production for 2011 and 2012. All of our current commodity derivative contracts qualify for hedge accounting.

As of March 31, 2011, we have the following volumes under derivative contracts related to our oil and gas producing activities totaling approximately 1.8 MMBbl of oil and 10.4 Bcf of natural gas:

Production Period	Instrument Type	Average Monthly Volumes	Weighted Average Price
Crude Oil:			(per barrel)
April 2011 — December 2011	Swap	192.2 MBbl	$82.35
April 2011 — December 2011	Collar	11.1 MBbl	$95.00 - $124.00

Natural Gas:			(per Mcf)
April 2011 — December 2011	Swap	825 Mmcf	$4.99
January 2012 — December 2012	Swap	250 Mmcf	$4.77

In April 2011, we entered into four additional costless collar financial hedging agreements. The first contract covers a total of 250 MBbls of oil over the second half of 2011 with a floor price of $95.00 and a ceiling price of $124.89. The second and third contracts cover a total 600 MBbls of oil with a floor price of $95.00 and an average ceiling price $117.10 from January to December 2012. The fourth contract covers 1 Bcf of natural gas with a floor price of $4.75 and a ceiling price of $5.28 from January to December 2012.

Changes in NYMEX oil and gas strip prices would, assuming all other things being equal, cause the fair value of these instruments to increase or decrease inversely to the change in NYMEX prices.

Variable Interest Rate Risks

As some of our long-term debt is subject to market influences and has variable interest rates, in January 2010 we entered into various interest rate swaps to stabilize cash flows relating to interest payments for $200 million of our Term Loan debt under our Credit Agreement (Note 7). These monthly contracts will mature in January 2012. Changes in the interest rate swap fair value are deferred to the extent the swap is effective and are recorded as a component of accumulated other comprehensive income (loss) until the anticipated interest payments occur and are recognized in interest expense. The ineffective portion of the interest rate swap, if any, will be recognized immediately in earnings within the line titled net interest expense.

Foreign Currency Exchange Risks

Because we operate in various regions in the world, we conduct a portion of our business in currencies other than the U.S. dollar. We entered into various foreign currency forwards to stabilize expected cash outflows relating to certain vessel charters denominated in British pounds. The last of our existing monthly foreign currency swap contracts will settle in June 2012.

Quantitative Disclosures Related to Derivative Instruments

The following tables present the fair value and balance sheet classification of our derivative instruments as of March 31, 2011 and December 31, 2010. The fair value amounts below are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements.

Derivatives designated as hedging instruments are as follows:

	As of March 31, 2011			As of December 31, 2010
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
	(in thousands)
Asset Derivatives:
Natural gas contracts	Other current assets	$	2,983	Other current assets	$	5,324
		$	2,983		$	5,324

	As of March 31, 2011			As of December 31, 2010
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
	(in thousands)
Liability Derivatives:
Oil contracts	Accrued liabilities	$	43,481	Accrued liabilities	$	28,855
Interest rate swaps	Accrued liabilities		1,541	Accrued liabilities		1,751
Gas contracts	Other long-term liabilities		529	Accrued liabilities		913
Interest rate swaps	Other long-term liabilities		—	Accrued liabilities		115
		$	45,551		$	31,634

Derivatives that were not designated as hedging instruments (in thousands):

	As of March 31, 2011			As of December 31, 2010
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
	(in thousands)
Asset Derivatives:
Foreign exchange forwards	Other current assets	$	483	Other current assets	$	148
Foreign exchange forwards	Other assets, net		101	Other assets, net		42
		$	584		$	190

Liability Derivatives:		$	—		$	—

The following tables present the impact that derivative instruments designated as cash flow hedges had on our accumulated comprehensive income (loss) and our consolidated statements of operations for the three-month periods ended March 31, 2011 and 2010. Most of our unrealized gains (losses) related to our derivatives are expected to be reclassified into earnings within the next 12 months; however, we do have some contracts that extend into 2012 (as discussed above).

		Gain (Loss) Recognized in Accumulated OCI on Derivatives
		2011			2010
		(in thousands)
Oil and natural gas commodity contracts	$	(10,778	)	$	14,630
Foreign exchange forwards		—			—
Interest rate swaps		211			(590	)
	$	(10,567	)	$	14,040

	Location of Gain (Loss) Reclassified from Accumulated OCI into Income		Gain (Loss) Recognized from Accumulated OCI into Income
			2011			2010
			(in thousands)
Oil and natural gas commodity contracts	Oil and gas revenue	$	(6,325	)	$	802
Interest rate swaps	Net interest expense		(480	)		(418	)
		$	(6,805	)	$	384

The following tables present the impact that derivative instruments not designated as hedges had on our condensed consolidated income statement for the three months ended March 31, 2011 and 2010:

	Location of Gain (Loss) Recognized in Income on Derivatives		Gain (Loss) Recognized in Income on Derivatives
	Location of Gain (Loss) Recognized in Income on Derivatives		2011		2010
			(in thousands)
Foreign exchange forwards	Other expense	$	608	$	(2,907	)
		$	608	$	(2,907	)

Condensed Consolidated Guarantor and Non-Guarantor Financial Information

3 Months Ended

Mar. 31, 2011

Notes To Financial Statements [Abstract]

Condensed Consolidated Guarantor and Non-Guarantor Financial Information

Note 17 – Condensed Consolidated Guarantor and Non-Guarantor Financial Information

The payment of our obligations under the Senior Unsecured Notes is guaranteed by all of our restricted domestic subsidiaries (“Subsidiary Guarantors”) except for Cal Dive I-Title XI, Inc. Each of these Subsidiary Guarantors is included in our consolidated financial statements and has fully and unconditionally guaranteed the Senior Unsecured Notes on a joint and several basis. As a result of these guaranty arrangements, we are required to present the following condensed consolidating financial information. The accompanying guarantor financial information is presented on the equity method of accounting for all periods presented. Under this method, investments in subsidiaries are recorded at cost and adjusted for our share in the subsidiaries’ cumulative results of operations, capital contributions and distributions and other changes in equity. Elimination entries related primarily to the elimination of investments in subsidiaries and associated intercompany balances and transactions.

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(in thousands)

(Unaudited)

	As of March 31, 2011
		Helix		Guarantors		Non-Guarantors			Consolidating Entries			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	425,514	$	2,473	$	12,544		$	—		$	440,531
Accounts receivable, net		62,735		106,559		21,565			—			190,859
Unbilled revenue		1,547		—		20,846			—			22,393
Income taxes receivable		46,442		—		12,167			(51,112	)		7,497
Other current assets		44,066		56,385		10,268			(4,387	)		106,332
Total current assets		580,304		165,417		77,390			(55,499	)		767,612
Intercompany		4,447		287,466		(188,963	)		(102,950	)		—
Property and equipment, net		219,598		1,565,045		709,591			(5,013	)		2,489,221
Other assets:
Equity investments in unconsolidated affiliates		—		—		186,831			—			186,831
Equity investments		1,954,489		24,237		—			(1,978,726	)		—
Goodwill		—		45,107		17,849			—			62,956
Other assets, net		42,135		37,198		20,808			(29,692	)		70,449
Due from subsidiaries/parent		90,965		184,967		—			(275,932	)		—
	$	2,891,938	$	2,309,437	$	823,506		$	(2,447,812	)	$	3,577,069

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	33,137	$	69,424	$	23,803		$	—		$	126,364
Accrued liabilities		45,094		124,574		29,811			—			199,479
Income taxes payable		—		67,543		—			(67,543	)		—
Current maturities of long-term debt		4,326		—		9,169			(3,857	)		9,638
Total current liabilities		82,557		261,541		62,783			(71,400	)		335,481
Long-term debt		1,238,712		—		107,757			—			1,346,469
Deferred income taxes		199,200		124,072		97,964			(5,924	)		415,312
Asset retirement obligations		—		168,014		—			—			168,014
Other long-term liabilities		1,319		3,341		641			—			5,301
Due to parent		—		—		116,451			(116,451	)		—
Total liabilities		1,521,788		556,968		385,596			(193,775	)		2,270,577
Convertible preferred stock		1,000		—		—			—			1,000
Total equity		1,369,150		1,752,469		437,910			(2,254,037	)		1,305,492
	$	2,891,938	$	2,309,437	$	823,506		$	(2,447,812	)	$	3,577,069

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(in thousands)

	As of December 31, 2010
		Helix		Guarantors		Non-Guarantors			Consolidating Entries			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	376,434	$	3,294	$	11,357		$	—		$	391,085
Accounts receivable, net		61,846		91,659		23,788			—			177,293
Unbilled revenue		11,990		—		37,421			—			49,411
Income taxes receivable		19,334		—		7,195			(20,430	)		6,099
Other current assets		63,306		49,557		12,889			(8,786	)		116,966
Total current assets		532,910		144,510		92,650			(29,216	)		740,854
Intercompany		1,906		263,920		(171,513	)		(94,313	)		—
Property and equipment, net		217,153		1,605,906		709,082			(5,061	)		2,527,080
Other assets:
Equity investments in unconsolidated affiliates		—		—		187,031			—			187,031
Equity investments in affiliates		1,998,289		29,899		—			(2,028,188	)		—
Goodwill, net		—		45,107		17,387			—			62,494
Other assets, net		43,971		38,324		21,900			(29,634	)		74,561
Due from subsidiaries/parent		95,398		105,434		—			(200,832	)		—
	$	2,889,627	$	2,233,100	$	856,537		$	(2,387,244	)	$	3,592,020

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	60,308	$	56,107	$	42,966		$	—		$	159,381
Accrued liabilities		58,074		107,874		32,289			—			198,237
Income taxes payable		—		36,678		—			(36,678	)		—
Current maturities of long-term debt		4,326		—		14,301			(8,448	)		10,179
Total current liabilities		122,708		200,659		89,556			(45,126	)		367,797
Long-term debt		1,237,587		—		110,166			—			1,347,753
Deferred income taxes		185,453		135,101		98,968			(5,883	)		413,639
Asset retirement obligations		—		170,410		—			—			170,410
Other long-term liabilities		1,421		3,691		665			—			5,777
Due to parent		—		—		120,884			(120,884	)		—
Total liabilities		1,547,169		509,861		420,239			(171,893	)		2,305,376
Convertible preferred stock		1,000		—		—			—			1,000
Total equity		1,341,458		1,723,239		436,298			(2,215,351	)		1,285,644
	$	2,889,627	$	2,233,100	$	856,537		$	(2,387,244	)	$	3,592,020

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(in thousands)

(Unaudited)

	Three Months Ended March 31, 2011
	Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated

Net revenues	$	15,582		$	242,042		$	57,876		$	(23,893	)	$	291,607
Cost of sales		16,593			165,231			56,278			(23,571	)		214,531
Gross profit		(1,011	)		76,811			1,598			(322	)		77,076
Gain on sale or acquisition of assets		16			—			—			—			16
Selling, general and administrative expenses		(11,186	)		(10,036	)		(4,154	)		395			(24,981	)
Income (loss) from operations		(12,181	)		66,775			(2,556	)		73			52,111
Equity in earnings of investments		48,107			(5,662	)		5,650			(42,445	)		5,650
Net interest expense and other		(17,284	)		(4,709	)		417			—			(21,576	)
Income (loss) before income taxes		18,642			56,404			3,511			(42,372	)		36,185
Provision (benefit) for income taxes		(7,173	)		21,741			(5,041	)		23			9,550
Net income (loss) applicable to Helix		25,815			34,663			8,552			(42,395	)		26,635
Less:net income applicable to noncontrolling interests		—			—			—			(768	)		(768	)
Preferred stock dividends		(10	)		—			—			—			(10	)
Net income (loss) applicable to Helix common shareholders	$	25,805		$	34,663		$	8,552		$	(43,163	)	$	25,857

	Three Months Ended March 31, 2010
	Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated

Net revenues	$	21,022		$	169,723		$	44,972		$	(34,147	)	$	201,570
Cost of sales		13,334			140,042			49,957			(27,619	)		175,714
Gross profit		7,688			29,681			(4,985	)		(6,528	)		25,856
Gain on sale or acquisition of assets		—			287			5,960			—			6,247
Selling, general and administrative expenses		(23,875	)		(10,081	)		(7,045	)		500			(40,501	)
Income (loss) from operations		(16,187	)		19,887			(6,070	)		(6,028	)		(8,398	)
Equity in earnings of investments		4,868			(507	)		5,055			(4,361	)		5,055
Net interest expense and other		(7,389	)		(7,566	)		(6,265	)		—			(21,220	)
Income (loss) before income taxes		(18,708	)		11,814			(7,280	)		(10,389	)		(24,563	)
Provision (benefit) for income taxes		(4,796	)		4,215			(4,871	)		(2,109	)		(7,561	)
Net income (loss) applicable to Helix		(13,912	)		7,599			(2,409	)		(8,280	)		(17,002	)
Less:net income applicable to noncontrolling interests		—			—			—			(829	)		(829	)
Preferred stock dividends		(60	)		—			—			—			(60	)
Net income (loss) applicable to Helix common shareholders	$	(13,972	)	$	7,599		$	(2,409	)	$	(9,109	)	$	(17,891	)

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

	Three Months Ended March 31, 2011
			Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated

Cash flow from operating activities:
Net income (loss), including noncontrolling interests		$	25,815		$	34,663		$	8,552		$	(42,395	)	$	26,635
Adjustments to reconcile net income (loss), including noncontrolling interests to net cash provided by (used in) operating activities:
Equity in earnings of affiliates			(48,107	)		5,662			—			42,445			—
Other adjustments			(16,484	)		74,174			4,644			(3,904	)		58,430
Net cash provided by (used in) operating
activities			(38,776	)		114,499			13,196			(3,854	)		85,065

Cash flows from investing activities:
Capital expenditures			(7,143	)		(18,200	)		(9,145	)		—			(34,488	)
Distributions from equity investments, net			—			—			480			—			480
Proceeds from sale of Cal Dive common stock			3,588			—			—			—			3,588
Deceases in restricted cash			—			613			—			—			613
Net cash used in investing activities			(3,555	)		(17,587	)		(8,665	)		—			(29,807	)

Cash flows from financing activities:
Repayments of debt			(1,082	)		—			(2,954	)		—			(4,036	)
Preferred stock dividends paid and other			(10	)		—			—			—			(10	)
Repurchases of common stock			(927	)		—			—			—			(927	)
Excess tax benefit from stock-based compensation			(969	)		—			—			—			(969	)
Exercise of stock options, net			600			—			—			—			600
Intercompany financing			93,799			(97,733	)		80			3,854			—
Net cash provided by (used in) financing activities			91,411			(97,733	)		(2,874	)		3,854			(5,342	)
Effect of exchange rate changes on cash and cash equivalents			—			—			(470	)		—			(470	)
Net increase (decrease) in cash and cash equivalents			49,080			(821	)		1,187			—			49,446
Cash and cash equivalents:
Balance, beginning of year			376,434			3,294			11,357			—			391,085
Balance, end of year		$	425,514		$	2,473		$	12,544		$	—		$	440,531

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(in thousands)

	Three Months Ended March 31, 2010
		Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated

Cash flow from operating activities:
Net income (loss), including noncontrolling interests	$	(13,912	)	$	7,599		$	(2,409	)	$	(8,280	)	$	(17,002	)
Adjustments to reconcile net income (loss), including noncontrolling interests to net cash provided by (used in) operating activities:
Equity in earnings of affiliates		(4,868	)		507			—			4,361			—
Other adjustments		(111	)		42,640			(1,210	)		(5,880	)		35,439
Net cash provided by (used in) operating
activities		(18,891	)		50,746			(3,619	)		(9,799	)		18,437

Cash flows from investing activities:
Capital expenditures		(29,067	)		(34,501	)		(4,860	)		—			(68,428	)
Distributions from equity investments, net		—			—			965			—			965
Increases in restricted cash		—			(4	)		—			—			(4	)
Net cash used in investing activities		(29,067	)		(34,505	)		(3,895	)		—			(67,467	)

Cash flows from financing activities:
Repayments of debt		(1,082	)		—			(3,114	)		—			(4,196	)
Deferred financing costs		(2,789	)		—			—			—			(2,789	)
Preferred stock dividends paid		(60	)		—			—			—			(60	)
Repurchase of common stock		(976	)		—			—						(976	)
Excess tax benefit from stock-based compensation		(1,842	)		—			—			—			(1,842	)
Intercompany financing		(6,434	)		(15,163	)		11,798			9,799			—
Net cash provided by (used in) financing activities		(13,183	)		(15,163	)		8,684			9,799			(9,863	)
Effect of exchange rate changes on cash and cash equivalents		—			—			398			—			398
Net increase (decrease) in cash and cash equivalents		(61,141	)		1,078			1,568			—			(58,495	)
Cash and cash equivalents:
Balance, beginning of year		258,742			2,522			9,409			—			270,673
Balance, end of year	$	197,601		$	3,600		$	10,977		$	—		$	212,178

Entity Information - USD ($)	3 Months Ended
Entity Information - USD ($)	Mar. 31, 2011	Apr. 21, 2011	Jun. 30, 2010
Entity Registrant Name	HELIX ENERGY SOLUTIONS GROUP INC
Entity Central Index Key	0000866829
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 1,063,094,099
Entity Common Stock, Shares Outstanding		106,011,182
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q1

Income Taxes	3 Months Ended
Income Taxes	Mar. 31, 2011
Notes To Financial Statements [Abstract]
Income Taxes	Note 8 – Income Taxes The effective tax rate for the three-month period ended March 31, 2011 was 26.4% as compared with 30.8% for the three-month period ended March 31, 2010. The effective tax rate for the first quarter of 2011 resulted from of the increased benefit derived from lower tax rates in certain foreign jurisdictions. We believe our recorded assets and liabilities are reasonable; however, tax laws and regulations are subject to interpretation and tax litigation is inherently uncertain, and therefore our assessments can involve a series of complex judgments about future events and rely heavily on estimates and assumptions.

Related Party Transactions	3 Months Ended
Related Party Transactions	Mar. 31, 2011
Notes To Financial Statements [Abstract]
Related Party Transactions	Note 13 – Related Party Transactions In April 2000, we acquired a 20% working interest in Gunnison, a deepwater Gulf of Mexico prospect, from a third party. Financing for the exploratory costs of approximately $20 million was provided by an investment partnership (OKCD Investments, Ltd. or “OKCD”), the investors of which include current and former Helix senior management, in exchange for a revenue interest that is an overriding royalty interest of 25% of Helix’s 20% working interest. Production began in December 2003. Our payments to OKCD totaled $2.3 million and $3.0 million for the three-month periods ended March 31, 2011 and 2010, respectively. Our Chief Executive Officer, Owen Kratz, through Class A limited partnership interests in OKCD, personally owns approximately 80.4% of the partnership. In 2000, OKCD also awarded Class B income participations to key Helix employees, who are required to maintain their employment status with Helix in order to retain such income participations.

Document Information	3 Months Ended
Document Information	Mar. 31, 2011
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2011

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) shares in Thousands, $ in Thousands	Mar. 31, 2011	Dec. 31, 2010
Current assets:
Accounts receivable - Trade, net of allowance for uncollectible accounts of $4,445 and $4,527, respectively	$ 4,445	$ 4,527
Shareholders' equity
Common stock, par (in dollars per share)	$ 0	$ 0
Common stock, authorized (in shares)	240,000	240,000
Common stock, issued (in shares)	106,012	105,592