CONDENSED CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	6 Months Ended	12 Months Ended
	Jun. 30, 2010	Dec. 31, 2009
Current assets:
Cash and cash equivalents	$ 270,001	$ 270,673
Accounts receivable - Trade, net of allowance for uncollectible accounts of $419 and $5,172, respectively	175,240	145,519
Unbilled revenue	17,308	17,854
Costs in excess of billing	11,829	9,305
Other current assets	120,670	122,209
Total current assets	595,048	565,560
Property and equipment	4,454,976	4,352,109
Less - accumulated depreciation	(1,789,416)	(1,488,403)
Property and equipment, net	2,665,560	2,863,706
Other assets:
Equity investments	187,694	189,411
Goodwill	76,134	78,643
Other assets, net	82,137	82,213
Total assets	3,606,573	3,779,533
Current liabilities
Accounts payable	163,975	155,457
Accrued liabilities	202,154	200,607
Current maturities of long-term debt	11,396	12,424
Total current liabilities	377,525	368,488
Long-term debt	1,347,994	1,348,315
Deferred income taxes	383,652	442,607
Asset retirement obligations	165,799	182,399
Other long-term liabilities	5,109	4,262
Total liabilities	2,280,079	2,346,071
Convertible preferred stock	1,000	6,000
Commitments and contingencies
Shareholders' equity
Common stock, no par, 240,000 shares authorized, 105,681 and 104,281 shares issued, respectively	906,153	907,691
Retained earnings	416,365	519,807
Accumulated other comprehensive loss	(20,502)	(22,241)
Total controlling interest shareholders' equity	1,302,016	1,405,257
Noncontrolling interests	23,478	22,205
Total equity	1,325,494	1,427,462
Liabilities and shareholders' equity, total	$ 3,606,573	$ 3,779,533

PARENTHETICAL DATA TO CONDENSED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Jun. 30, 2010	Dec. 31, 2009
Statement of Financial Position [Abstract]
Accounts receivable - Trade, net of allowance for uncollectible accounts of $419 and $5,172, respectively	$ 419	$ 5,172
Common stock, authorized	240,000	240,000
Common stock, issued	105,681	104,281

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2010	Jun. 30, 2009	Jun. 30, 2010	Jun. 30, 2009
Net revenues:
Contracting services	$ 196,676	$ 404,647	$ 307,531	$ 815,441
Oil and gas	102,586	89,992	193,301	250,173
Total net revenues	299,262	494,639	500,832	1,065,614
Cost of sales:
Contracting services	140,126	312,502	226,374	638,200
Oil and gas	94,092	(16,692)	172,446	67,375
Oil and gas property impairments	159,862	63,073	170,974	63,073
Total cost of revenue	394,080	358,883	569,794	768,648
Gross profit (loss)	(94,818)	135,756	(68,962)	296,966
Gain on oil and gas derivative contracts	2,482	4,121	2,482	78,730
Gain (loss) on sale or acquisition of assets, net	(14)	1,319	6,233	1,773
Selling and administrative expenses	(24,546)	(39,372)	(65,047)	(80,725)
Income (loss) from operations	(116,896)	101,824	(125,294)	296,744
Equity in earnings of investments	1,656	6,264	6,711	13,767
Gain on sale of Cal Dive common stock	0	59,442	0	59,442
Net interest expense	(20,523)	(15,644)	(36,158)	(37,611)
Other income (expense)	(1,659)	8,176	(7,217)	7,948
Income (loss) before income taxes	(137,422)	160,062	(161,958)	340,290
Provision (benefit) for income taxes	(52,366)	56,809	(59,927)	121,728
Income (loss) from continuing operations	(85,056)	103,253	(102,031)	218,562
Discontinued operations, net of tax	(17)	9,836	(44)	7,282
Net income (loss), including noncontrolling interests	(85,073)	113,089	(102,075)	225,844
Less: net income applicable to noncontrolling interests	(444)	(12,620)	(1,273)	(18,173)
Net income (loss) applicable to Helix	(85,517)	100,469	(103,348)	207,671
Preferred stock dividends	(34)	(250)	(94)	(563)
Preferred stock beneficial conversion charges			0	(53,439)
Net income (loss) applicable to Helix common shareholders	$ (85,551)	$ 100,219	$ (103,442)	$ 153,669
Basic earnings (loss) per share of common stock:
Continuing operations	$ (0.82)	$ 0.92	$ (1.00)	$ 1.50
Discontinued operations	$ 0.00	$ 0.10	$ 0.00	$ 0.08
Net income (loss) per common share	$ (0.82)	$ 1.02	$ (1.00)	$ 1.58
Diluted earnings (loss) per share of common stock:
Continuing operations	$ (0.82)	$ 0.85	$ (1.00)	$ 1.37
Discontinued operations	$ 0.00	$ 0.09	$ 0.00	$ 0.07
Net income (loss) per common share	$ (0.82)	$ 0.94	$ (1.00)	$ 1.44
Weighted average common shares outstanding:
Basic	104,125	96,936	103,610	96,077
Diluted	104,125	105,995	103,610	106,000

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2010	Jun. 30, 2009
Cash flows from operating activities:
Net income (loss), including noncontrolling interests	$ (102,075)	$ 225,844
Adjustments to reconcile net income (loss) including noncontrolling interests to net cash provided by operating activities
Depreciation and amortization	146,268	157,289
Asset impairment charge and dry hole expense	170,784	63,499
Equity in earnings of investments, net of distributions	0	(3,697)
Amortization of deferred financing costs	3,768	2,903
Loss (income) from discontinued operations	44	(7,282)
Stock compensation expense	4,589	7,188
Amortization of debt discount	4,136	3,876
Deferred income taxes	(54,749)	19,917
Excess tax benefit from stock-based compensation	2,163	754
Gain on sale or acquisition of assets	(6,233)	(1,773)
Unrealized (gain) loss on derivative contracts	2,813	(24,667)
Gain on sale of investment in Cal Dive common stock	0	(59,442)
Changes in operating assets and liabilities:
Accounts receivable, net	(30,591)	(14,231)
Other current assets	16,477	15,704
Income tax payable	(10,811)	124,531
Accounts payable and accrued liabilities	28,027	9,220
Asset retirement obligation costs	(28,727)	(11,775)
Other noncurrent, net	(9,439)	(78,865)
Cash provided by operating activities	136,444	428,993
Cash used in discontinued operations	(44)	(6,121)
Net cash provided by operating activities	136,400	422,872
Cash flows from investing activities:
Capital expenditures	(135,612)	(238,402)
Investments in equity investments	6,307	454
Distributions from equity investments, net	8,132	3,253
Insurance recovery for capital items	16,106	0
Proceeds from sale of Cal Dive common stock	0	196,656
Reduction in cash from deconsolidation of Cal Dive	0	(112,995)
Proceeds from sales of properties	0	23,238
Other	109	(15)
Net cash used in investing activities	(117,572)	(128,719)
Cash provided by discontinued operations	0	20,874
Net cash used in investing activities	(117,572)	(107,845)
Cash flows from financing activities
Repayment of Helix Term Loan	(2,163)	(2,163)
Repayments on Helix Revolver	0	(349,500)
Repayment of MARAD borrowings	(2,403)	(2,081)
Borrowings on CDI Revolver	0	100,000
Repayments on CDI Term Note	0	(20,000)
Deferred financing costs	(2,792)	(28)
Repurchases of common stock	(9,127)	(753)
Excess tax benefit from stock-based compensation	(2,163)	(754)
Loan note repayment, preferred stock dividends paid and other	(1,098)	(500)
Net cash used in financing activities	(19,746)	(275,779)
Effect of exchange rate changes on cash and cash equivalents	246	(931)
Net (decrease) increase in cash and cash equivalents	(672)	38,317
Balance, end of period	270,673	223,613
Balance, end of period	$ 270,001	$ 261,930

Basis of Presentation	6 Months Ended
Basis of Presentation	Jun. 30, 2010
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. Until June 2009, Cal Dive International, Inc. (collectively with its subsidiaries referred to as “Cal Dive” or “CDI”) was a majority-owned subsidiary of Helix. Helix sold substantially all its ownership interest in Cal Dive during 2009 (see Note 4 below and Note 3 of our Annual Report on Form 10-K for the year ended December 31, 2009 (“2009 Form 10-K”)). 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 2009 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 periods ended June 30, 2010 are not necessarily indicative of the results that may be expected for the year ending December 31, 2010. Our balance sheet as of December 31, 2009 included herein has been derived from the audited balance sheet as of December 31, 2009 included in our 2009 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 2009 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.

- Definition

Description containing the entire organization, consolidation and basis of presentation of financial statements disclosure. May be provided in more than one note to the financial statements, as long as users are provided with an understanding of (1) the significant judgments and assumptions made by an enterprise in determining whether it must consolidate a VIE and/or disclose information about its involvement with a VIE, (2) the nature of restrictions on a consolidated VIE's assets reported by an enterprise in its statement of financial position, including the carrying amounts of such assets, (3) the nature of, and changes in, the risks associated with an enterprise's involvement with the VIE, and (4) how an enterprise's involvement with the VIE affects the enterprise's financial position, financial performance, and cash flows. Describes procedure if disclosures are provided in more than one note to the financial statements.

+ References+ Details

Company Overview

6 Months Ended

Jun. 30, 2010

Notes To Financial Statements [Abstract]

Note 2 - 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 our own oil and gas properties. Our Contracting Services segment utilizes our vessels, offshore equipment and methodologies to deliver services that encompass the complete lifecycle of an offshore oil and gas field and that may reduce finding and development costs. Our Contracting Services operations are located primarily in the 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 almost exclusively located in the Gulf of Mexico.

Contracting Services Operations

We seek to provide services and methodologies that we believe are critical to finding and developing offshore reservoirs and maximizing production economics. Our “life of field” services are segregated into three disciplines: subsea construction, well operations and production facilities. We have disaggregated our contracting services operations into two continuing reportable segments: Contracting Services and Production Facilities. Our Contracting Services business primarily consists of deepwater construction and well operation activities. Formerly, we had a third Contracting Services segment, Shelf Contracting, which represented the assets of CDI. We sold substantially all of our ownership of CDI through various transactions in 2009 (Note 4). Our Production Facilities business includes our investments in Deepwater Gateway, L.L.C. (“Deepwater Gateway”), Independence Hub, LLC (“Independence Hub”) and the Helix Producer I (“HP I”) vessel.

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 asset utilization of our contracting services business and to generate incremental returns. Over time, we 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.

Discontinued Operations

In April 2009, we sold Helix Energy Limited (“HEL”), our former reservoir technology consulting business, to a subsidiary of Baker Hughes Incorporated for $25 million. As a result of the sale of HEL, which entity’s operations were conducted by its wholly owned subsidiary, Helix RDS Limited (“Helix RDS”), we have presented the results of Helix RDS as discontinued operations in the accompanying condensed consolidated financial statements (Note 3). HEL and Helix RDS were previously included in our Contracting Services segment.

Business Strategy

During 2009, we focused on improving our balance sheet by increasing our liquidity through reductions in planned capital spending and potential additional dispositions of our non-core business assets. During 2009, we completed the following dispositions of non-core business assets:

·	Sold five oil and gas properties for approximately $24 million;

·	Sold a total of 15.2 million shares of CDI common stock held by us to CDI for $100 million in separate transactions in January and June 2009;

Sold a total of 45.8 million shares of CDI common stock held by us to third parties in two separate public secondary offerings for approximately $404.4 million, net of underwriting fees in June 2009 and September 2009. For additional information regarding the sales of CDI common shares by us see Note 4; and

·	Sold Helix RDS Limited, our subsurface reservoir consulting business for $25 million in April 2009.

In March 2010, we announced that we had engaged advisors to assist us with evaluating potential alternatives for the disposition of our oil and gas business. At the time of the filing of this Current Report on Form 10-Q we do not have an approved or definitive plan for such disposition of our oil and gas business.

Recent Events in Gulf of Mexico

Oil Spill

On April 20, 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 is unprecedented in U.S territorial waters. The operator of the Macondo project, BP PLC (“BP”) has recently controlled the flow of the oil from the well and ultimately plans to plug the well. Simultaneously, efforts to contain and ultimately remediate the environmental impacts caused by the oil spill are ongoing. We have contracted three of our vessels, the Q4000, the Express and the HP I to participate in the coordinated containment response to the oil spill in the Gulf of Mexico.

Drilling Moratorium

On May 12, 2010, the U.S. Department of Interior (“DOI”) announced a total moratorium on new drilling in the Gulf of Mexico. This moratorium also affected 33 in progress wells in the deepwater. On May 28, 2010 the moratorium on drilling in the shallow water of the Gulf, as defined as water depths less than 500 feet, was lifted. However, the DOI extended the drilling moratorium on deepwater wells through November 2010. This drilling moratorium was challenged in court and the court enjoined its enforcement. However, the DOI has recently amended its drilling moratorium which remains in effect at the time of this filing despite additional potential legal challenges.

Details of Certain Accounts (in thousands)

6 Months Ended

Jun. 30, 2010

Notes To Financial Statements [Abstract]

Details of Certain Accounts

Note 3 – Details of Certain Accounts

Other current assets consisted of the following as of June 30, 2010 and December 31, 2009:

		June 30,		December 31,
		2010		2009
		(in thousands)
Other receivables	$	3,851	$	7,990
Prepaid insurance		12,901		11,105
Other prepaids		16,545		21,819
Inventory		25,808		25,755
Current deferred tax assets		15,057		24,517
Hedging assets		15,306		6,214
Gas imbalance		6,774		7,655
Income tax receivable		18,139		8,492
Assets of discontinued operations		825		878
Other		5,464		7,784
	$	120,670	$	122,209

Other assets, net, consisted of the following as of June 30, 2010 and December 31, 2009:

		June 30,		December 31,
		2010		2009
		(in thousands)
Restricted cash	$	35,519	$	35,409
Deferred drydock expenses, net		14,238		12,030
Deferred financing costs		29,284		30,061
Intangible assets with finite lives, net		713		768
Other		2,383		3,945
	$	82,137	$	82,213

Accrued liabilities consisted of the following as of June 30, 2010 and December 31, 2009:

		June 30,		December 31,
		2010		2009
		(in thousands)
Accrued payroll and related benefits	$	25,976	$	30,513
Royalties payable		11,146		5,717
Asset retirement obligation		76,708		65,729
Unearned revenue		9,188		3,672
Accrued interest		27,826		27,830
Billing in excess of cost		6,814		—
Deposit		25,542		25,542
Hedge liability		5,108		19,536
Liabilities of discontinued operations		13		451
Other		13,833		21,617
	$	202,154	$	200,607

Ownership of Cal Dive International, Inc.	6 Months Ended
Ownership of Cal Dive International, Inc.	Jun. 30, 2010
Notes To Financial Statements [Abstract]
Ownership of Cal Dive International, Inc.	Note 4 — Ownership of Cal Dive International, Inc. In January 2009, we sold approximately 13.6 million shares of Cal Dive common stock to Cal Dive for $86 million. This transaction constituted a single transaction and was not part of any planned set of transactions that would have resulted in us having a noncontrolling interest in Cal Dive, and reduced our ownership in Cal Dive to approximately 51%. Because we retained control of CDI immediately after the transaction, the loss of approximately $2.9 million on this sale was treated as a reduction of our equity. In June 2009, we sold 22.6 million shares of Cal Dive common stock held by us pursuant to a secondary public offering (“Offering”) and Cal Dive repurchased an additional 1.6 million shares of its common stock from us. Following the closing of these two transactions, our ownership of Cal Dive common stock was reduced to approximately 26%. Since we no longer held a controlling interest in Cal Dive, we ceased consolidating Cal Dive effective June 10, 2009, and subsequently accounted for our remaining ownership interest in Cal Dive under the equity method of accounting until September 2009, when we sold substantially all of our remaining interest in Cal Dive. We continue to own 0.5 million shares of Cal Dive common stock, representing less than 1% of the total outstanding shares of Cal Dive. Accordingly, we now classify our remaining interest in Cal Dive as an investment available for sale pursuant to ASC Topic No. 320 “Investment - Debt and Equity Securities.” As an investment available for sale, the value of our remaining interest will be marked-to-market at each period end with the corresponding change in value being reported as a component of other accumulated comprehensive income (loss) in the accompanying condensed consolidated balance sheets (Note 11). The pre-tax value of our remaining investment in Cal Dive as of June 30, 2010 has decreased $0.9 million since December 31, 2009 and $2.2 million since our Cal Dive sales transaction in September 2009. We consider our unrealized losses on our remaining Cal Dive investment to be temporary. We will continue to monitor our investment and should we determine that these losses are not temporary we will remove the unrealized amounts from our accumulated comprehensive loss by recording the difference between our original investment and the then expected realizable value as a non operating expense charge in our consolidated statement of operations. See Note 3 of our 2009 Form 10-K for additional information regarding our sale transactions involving Cal Dive common stock in 2009.

Convertible Preferred Stock	6 Months Ended
Convertible Preferred Stock	Jun. 30, 2010
Notes To Financial Statements [Abstract]
Convertible Preferred Stock	Note 5 – Convertible Preferred Stock In January 2009, Fletcher International, Ltd. (“Fletcher”) issued a redemption notice with respect to its $30 million of Series A-2 Cumulative Convertible Preferred Stock, and, pursuant to the resulting redemption, we issued and delivered 5,938,776 shares of our common stock to Fletcher. Accordingly, in the first quarter of 2009 we recognized a $29.3 million charge to reflect the terms of this redemption, which was recorded as a reduction in our net income applicable to common shareholders. This beneficial conversion charge reflected the value associated with the additional 3,974,718 shares delivered over the original 1,964,058 shares that would have been contractually required to be issued upon a conversion but was limited to the $29.3 million of net proceeds we received from the issuance of the Series A-2 Cumulative Convertible Preferred Stock in June 2004. In February 2009, the price of our common stock fell below $2.767 per share. Under terms of the agreement governing the issuance of the cumulative convertible preferred stock, we provided notice to Fletcher that with respect to the $25 million of Series A-1 Cumulative Convertible Preferred Stock the conversion price was reset to $2.767, the established minimum price per the agreement, and that Fletcher shall have no further rights to redeem the shares, and we have no further right to pay dividends in common stock. As a result of the reset of the conversion price, Fletcher would receive an aggregate of 9,035,056 shares in future conversion(s) into our common stock. In the event we elect to settle any future conversion in cash, Fletcher would receive cash in an amount approximately equal to the value of the shares it would receive upon a conversion, which could be substantially greater than the original face amount of the Series A-1 Cumulative Convertible Preferred Stock, and which would result in additional beneficial conversion charges in our statement of operations. Under the existing terms of our Senior Credit Facilities (Note 9) we are not permitted to deliver cash upon a conversion of the Convertible Preferred Stock. In connection with the reset of the conversion price of the Series A-1 Cumulative Convertible Preferred Stock to $2.767, we were required to recognize a $24.1 million charge to reflect the value associated with the additional 7,368,388 shares that will be required to be delivered upon any future conversion(s) over the 1,666,668 shares that were to be delivered under the original contractual terms. This $24.1 million charge was recorded as a beneficial conversion charge reducing our net income applicable to common shareholders. The beneficial conversion charge for the Series A-1 Cumulative Convertible Preferred Stock is limited to the $24.1 million of net proceeds received upon its issuance in January 2003. In May 2010, Fletcher converted $5 million of its Series A-1 Cumulative Convertible Preferred Stock into 1,807,011 shares of our common stock. In the third quarter of 2009, Fletcher converted $19 million of its Series A-1 Cumulative Convertible Preferred Stock into 6,866,641 shares of our common stock. The remaining $1 million of the Series A-1 Cumulative Convertible Preferred Stock, which is convertible into 361,402 shares of our common stock, maintains its mezzanine presentation below liabilities but is not included as a component of shareholders’ equity, because we may, under certain instances be required to settle any future conversions in cash. Prior to any future conversion(s), the common shares issuable will be assessed for inclusion in our diluted earnings per share computations using the if converted method based on the applicable conversion price of $2.767 per share, meaning that for all periods in which we have positive earnings from continuing operations and our average stock price exceeds $2.767 per share we will have an assumed conversion of convertible preferred stock and the 361,402 shares will be included in our diluted shares outstanding amount.

Oil and Gas Properties

6 Months Ended

Jun. 30, 2010

Notes To Financial Statements [Abstract]

Oil and Gas Properties

Note 6 – Oil and Gas Properties

In March 2010, we announced that we engaged advisors to assist us with evaluating potential alternatives for the disposition of our oil and gas business. At the time of the filing of this Quarterly Report on Form 10-Q we do not have an approved or definitive plan for such disposition of our oil and gas business.

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.

Mid Year Reserve Assessment

In connection with our regular mid-year review as well as our efforts to pursue potential divestment alternatives for our oil and gas business, we engaged an independent petroleum reservoir engineering firm to update our estimates of proved reserves for our domestic oil and gas properties as of June 30, 2010. The resulting independent petroleum engineer reserve report indicated the we had a significant reduction in proved reserves resulting from a combination of factors including well performance issues at certain of our producing fields, most notably our Bushwood field at Garden Banks Blocks 462/463/506/507, as well as changes in the field economics of some of our other oil and gas properties. The changes in field economics primarily affected properties that were either close to the end of their production life or in which we had proved undeveloped reserves, which would have been required to be developed in the near term. The decision not to develop these properties in light of these economic changes was also driven by our desire to pursue potential alternatives to divest our oil and gas business and the increasing uncertainties about future oil and gas operations in the Gulf of Mexico as a result of the oil spill from the Macondo well. As a result of the reduction in estimated reserves we were required to record oil and gas property impairment charges of $159.9 million at June 30, 2010.

Impairments

Following the determination of a significant reduction in our estimates of proved reserves at June 30, 2010, we recorded oil and gas property impairment charges totaling $159.9 million which affected the carrying value of 15 of our Gulf of Mexico oil and gas properties.

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 three properties subject to these impairment

charges produce natural gas almost entirely. Separately, we also recorded a $4.1 million impairment charge for our only non-domestic oil and gas property (see “United Kingdom Property” below).

In the second quarter of 2009, we recorded an aggregate of approximately $63.1 million of impairment charges. These charges primarily reflected the approximate $51.5 million of impairment-related charges recorded to properties that were severely damaged by Hurricane Ike (as discussed below in Insurance). Separately, we also recorded $11.5 million of impairment charges to reduce the asset carrying value of four fields following reductions in their estimated proved reserves as evaluated at June 30, 2009.

Exploration and Other

As of June 30, 2010, we capitalized approximately $3.2 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 and six month periods ended June 30, 2010 and 2009 (in thousands):

		Three Months Ended					Six Months Ended
		June 30,					June 30,
		2010			2009		2010			2009
Delay rental and geological and geophysical costs	$	1,182		$	1,061	$	1,528		$	1,533
Dry hole expense		(10	)		422		(190	)		426
Total exploration expense	$	1,172		$	1,483	$	1,338		$	1,959

MMS Royalty Claims

We and other industry participants were involved in a dispute with the U.S. Department of the Interior Minerals Management Service (“MMS”) (recently reorganized as the Bureau of Ocean Energy Management, Regulation and Enforcement) over royalties associated with production from certain deepwater oil and gas leases. As a result of this dispute, we recorded reserves for the disputed royalties (and any other royalties that may be claimed for production during 2005, 2006, 2007 and 2008) plus interest at 5% for our portion the MMS claim, which affected our Garden Banks Blocks 667, 668 and 669 (“Gunnison”) leases. The result of accruing these reserves since 2005 had reduced our oil and gas revenues. In the first quarter of 2009, following the decision of the United States Court of Appeals for the Fifth Circuit Court affirming the district court’s previous ruling in favor of the plaintiffs in that case, which pertained to the Gunnison leases, we reversed our previously accrued royalties ($73.5 million) to oil and gas revenues. On October 5, 2009, the United States Supreme Court denied the government’s petition for a writ of certiorari, and, the MMS subsequently withdrew its orders to pay the royalty.

For additional information regarding our royalty dispute and related litigation see Note 17 of our 2009 Form 10-K.

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 thereby assuming its obligations, most notably the asset retirement obligation (“ARO”), related to its 50% working interest in the field. The following table contains the fair value of the assets acquired and liabilities assumed in our acquisition of this third party and its 50% working interest in the Camelot field (in thousands):

Cash (a)	$	10,156
Deferred tax asset		2,083
Accrued liabilities		(452	)
Asset retirement obligation		(5,841	)
Gain on acquisition of assets	$	5,946

At March 31, 2010, $10.0 million of this amount remained held in an escrow account and was restricted for future use to fund the asset retirement costs associated with Camelot field. The amount was released from escrow in the second quarter and is now unrestricted and classified with our cash and cash equivalents in the accompanying condensed consolidated balance sheet. The current classification of the asset retirement reflects the near-term probability of these activities occurring.

In connection with the valuation of assets acquired and liabilities assumed in this acquisition, we reassessed the fair value associated with our original 50% interest in the field. Based on these evaluations, it was concluded that an impairment of the property was required based on the unlikely probability of our expending the future capital necessary to further develop the Camelot field and our plans are to abandon the field over the near term. As a result, we recorded a $4.1 million impairment charge to fully impair the property. Accordingly, in our future estimates of proved reserves we will no longer consider the reserves associated with this field as proved but rather deem them as probable reserves.

Property Sales

In the first quarter of 2009, we sold our interest in East Cameron Block 316 for gross proceeds of approximately $18 million. We recorded an approximate $0.7 million gain from the sale of East Cameron Block 316 which was partially offset by the loss on the sale of the remaining 10% of our interest in the Bass Lite field at Atwater Block 426 in January 2009. In the second quarter of 2009, we sold three fields for gross proceeds of $0.8 million resulting in an aggregate gain of $1.2 million, including transfer of the respective field’s asset retirement obligations.

Asset retirement obligations

The following table describes the changes in our asset retirement obligations (both long term and current) since December 31, 2009 (in thousands):

Asset retirement obligation at December 31, 2009	$	248,128
Liability incurred during the period (a)		17,392
Liability settled during the period		(38,496	)
Revision in estimated cash flows		7,540
Accretion expense (included in depreciation and amortization)		7,943
Asset retirement obligations at June 30, 2010	$	242,507

Amount primarily includes the acquisition of the remaining 50% working interest in the Camelot field in February 2010 (see “United Kingdom Property” above) and the additional scope of work associated with the development of the Phoenix field. Initial production was deferred from June 2010 to allow our HP I vessel to be contracted and used in the Gulf oil spill containment efforts. Following its release from the oil spill containment response contract, the HP I will mobilize to Phoenix field, where initial production is expected to commence late in the third quarter of 2010.

Insurance

In September 2008, we sustained damage to certain of our oil and gas production facilities from Hurricanes Gustav and Ike. While we sustained some damage to our own production facilities from Hurricane Ike, the larger issue in terms of production recovery involved damage to third party pipelines and onshore processing facilities. 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 were recorded when the realization of the claim for recovery of a loss is deemed probable.

In June 2009, we reached a settlement with the underwriters of our insurance policies related to damages from Hurricane Ike. Insurance proceeds received in the second quarter of 2009 totaled $102.6 million. Previously, we had received approximately $25.6 million of reimbursements under previously submitted Ike-related insurance claims. In the second quarter of 2009, we recorded a $43.0 million net reduction in our cost of sales in the accompanying condensed consolidated statements of operations representing the amount our insurance recoveries exceeded our costs during the second quarter of 2009. The cost reduction reflects the net proceeds of $102.6 million partially offset by $8.1 million of hurricane-related expenses incurred in the second quarter of 2009 and $51.5 million of hurricane related impairment charges, including $43.8 million of additional estimated asset retirement costs resulting from additional work performed and/or further evaluation of facilities on properties that were classified as a “total loss” following the storm. During the first half of 2010, we incurred a total of $3.6 million of additional hurricane-related repair costs.

The following table summarizes the claims and reimbursements by segment that affected our costs of sales accounts under various insurance claims resulting from damages sustained by Hurricane Ike, primarily those claims and reimbursement recently settled under our energy insurance policy (in thousands):

	Second Quarter 2009			Six Months Ended June 30, 2009

Oil and gas:
Hurricane repair costs	$	7,427		$	20,163
ARO liability adjustments		43,812			43,812
Hurricane-related impairments		7,699			7,699
Insurance recoveries		(97,747	)		(100,874	)
Net (reimbursements) costs	$	(38,809	)	$	(29,200	)

Contracting services:
Hurricane repair costs	$	317		$	776
Insurance recoveries		(2,249	)		(2,726	)
Net (reimbursements) costs		(1,932	)		(1,950	)

Shelf Contracting:
Hurricane repair costs		383			610
Insurance recoveries		(2,611	)		(2,611	)
Net (reimbursements) costs		(2,228	)		(2,001	)

Totals:
Hurricane repair costs		8,127			21,549
ARO liability adjustments		43,812			43,812
Hurricane-related impairments		7,699			7,699
Insurance recoveries		(102,607	)		(106,211	)
Net reimbursements	$	(42,969	)	$	(33,151	)

Similar to last year, our insurance renewal did not include wind storm coverage as the premium and deductibles would have been relatively substantial for the underlying coverage provided. In order to mitigate potential loss with respect to our most significant oil and gas properties from hurricanes in the Gulf of Mexico, we entered into a Catastrophic Bond instrument. The Catastrophic Bond provides for payments of negotiated amounts should the eye of a Category 2 or greater hurricane pass within certain pre-defined areas encompassing our more prominent oil and gas producing fields. The premium for this Catastrophic Bond was approximately $11.9 million. The Catastrophic Bond is not considered a risk management instrument for accounting purposes. Accordingly, the premium associated with the Catastrophic Bond is not charged to expense on a straight line basis as customary with insurance premiums, but rather it is charged to expense on a basis to reflect the Catastrophic Bond’s intrinsic value at the end of the period. Because our Catastrophic Bond was underwritten to mitigate the risk of hurricanes in the Gulf of Mexico, substantially all of its intrinsic value is for the period associated with “hurricane season” (typically June 1 to November 30) with a substantial majority of the intrinsic value associated with the period July 1, 2010 to September 30, 2010. As a result, we will charge to expense $9.4 million of our $11.9 premium in the third quarter of 2010 and $2.3 million of the premium will be charged to expense in the fourth quarter of 2010. The remaining $0.2 million will be charged to expense over first half of 2011. The expense associated with the Catastrophic Bond premium is recorded as a component of lease operating expense for our oil and gas operations.

Statement of Cash Flow Information

6 Months Ended

Jun. 30, 2010

Notes To Financial Statements [Abstract]

Statement of Cash Flow Information

Note 7 – Statement of Cash Flow Information

We define cash and cash equivalents as cash and all highly liquid financial instruments with original maturities of less than three months. We had restricted cash totaling $35.5 million at June 30, 2010 and $35.4 million December 31, 2009 all of which was related to funds required to be escrowed to cover the future asset retirement obligations associated with our South Marsh Island Block 130 field. We have fully satisfied the escrow requirements under the escrow agreement and may use the restricted cash for the future asset retirement costs of the related field. These amounts are reflected in other assets, net in the accompanying condensed consolidated balance sheets.

The following table provides supplemental cash flow information for the three months ended June 30, 2010 and 2009 (in thousands):

		Six Months Ended
		June 30,
		2010		2009

Interest paid, net of capitalized interest(1)	$	27,847	$	35,367
Income taxes paid	$	6,642	$	20,442

Non-cash investing activities for the six-month periods ended June 30, 2010 and 2009 included $32.0 million and $50.0 million, respectively, of accruals for capital expenditures. The accruals have been reflected in the condensed consolidated balance sheet as an increase in property and equipment and accounts payable.

Equity Investments

6 Months Ended

Jun. 30, 2010

Notes To Financial Statements [Abstract]

Equity Investments

Note 8 – Equity Investments

As of June 30, 2010, we have the following material investments, both of which are included within our Production Facilities segment and are accounted for under the equity method of accounting:

Deepwater Gateway, L.L.C. In June 2002, we, along with Enterprise Products Partners L.P. (”Enterprise”), formed Deepwater Gateway, L.L.C. (“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 $101.7 million and $103.3 million as of June 30, 2010 and December 31, 2009, respectively (including capitalized interest of $1.5 million at June 30, 2010 and December 31, 2009). Distributions from Deepwater Gateway, net to our interest, totaled $1.6 million and $3.9 million for the respective three month and six month periods ended June 30, 2010.

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 $85.1 million and $86.1 million as of June 30, 2010 and December 31, 2009, respectively (including capitalized interest of $5.4 million and $5.6 million at June 30, 2010 and December 31, 2009, respectively). Distributions from Independence Hub, net to our interest, totaled $5.8 million and $10.7 million for the three month and six month periods ended June 30, 2010, respectively.

The following presents selected summarized unaudited operating results for our Deepwater Gateway and Independence Hub equity investments for the three and six month periods ended June 30, 2010 and 2009 (in thousands):

	Deepwater Gateway				Independence Hub				Combined
	Three Months Ended				Three Months Ended				Three Months Ended
	June 30,				June 30,				June 30,
	2010		2009		2010		2009			2010		2009
Revenues	$	4,424	$	1,691	$	27,583	$	33,155		$	32,007	$	34,846
Operating income		2,346		(469)		24,008		29,590			26,354		29,121
Net income		2,347		(464)		24,009		29,595			26,356		29,131

Equity in earnings	$	1,174	$	(233)	$	4,802	$	5,919		$	5,976	$	5,686

	Deepwater Gateway				Independence Hub				Combined
	Six Months Ended				Six Months Ended				Six Months Ended
	June 30,				June 30,				June 30,
	2010		2009		2010		2009		2010		2009
Revenues	$	8,742	$	8,333	$	56,765	$	66,771	$	65,507	$	75,104
Operating income		4,584		3,154		49,618		59,615		54,202		62,769
Net income		4,585		3,167		49,619		59,632		54,204		62,799

Equity in earnings	$	2,293	$	1,583	$	9,924	$	11,926	$	12,217	$	13,509

In February 2010, we announced the formation of a joint venture 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. Services provided by the joint venture, named CloughHelix JV Co., will include subsea well intervention and well abandonment, SURF (subsea infrastructure, umbilical, riser and flowline installation), saturation and air diving, and subsea inspection, repair and maintenance services. The CloughHelix JV will integrate our well intervention equipment with Clough’s new 12 man saturation diving system, to enable both to be deployed from the 118 meter long DP2 multiservice vessel, the Normand Clough, outfitted with a 250 ton active heave compensated crane. We recorded $4.3 million and $5.7 million of losses associated with our 50% interest in the joint venture for the three month and six month periods ended June 30, 2010, respectively. The losses primarily represented the mobilization costs of transporting the Normand Clough from the Gulf of Mexico to Singapore and other start up costs related to the joint venture. This joint venture is part of our Contracting Services segment.

Long-Term Debt

6 Months Ended

Jun. 30, 2010

Notes To Financial Statements [Abstract]

Long-Term Debt

Note 9 – Long-Term Debt

Scheduled maturities of long-term debt and capital lease obligations outstanding as of June 30, 2010 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		$	─	$	─	$	─		$	4,533		$	2,537		$	11,396
One to two years		4,326			─		─		─			4,760			─			9,086
Two to three years		4,326			─		─		─			4,997			─			9,323
Three to four years		399,625			─		─		─			5,247			─			404,872
Four to five years		─			─		─		─			5,508			─			5,508
Over five years		─			─		550,000		300,000			92,005			─			942,005
Total debt		412,603			─		550,000		300,000			117,050			2,537			1,382,190
Current maturities		(4,326	)		─		─		─			(4,533	)		(2,537	)		(11,396	)
Long-term debt, less current maturities	$	408,277		$	─	$	550,000	$	300,000		$	112,517		$	─		$	1,370,794
Unamortized debt discount (3)		─			─		─		(22,800	)		─			─			(22,800	)
Long-term debt	$	408,277		$	─	$	550,000	$	277,200		$	112,517		$	─		$	1,347,994

(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 not mature until March 2025.

(2)	Represents the balance of the loan provided by Kommandor RØMØ to Kommandor LLC as of June 30, 2010.

(3)	Reflects debt discount resulting from adoption of new provisions of ASC Topic No. 470-20 “Convertible Debt and Other Options” on January 1, 2009. The notes will increase to $300 million face amount through accretion of non-cash interest charges through 2012.

At June 30, 2010, unsecured letters of credit issued totaled approximately $57.6 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 and six month periods ended June 30, 2010 and 2009:

		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2010			2009			2010			2009
		(in thousands)
Interest expense	$	24,597		$	27,612		$	48,946		$	57,463
Interest income		(199	)		(98	)		(397	)		(362	)
Capitalized interest		(3,875	)		(11,870	)		(12,391	)		(19,490	)
Interest expense, net	$	20,523		$	15,644		$	36,158		$	37,611

Included below is a summary of certain components of our indebtedness. For additional information regarding our debt see Note 10 of our 2009 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 parties have amended the Credit Agreement 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 Quarterly Report on Form 10-Q for the period ending March 31, 2010.

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 six month periods ended June 30, 2010 and 2009 was approximately 2.9% and 4.9%, respectively, including the effects of our interest rate swaps (Note 18). The Term Loan is 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 amount 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 June 30, 2010, we had no amounts drawn on the Revolving Credit Facility and our availability under the Revolving Credit Facility totaled $377.4 million, net of $57.6 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 did not have any borrowings under our Revolving Loans in the six months ended June 30, 2010. Our average interest rate on the Revolving Loans for the six months ended June 30, 2009 was approximately 3.4%.

The Credit Agreement contains various covenants regarding, among other things, collateral, capital expenditures, investments, dispositions, indebtedness and financial performance that are normal 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 entered 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 18).

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 balance sheet. No conversion triggers were met during the six-month period ended June 30, 2010. 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. The effective interest rate for the Convertible Senior Notes is 6.6%.

Our average share price for all the periods presented in this Quarterly Report on Form 10-Q 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 vessel. The MARAD Debt is payable in equal semi-annual installments which began 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 and restrictions, including the maintenance of minimum net worth, working capital and debt-to-equity requirements. The Senior Unsecured Notes and Credit Agreement contain provisions that limit our ability to incur certain types of additional indebtedness. As of June 30, 2010, we were in compliance with all of our debt covenants and restrictions.

Deferred financing costs of $29.3 million at June 30, 2010 and $30.1 million at December 31, 2009 are included in other assets, net and are being amortized over the life of the respective loan agreements.

Income Taxes	6 Months Ended
Income Taxes	Jun. 30, 2010
Notes To Financial Statements [Abstract]
Income Taxes	Note 10 – Income Taxes The effective tax rate for the three month and six month periods ended June 30, 2010 was a benefit of 38.1% and 37.0%, respectively, due to increased benefit derived from the effect of lower tax rates in certain foreign jurisdictions. The effective tax rate for the three month and six month periods ended June 30, 2009 was an expense of 35.5% and 35.8%, respectively, as a result of the consolidation of CDI in 2009. We believe our recorded assets and liabilities are reasonable. However, because tax laws and regulations are subject to interpretation and tax litigation is inherently uncertain, our assessments can involve a series of complex judgments about future events and rely heavily on estimates and assumptions.

Comprehensive Income (Loss)

6 Months Ended

Jun. 30, 2010

Notes To Financial Statements [Abstract]

Comprehensive Income (Loss)

Note 11 – Comprehensive Income (Loss)

The components of total comprehensive income (loss) for the three and six month periods ended June 30, 2010 and 2009 were as follows (in thousands):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009

Net income (loss), including noncontrolling interests	$	(85,073	)	$	113,089		$	(102,075	)	$	225,844
Other comprehensive income (loss), net of tax
Foreign currency translation gain		(3,106	)		30,650			(13,808	)		27,032
Unrealized loss on hedges, net		2,063			(8,873	)		16,103			(13,338	)
Unrealized loss on investment available for sale		(481	)	─				(556	)	─
Total Comprehensive income (loss)		(86,597	)		134,866			(100,336	)		239,538
Less: Comprehensive loss applicable to noncontrolling interest	─				(12,333	)	─				(17,880	)
Total other comprehensive income (loss) applicable to Helix	$	(86,597	)	$	122,533		$	(100,336	)	$	221,658

The components of accumulated other comprehensive loss were as follows (in thousands):

	June 30,			December 31,
	2010			2009

Cumulative foreign currency translation adjustment	$	(26,065	)	$	(12,257	)
Unrealized gain (loss) on hedges, net		7,006			(9,097	)
Unrealized loss on investment available for sale		(1,443	)		(887	)
Accumulated other comprehensive loss	$	(20,502	)	$	(22,241	)

- Definition

This label may include the following: 1) the amount of income tax expense or benefit allocated to each component of other comprehensive income, including reclassification adjustments, 2) the reclassification adjustments for each classification of other comprehensive income and 3) the ending accumulated balances for each component of comprehensive income. Components of comprehensive income include: (1) foreign currency translation adjustments; (2) gains and losses on foreign currency transactions that are designated as, and are effective as, economic hedges of a net investment in a foreign entity; (3) gains and losses on intercompany foreign currency transactions that are of a long-term-investment nature, when the entities to the transaction are consolidated, combined, or accounted for by the equity method in the reporting enterprise's financial statements; (4) change in the market value of a futures contract that qualifies as a hedge of an asset reported at fair value; (5) unrealized holding gains and losses on available-for-sale securities and that resulting from transfers of debt securities from the held-to-maturity category to the available-for-sale category; (6) a net loss recognized as an additional pension liability not yet recognized as net periodic pension cost; and (7) the net gain or loss and net prior service cost or credit for pension plans and other postretirement benefit plans.

+ References+ Details

Earnings Per Share

6 Months Ended

Jun. 30, 2010

Notes To Financial Statements [Abstract]

Earnings Per Share

Note 12 – 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 the applicable 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.

Basic EPS 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 computation of basic and diluted EPS amounts for the three and six months ended June 30, 2010 and 2009 follows (in thousands):

		Three Months Ended				Three Months Ended
		June 30, 2010				June 30, 2009
		Income		Shares		Income		Shares
Basic:
Net income (loss) applicable to common shareholders	$	(85,551	)		$	100,219
Less: Undistributed net income allocable to participating securities		─				(1,526	)
Undistributed net income (loss) applicable to common shareholders		(85,551	)			98,693
(Income) loss from discontinued operations		17				(9,836	)
Add: Undistributed net income from discontinued operations allocable to participating securities		─				150
Income (loss) per common share – continuing operations	$	(85,534	)	104,125	$	89,007		96,936

		Three Months Ended June 30, 2010				Three Months Ended June 30, 2009
		Three Months Ended June 30, 2010				Three Months Ended June 30, 2009
		Income		Shares		Income	Shares
Diluted:
Net income (loss) per common share – continuing operations – Basic	$	(85,534	)	104,125	$	89,007	96,936
Effect of dilutive securities:
Stock options		─		─		─	24
Undistributed earnings reallocated to participating securities						116	─
Convertible Senior Notes		─		─		─	─
Convertible preferred stock		─		─		250	9,035
Income (loss) per common share ─ continuing operations		(85,534	)			89,373
Income (loss) per common share ─ discontinued operations		(17	)			9,836
Net income (loss) per common share	$	(85,551	)	104,125	$	99,209	105,995

		Six Months Ended				Six Months Ended
		June 30, 2010				June 30, 2009
		Income		Shares		Income		Shares
Basic:
Net income (loss) applicable to common shareholders	$	(103,442	)		$	153,669
Less: Undistributed net income allocable to participating securities		─				(2,305	)
Undistributed net income (loss) applicable to common shareholders		(103,442	)			151,364
(Income) loss from discontinued operations		44				(7,282	)
Add: Undiscounted net income from discontinued operations allocable to participating securities		─				109
Income (loss) per common share – continuing operations	$	(103,398	)	103,610	$	144,191		96,077

		Six Months Ended June 30, 2010				Six Months Ended June 30, 2009
		Six Months Ended June 30, 2010				Six Months Ended June 30, 2009
		Income		Shares		Income	Shares
Diluted:
Net income (loss) per common share – continuing operations – Basic	$	(103,398	)	103,610	$	144,191	96,077
Effect of dilutive securities:
Stock options		─		─		─	─
Undistributed earnings reallocated to participating securities						203	─
Convertible Senior Notes		─		─		─	─
Convertible preferred stock		─		─		563	9,923
Income (loss) per common share ─ continuing operations		(103,398	)			144,957
Income (loss) per common share ─ discontinued operations		(44	)			7,282
Net income (loss) per common share	$	(103,442	)	103,610	$	152,239	106,000

We had a net loss from continuing operations for both the three and six month periods ended June 30, 2010. Accordingly, we had no dilutive securities during these reporting periods 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 and six month periods ended June 30, 2010 assuming we had earnings from continuing operations (in thousands):

	Three Months		Six Months
Diluted shares (as reported)		104,125		103,610
Stock options		94		80
Convertible preferred stock		1,195		1,689
Total		105,414		105,379

There were no dilutive stock options for the six month period ended June 30, 2009 as the option strike price was below the average market price for the period ($7.50 per share). The cumulative $53.4 million of beneficial conversion charges that were realized and recorded during the first quarter of 2009 following the transactions affecting our convertible preferred stock (Note 5) are not included as an addition to adjust earnings applicable to common stock for our diluted earnings per share calculation. The diluted EPS amount included the $0.3 million and $0.6 million of dividends and related costs associated with the assumed conversion of the convertible preferred stock for the three and six month periods ended June 30, 2009.

Stock-Based Compensation Plans

6 Months Ended

Jun. 30, 2010

Notes To Financial Statements [Abstract]

Stock-Based Compensation Plans

Note 13 – 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 June 30, 2010, there were approximately 1.3 million shares available for grant under our 2005 Incentive Plan.

During the first half of 2010, we made the following restricted share or restricted stock unit grants to certain key executives, selected management employees and non-employee members of the board of directors under the 2005 Incentive Plan:

Date of Grant	Type			Shares		Market Value Per Share		Vesting Period

January 4, 2010		(1	)		452,849	$	11.75	20% per year over five years
January 4, 2010		(2	)		23,569		11.75	20% per year over five years
January 4, 2010		(1	)		1,197		11.75	100% on January 1, 2012
April 1, 2010		(1	)		4,029		13.03	100% on January 1, 2012

(1)	Restricted shares

(2)	Restricted stock units

There were no stock option grants in the three and six month periods ended June 30, 2010 and 2009.

Compensation cost is recognized over the respective vesting periods on a straight-line basis. There was no compensation cost associated with stock options for the three and six month periods ended June 30, 2010 as all outstanding stock options have vested. We recorded $0.1 million of compensation expense related to the final vesting of stock options in the first quarter of 2009. For the three and six month periods ended June 30, 2010, $2.1 million and $4.6 million, respectively, was recognized as compensation expense related to restricted shares as compared with $2.3 million and $4.6 million during the three and six month periods ended June 30, 2009, respectively.

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 price and the payment amount will fluctuate based on the common stock’s performance. This share based component is considered a liability plan under the guidance of ACS Topic No. 718 “Compensation – Stock

Compensation” 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 $14.7 million in 2009, including $8.1 million for our executive officers, which vest over a five year period. In January 2010, $10.1 million was awarded under the 2009 LTI Plan to eligible employees, including $6.0 million to our executive officers and other members of senior management. Total compensation under the 2009 LTI plan totaled $0.9 million and $2.6 million for the three and six month periods ended June 30, 2010, respectively. For the three and six month periods ended June 30, 2009, total compensation under the 2009 LTI plan totaled $0.7 million and $1.4 million, respectively.

For more information regarding our stock-based compensation plans, including our 2009 LTI Plan see Note 13 of our 2009 Form 10-K.

Business Segment Information (in thousands)

6 Months Ended

Jun. 30, 2010

Notes To Financial Statements [Abstract]

Business Segment Information (in thousands)

Note 14 – Business Segment Information

Our operations are conducted through two lines of business: contracting services and oil and gas. We have disaggregated our contracting services operations into two continuing reportable segments in accordance with ASC Topic No 280 “Segment Reporting”: Contracting Services and Production Facilities. As a result, our reportable segments consisted of the following: Contracting Services, Oil and Gas, and Production Facilities. Contracting Services operations include deepwater pipelay, well operations and robotics. Formerly, we had a third contracting services business, Shelf Contracting, which consisted of CDI’s operations, and which included all assets deployed primarily for diving-related activities and shallow water construction. On June 10, 2009, we ceased consolidating CDI when our ownership interest decreased to below 50% following the sale of a portion of CDI common stock held by us (Note 4). We continued to disclose the results of Shelf Contracting business as a segment up to and through June 10, 2009. All material intercompany transactions between the segments have been eliminated.

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. For our Production Facilities segment, we account for our investments in the Deepwater Gateway and Independence Hub under the equity method and we consolidate our investment in the HP I.

		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2010			2009			2010			2009
		(in thousands)
Revenues ─
Contracting Services	$	202,317		$	239,476		$	356,517		$	470,331
Shelf Contracting		–			197,656			–			404,709
Oil and Gas (1)		102,586			89,992			193,301			250,173
Production Facilities(2)		21,391			1,120			22,711			1,120
Intercompany elimination		(27,032	)		(33,605	)		(71,697	)		(60,719	)
Total	$	299,262		$	494,639		$	500,832		$	1,065,614

Income (loss) from operations ─
Contracting Services	$	43,781		$	34,636		$	71,267		$	74,384
Shelf Contracting		–			38,145			–			59,077
Oil and Gas (1)		(154,943	)		42,945			(155,607	)		188,128
Production Facilities (2)		12,977			(1,018	)		12,940			(1,152	)
Corporate (3)		(12,597	)		(11,253	)		(35,475	)		(21,772	)
Intercompany elimination		(6,114	)		(1,631	)		(18,419	)		(1,921	)
Total	$	(116,896	)	$	101,824		$	(125,294	)	$	296,744

Equity in earnings of equity investments	$	1,656		$	6,264		$	6,711		$	13,767

(1)	Included $73.5 million of disputed accrued royalty payments that we reversed in first quarter of 2009 following a favorable court ruling (Note 6).

(2)	Included the operating results related to the HP I.

(3)	Included $13.8 million of $17.5 million settlement of a third party claim against us in March 2010 (Note 16).

Intercompany segment revenues during the three and six month periods ended June 30, 2010 and 2009 were as follows:

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2010		2009		2010		2009
		(in thousands)
Contracting Services	$	24,426	$	28,951	$	68,167	$	52,854
Shelf Contracting		–		4,654		–		7,865
Production Facilities		2,606		–		3,530		–
Total	$	27,032	$	33,605	$	71,697	$	60,719

Intercompany segment gross profit (losses) during the three and six month periods ended June 30, 2010 and 2009 were as follows:

		Three Months Ended					Six Months Ended
		June 30,					June 30,
		2010		2009			2010		2009
		(in thousands)
Contracting Services	$	3,701	$	1,551		$	15,143	$	1,447
Shelf Contracting		–		109			–		503
Production Facilities		2,413		(29	)		3,293		(29	)
Total	$	6,114	$	1,631		$	18,436	$	1,921

Our identifiable assets as of June 30, 2010 and December 31, 2009 were as follows:

	June 30, 2010		December 31, 2009
		(in thousands)
Identifiable Assets ─
Contracting Services	$	1,757,811	$	1,738,005
Oil and Gas		1,321,817		1,541,153
Production Facilities		526,120		499,497
Assets of discontinued operations		825		878
Total	$	3,606,573	$	3,779,533

Related Party Transactions	6 Months Ended
Related Party Transactions	Jun. 30, 2010
Notes To Financial Statements [Abstract]
Related Party Transactions	Note 15 – Related Party Transactions In April 2000, we acquired a 20% working interest in Gunnison, a Deepwater Gulf of Mexico prospect. 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. 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. Production began in December 2003. Our payments to OKCD totaled $3.0 million and $6.1 million for the three and six month periods ended June 30, 2010, respectively, and $2.6 million and $5.4 million in the three and six month periods ended June 30, 2009, respectively.

- Definition

This element may be used for the entire related party transactions disclosure as a single block of text. Disclosure may include: the nature of the relationship(s), a description of the transactions, the amount of the transactions, the effects of any change in the method of establishing the terms of the transaction from the previous period, stated interest rate, expiration date, terms and manner of settlement per the agreement with the related party, and amounts due to or from related parties. If the entity and one or more other entities are under common ownership or management control and this control affects the operating results or financial position, disclosure includes the nature of the control relationship even if there are no transactions between the entities. Disclosure may also include the aggregate amount of current and deferred tax expense for each statement of earnings presented where the entity is a member of a group that files a consolidated tax return, the amount of any tax related balances due to or from affiliates as of the date of each statement of financial position presented, the principal provisions of the method by which the consolidated amount of current and deferred tax expense is allocated to the members of the group and the nature and effect of any changes in that method. Examples of related party transactions include transactions between (a) a parent company and its subsidiary; (b) subsidiaries of a common parent; (c) and entity and its principal owners; and (d) affiliates.

+ References+ Details

Commitments and Contingencies	6 Months Ended
Commitments and Contingencies	Jun. 30, 2010
Notes To Financial Statements [Abstract]
Commitments and Contingencies	Note 16 – Commitments and Contingencies Commitments We completed the conversion of the Caesar (acquired in January 2006 for $27.5 million in cash) into a deepwater pipelay vessel. The Caesar was placed in service in the second quarter of 2010. There will be some additional capital upgrades to the vessel that will be performed at a later date. Capitalized costs incurred for the vessel as of June 30, 2010 totaled $279.6 million (including capitalized interest of $24.4 million). There were $4.9 million of additional committed capital expenditures for the Caesar at June 30, 2010. We also plan for future spending of approximately $23.4 million of capital for additional Caesar upgrades. Further, we, along with Kommandor Rømø, a Danish corporation, formed a joint venture company called Kommandor and converted a ferry vessel into a floating production unit, the HP I. The total cost of the ferry and the conversion was approximately $150 million. We provided $98.9 million in interim construction financing to the joint venture. During 2009, $58.8 million of this amount was converted to equity in our investment in Kommandor. Kommandor Rømø provided a $5.0 million loan to Kommandor, the remaining balance of which was $2.5 million at June 30, 2010. Upon completion of the initial conversion, which occurred in April 2009, we chartered the HP I from Kommandor, and have installed, at 100% our cost, processing facilities and a disconnectable fluid transfer system on the HP I. This work was completed in the second quarter of 2010 and the HP I is now in service at the oil spill site at the Macondo well. Following its release from the oil spill site, the HP I will mobilize to the Phoenix field where production is expected to commence late in the third quarter of 2010. The final total cost of processing facilities approximates $200 million (including capitalized interest of $16.9 million). As of June 30, 2010, we have committed to spend $3.7 million in additional capital expenditures on our HP I processing facilities. We have consolidated Kommandor in all periods presented in the accompanying consolidated financial statements. The results of Kommandor are included within our Production Facilities segment. As of June 30, 2010, we planned to spend approximately $5.8 million for additional capital improvements to the newly constructed Well Enhancer vessel and have committed to spend $25.1 million in additional capital expenditures for exploration, development and drilling costs related to our oil and gas properties. Contingencies 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. Litigation and Claims In March 2009, we were notified of a third party’s intention to terminate an international construction contract based on a claimed breach of that contract by one of our subsidiaries. Under the terms of the contract, our potential liability was generally capped for 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 agreement, we paid the third party $15 million AUD to settle all their damage claims against us. We also agreed not to seek any further payment of our counter claims against them. In the first quarter of 2010, we recorded 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 general and administrative expenses in the accompanying condensed consolidated statements of operations. In 2008, we were subcontracted by the prime contractor to perform development work for a large gas field offshore India. Work commenced in the fourth quarter of 2008 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 receivable 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 in which it asserts 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. At the time of this filing we believe we will collect our trade receivable balance and we are continuing our efforts to actively pursue our other claim amounts but do not yet have the approvals necessary to recognize additional revenue. See Note 6 for information involving certain disputed royalty payments, which were recognized as oil and gas revenues in the first quarter of 2009.

Fair Value Measurements and Recent Accounting Standards

6 Months Ended

Jun. 30, 2010

Notes To Financial Statements [Abstract]

Fair Value Measurements and Recent Accounting Standards

Note 17 – Fair Value Measurements and Recent Accounting Standards

Fair Value Measurements

We follow the provisions of the ASC 820, Fair Value Measurements and Disclosures, for financial assets and liabilities that are measured and reported at fair value on a recurring basis. ASC 820 establishes 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 June 30, 2010 (in thousands):

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

Assets:
Oil and gas swaps and collars	$	–	$	15,373	$	–	$	15,373	(c)
Investment in Cal Dive		2,925		–		–		2,925	(a)

Liabilities:
Oil and gas swaps and collars		–		2,804		–		2,804	(c)
Fair value of long term debt(2)		1,148,754		127,819				1,276,573	(a), (b)
Foreign currency forwards		–		1,231		–		1,231	(c)
Interest rate swaps		–		1,695		–		1,695	(c)
Total net liability	$	1,145,829	$	118,176	$	–	$	1,264,005

(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 9 for additional information regarding our long term debt. The fair value of our long term debt at June 30, 2010 is as follows:

	Fair Value		Carrying Value
Term Loan (matures July 2013)	$	381,658	$	412,603
Revolving Credit Facility (matures November 2012)		–		–
Convertible Senior Notes (matures March 2025)		261,489		277,200
Senior Unsecured Notes (matures January 2016)		503,250		550,000
MARAD Debt (matures August 2027) (a)		127,819		117,050
Loan Note(b)		2,537		2,537
Total	$	1,276,753	$	1,359,390

(a)

The estimated fair value of all debt, other than MARAD Debt and Loan Note, 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 note approximates fair value as the maturity date is current.

We account for long-lived assets in accordance with ASC 360-10-35, Impairment of Disposal of Long-Lived Assets, and 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.

At June 30, 2010 we impaired 15 of our Gulf of Mexico properties as a result of reductions in estimates of proved reserves. The total amount of these impairment charges were $159.9 million, which reduced the carrying value of these properties to their aggregate fair value of $62.5 million. 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 . The total amount of the impairment charges were $7.0 million, which reduced these properties to their aggregate fair value of $28.2 million. See Note 6 for additional information regarding our oil and gas property impairment charges.

Recent Accounting Pronouncements

In January 2010, the Financial Accounting Standard Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2010-06, “Improving Disclosures about Fair Value Measurements” an amendment to ASC Topic 820. This amendment requires an entity to: (i) disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reason for the transfers and (ii) present separate information for Level 3 activity pertaining to gross purchases, sales, issuances, and settlements. This amendment is effective for interim and annual reporting periods beginning after December 15, 2009. We adopted this ASU effective January 1, 2010.

Derivative Instruments and Hedging Activities

6 Months Ended

Jun. 30, 2010

Notes To Financial Statements [Abstract]

Derivative Instruments and Hedging Activities

Note 18 – 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 our balance sheet at fair value unless otherwise noted, and do not contain credit-risk related or other contingent features that could cause accelerated payments when our derivative liabilities are in net liability positions.

We engage only 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, 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. Further, when we have obligations and receivables with the same counterparty, the fair value of the derivative liability and asset are presented at net value.

For additional information regarding our accounting for derivatives see Notes 2 and 22 of our 2009 Form 10-K.

Commodity Price Risks

We currently manage commodity price risks through various financial costless collars and swap instruments covering a portion of our anticipated oil and natural gas production for 2010. In the past, we have also utilized forward sales contracts that require physical delivery of oil and natural gas. We seek hedge accounting treatment for our oil and gas commodity derivative contracts. However, due to disruptions in our production as a result of damages caused by the hurricanes in third quarter 2008, most of our financial commodity contracts in place at March 31, 2009 no longer qualified for hedge accounting. Our forward sales contracts were not within the scope of SFAS No. 133 as they qualified for the normal purchases and sales scope exception. However, due to disruptions in our production as a result of damages caused by the hurricanes, as mentioned above, they no longer qualified for the scope exception. As a result, both our oil and natural gas commodity contracts and our natural gas normal purchase and sale contracts were required to be mark-to-market effective March 31, 2009. Changes in the fair value of these mark to market oil and gas derivative contracts are reflected in our accompanying condensed consolidated statements of operations in the line titled “Gain on oil and gas derivative contracts.”

Until June 2010 all of our oil and gas commodity contracts for expected 2010 production qualified for hedge accounting. In June 2010 some of our oil contracts for 480 MBbl covering portions of our anticipated production during the third quarter of 2010 ceased to qualify for hedge accounting as a result of our decision to contract the HP I to BP to assist in the oil spill containment response rather than commencing production from our Phoenix field. The HP I will return to the Phoenix field following its release from the oil spill site and first production is now anticipated late in the third quarter of 2010. All of our remaining commodity derivative contracts are designated as cash flow hedges remain effective and qualify for hedge accounting as of June 30, 2010 (Note 18). The amount of ineffectiveness related to our oil and gas commodity contracts was immaterial for all periods presented in this Quarterly Report on Form 10-Q.

As of June 30, 2010, we have the following volumes under derivative contracts related to our oil and gas producing activities totaling approximately 1,710 MMBbl of oil and 16.4 Bcf of natural gas:

Production Period	Instrument Type	Average Monthly Volumes	Weighted Average Price
Crude Oil:			(per barrel)
July 2010 — December 2010	Collar	100 MBbl	$62.50-$80.73
July 2010 — December 2010	Swap	105 MBbl	$76.55
October 2010 — December 2010	Swap	160 MBbl	$81.44

Natural Gas:			(per Mcf)
July 2010 — December 2010	Swap	970.0 Mmcf	$5.81
July 2010 — December 2010	Collar	1,012.0 Mmcf	$6.00 — $6.70
January 2011 — December 2011	Swap	375.0 Mmcf	$5.44

In July 2010, we entered into contracts for 450 MBbls of oil at a contract price of $82.00 per barrel, representing a portion of our anticipated production for 2011. 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 have 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 9). 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 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”. Ineffectiveness related to our interest swaps was immaterial for all periods presented in this Quarterly Report on Form 10-Q.

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 shipyard contracts where the contractual payments are denominated in Euros and expected cash outflows relating to certain vessel charters denominated in British pounds. We will have open foreign exchange contracts until the last one settles 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 June 30, 2010 and December 31, 2009. As required by ASC Topic No. 815 “Derivatives and Hedging”, 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. As a result, the amounts below may not agree with the amounts presented on our condensed consolidated balance sheet and the fair value information presented for our derivative instruments (Note 17).

Derivatives designated as hedging instruments under ASC Topic No. 815:

	As of June 30, 2010			As of December 31, 2009
	Balance Sheet Location		Fair Value	Balance Sheet Location		Fair Value
	(in thousands)
Asset Derivatives:
Oil contracts	Other current assets	$	368	Other current assets	$	—
Natural gas contracts	Other current assets		13,106	Other current assets		5,071
Natural gas contracts	Other assets, net		67	Other assets, net		—
Interest rate swaps	Other assets, net		—	Other assets, net		—
		$	13,541		$	5,071

	As of June 30, 2010			As of December 31, 2009
	Balance Sheet Location		Fair Value	Balance Sheet Location		Fair Value
	(in thousands)
Liability Derivatives:
Oil contracts	Accrued liabilities	$	2,804	Accrued liabilities	$	19,477
Natural gas contracts	Accrued liabilities		—	Accrued liabilities		59
Interest rate swaps	Accrued liabilities		1,368	Accrued liabilities		—
Interest rate swaps	Other liabilities		327	Other liabilities		—
		$	4,499		$	19,536

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

	As of June 30, 2010			As of December 31, 2009
	Balance Sheet Location		Fair Value	Balance Sheet Location		Fair Value
	(in thousands)
Asset Derivatives:
Natural gas contracts	Other current assets	$	—	Other current assets	$	—
Oil contracts	Other current assets		1,832	Other current assets		—
Foreign exchange forwards	Other current assets		—	Other current assets		1,143
Foreign exchange forwards	Other assets, net		—	Other assets, net		931
		$	1,832		$	2,074

Liability Derivatives:
Foreign exchange forwards	Accrued liabilities		936	Accrued liabilities		—
Foreign exchange forwards	Other liabilities		295	Other liabilities		—
		$	1,231		$	—

The following tables present the impact that derivative instruments designated as cash flow hedges had on our accumulated comprehensive loss and our condensed consolidated statements of operations for the three and six month periods ended June 30, 2010 and 2009.

		Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)
		Three Months Ended June 30,						Six Months Ended June 30,
		2010(1)			2009			2010(1)			2009
		(in thousands)
Oil and natural gas commodity contracts	$	2,575		$	(10,110	)	$	17,205		$	(14,377	)
Foreign exchange forwards		—			26			—			(556	)
Interest rate swaps		(512	)		1,211			(1,102	)		1,595
	$	2,063		$	(8,873	)	$	16,103		$	(13,338	)

(1)

All unrealized gains (losses) related to our derivatives are expected to be reclassified into earnings within the next 12 months, except for amounts related to our interest swaps and foreign exchange forwards, for which we have open contracts that have maturities through January and June of 2012, respectively.

	Location of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)		Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
			Three Months Ended June 30,						Six Months Ended June 30,
			2010			2009			2010			2009

Oil and natural gas commodity contracts	Oil and gas revenue	$	9,663		$	6,275		$	10,464		$	15,861
Interest rate swaps	Net interest expense and other		(469	)		(631	)		(887	)		(1,285	)
		$	9,194		$	5,644		$	9,577		$	14,576

The following table presents the impact of derivative instruments that no longer qualify for hedge accouting or were not designated as hedges on our condensed consolidated income statement for the three and six month periods ended June 30, 2010 and 2009 :

	Location of Gain (Loss) Recognized in Income on Derivatives		Gain (Loss) Recognized in Income on Derivatives
			Three Months Ended June 30,						Six Months Ended June 30,
			2010			2009			2010			2009
			(in thousands)
Natural gas contracts	Gain on oil and gas derivative contracts	$	2,482		$	4,122		$	2,482		$	78,730
Foreign exchange forwards	Net interest expense and other		(398	)		4,497			(3,305	)		5,143
Interest rate swaps	Net interest expense and other		—			(283	)		—			(295	)
		$	2,084		$	8,336		$	(823	)	$	83,578

Share Repurchase Program	6 Months Ended
Share Repurchase Program	Jun. 30, 2010
Notes To Financial Statements [Abstract]
ShareRepurchaseProgramTextBlock	Note 19 – Share Repurchase Program In June 2009, we announced that we intended to purchase up to 1.5 million shares plus an amount equal to additional shares granted under the stock-based compensation plans (Note 13) of our common stock as permitted under our Credit Agreement. Our Board of Directors had previously granted us the authority to repurchase shares of our common stock in an amount equal to any equity grants made pursuant to our stock-based compensation plans. We may continue to make repurchases pursuant to this authority from time to time as additional equity grants are made under our stock based compensation plans based upon prevailing market conditions and other factors. All repurchases may be commenced or suspended at any time at the discretion of management. As of June 30, 2010, we had repurchased a total of 1,752,831 shares of our common stock for $21.5 million or an average of $12.28 per share. In early July 2010, we purchased the remaining 223,487 shares currently available under this plan for $2.5 million or an average $11.21 per share. We retire all shares repurchased.

Condensed Consolidated Guarantor and Non-Guarantor Financial Information

6 Months Ended

Jun. 30, 2010

Notes To Financial Statements [Abstract]

Condensed Consolidated Guarantor and Non-Guarantor Financial Information

Note 20 – Condensed Consolidated Guarantor and Non-Guarantor Financial Information

The payment of 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. (Cal Dive and its subsidies were never guarantors of the Senior Unsecured Notes). 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 relate 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 June 30, 2010
		Helix		Guarantors		Non-Guarantors			Consolidating Entries			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	251,755	$	5,035	$	13,211		$	—		$	270,001
Accounts receivable, net		48,594		76,445		50,201			—			175,240
Unbilled revenue		10,494		—		18,643			—			29,137
Income taxes receivable		57,289		—		18,635			(57,785	)		18,139
Other current assets		51,752		53,194		15,882			(18,297	)		102,531
Total current assets		419,884		134,674		116,572			(76,082	)		595,048
Intercompany		29,528		225,128		(180,176	)		(74,480	)		—
Property and equipment, net		250,258		1,717,731		702,722			(5,151	)		2,665,560
Other assets:
Equity investments		2,034,923		32,754		187,694			(2,067,677	)		187,694
Goodwill		—		45,107		31,027			—			76,134
Other assets, net		47,801		39,658		28,287			(33,609	)		82,137
Due from subsidiaries/parent		109,138		90,455		—			(199,593	)		—
	$	2,891,532	$	2,285,507	$	886,126		$	(2,456,592	)	$	3,606,573

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	53,794	$	82,418	$	27,763		$	—		$	163,975
Accrued liabilities		81,351		93,273		27,802			(272	)		202,154
Income taxes payable		—		75,333		—			(75,333	)		—
Current maturities of long-term debt		4,326		—		24,821			(17,751	)		11,396
Total current liabilities		139,471		251,024		80,386			(93,356	)		377,525
Long-term debt		1,235,477		—		112,517			—			1,347,994
Deferred income taxes		151,339		155,261		85,826			(8,774	)		383,652
Asset retirement obligations		—		165,799		—			—			165,799
Other long-term liabilities		1,326		2,992		714			77			5,109
Due to parent		—		—		134,623			(134,623	)		—
Total liabilities		1,527,613		575,076		414,066			(236,676	)		2,280,079
Convertible preferred stock		1,000		—		—			—			1,000
Total equity		1,362,919		1,710,431		472,060			(2,219,916	)		1,325,494
	$	2,891,532	$	2,285,507	$	886,126		$	(2,456,592	)	$	3,606,573

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(in thousands)

	As of December 31, 2009
		Helix		Guarantors		Non-Guarantors			Consolidating Entries			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	258,742	$	2,522	$	9,409		$	—		$	270,673
Accounts receivable, net		49,813		77,399		18,307			—			145,519
Unbilled revenue		9,425		480		17,254			—			27,159
Income taxes receivable		38,333		—		13,795			(43,636	)		8,492
Other current assets		54,144		68,910		16,331			(25,668	)		113,717
Total current assets		410,457		149,311		75,096			(69,304	)		565,560
Intercompany		106,408		149,796		(190,729	)		(65,475	)		—
Property and equipment, net		220,408		1,919,412		729,131			(5,245	)		2,863,706
Other assets:
Equity investments in unconsolidated affiliates		—		—		189,411			—			189,411
Equity investments in affiliates		2,123,169		29,649		—			(2,152,818	)		—
Goodwill, net		—		45,107		33,536			—			78,643
Other assets, net		48,822		41,669		22,919			(31,197	)		82,213
Due from subsidiaries/parent		73,867		64,775		—			(138,642	)		—
	$	2,983,131	$	2,399,719	$	859,364		$	(2,462,681	)	$	3,779,533

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	58,451	$	79,128	$	17,878		$	—		$	155,457
Accrued liabilities		81,021		104,450		15,136			—			200,607
Income taxes payable		—		54,955		—			(54,955	)		—
Current maturities of long-term debt		4,326		—		33,837			(25,739	)		12,424
Total current liabilities		143,798		238,533		66,851			(80,694	)		368,488
Long-term debt		1,233,504		—		114,811			—			1,348,315
Deferred income taxes		137,662		222,528		90,676			(8,259	)		442,607
Asset retirement obligations		—		176,657		5,742			—			182,399
Other long-term liabilities		924		2,495		766			77			4,262
Due to parent		—		—		99,352			(99,352	)		—
Total liabilities		1,515,888		640,213		378,198			(188,228	)		2,346,071
Convertible preferred stock		6,000		—		—			—			6,000
Total equity		1,461,243		1,759,506		481,166			(2,274,453	)		1,427,462
	$	2,983,131	$	2,399,719	$	859,364		$	(2,462,681	)	$	3,779,533

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(in thousands)

(Unaudited)

	Three Months Ended June 30, 2010
	Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated

Net revenues	$	33,670		$	186,247		$	100,086		$	(20,741	)	$	299,262
Cost of sales		18,158			317,157			72,345			(13,580	)		394,080
Gross profit (loss)		15,512			(130,910	)		27,741			(7,161	)		(94,818	)
Gain on oil & gas derivative contracts		—			2,482			—			—			2,482
Loss on sale of assets		—			—			(14	)		—			(14	)
Selling and administrative expenses		(13,583	)		(7,834	)		(3,531	)		402			(24,546	)
Income (loss) from operations		1,929			(136,262	)		24,196			(6,759	)		(116,896	)
Equity in earnings of investments		(69,604	)		3,612			1,656			65,992			1,656
Net interest expense and other		(15,292	)		(5,002	)		(1,888	)		—			(22,182	)
Income (loss) before income taxes		(82,967	)		(137,652	)		23,964			59,233			(137,422	)
Provision (benefit) for income taxes		(1,872	)		(49,351	)		1,221			(2,364	)		(52,366	)
Income from continuing operations		(81,095	)		(88,301	)		22,743			61,597			(85,056	)
Discontinued operations, net of tax		(27	)		—			10			—			(17	)
Net income (loss) applicable to Helix		(81,122	)		(88,301	)		22,753			61,597			(85,073	)
Less:net income applicable to noncontrolling interests		—			—			—			(444	)		(444	)
Preferred stock dividends		(34	)		—			—			—			(34	)
Net income (loss) applicable to Helix common shareholders	$	(81,156	)	$	(88,301	)	$	22,753		$	61,153		$	(85,551	)

	Three Months Ended June 30, 2009
	Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated

Net revenues	$	93,906		$	176,474		$	255,165		$	(30,906	)	$	494,639
Cost of sales		79,650			118,281			190,069			(29,117	)		358,883
Gross profit (loss)		14,256			58,193			65,096			(1,789	)		135,756
Gain on oil & gas derivative contracts		—			4,121			—			—			4,121
Gain on sale of assets		—			1,319			—			—			1,319
Selling and administrative expenses		(12,770	)		(7,610	)		(20,062	)		1,070			(39,372	)
Income (loss) from operations		1,486			56,023			45,034			(719	)		101,824
Equity in earnings of investments		71,904			1,642			6,625			(73,907	)		6,264
Gain on sale of Cal Dive common stock		59,442			—			—			—			59,442
Net interest expense and other		(5,490	)		(933	)		(767	)		(278	)		(7,468	)
Income (loss) before income taxes		127,342			56,732			50,892			(74,904	)		160,062
Provision (benefit) for income taxes		25,571			19,276			12,441			(479	)		56,809
Income from continuing operations		101,771			37,456			38,451			(74,425	)		103,253
Discontinued operations, net of tax		(424	)		—			10,260			—			9,836
Net income (loss) applicable to Helix		101,347			37,456			48,711			(74,425	)		113,089
Less:net income applicable to noncontrolling interests		—			—			—			(12,620	)		(12,620	)
Preferred stock dividends		(250	)		—			—			—			(250	)
Net income (loss) applicable to Helix common shareholders	$	101,097		$	37,456		$	48,711		$	(87,045	)	$	100,219

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(in thousands)

(Unaudited)

	Six Months Ended June 30, 2010
	Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated

Net revenues	$	54,692		$	355,970		$	145,058		$	(54,888	)	$	500,832
Cost of sales		31,492			457,199			122,302			(41,199	)		569,794
Gross profit (loss)		23,200			(101,229	)		22,756			(13,689	)		(68,962	)
Gain on oil & gas derivative contracts		—			2,482			—			—			2,482
Gain on sale of assets		—			287			5,946			—			6,233
Selling and administrative expenses		(37,458	)		(17,915	)		(10,576	)		902			(65,047	)
Income (loss) from operations		(14,258	)		(116,375	)		18,126			(12,787	)		(125,294	)
Equity in earnings of investments		(64,736	)		3,105			6,711			61,631			6,711
Net interest expense and other		(22,681	)		(12,568	)		(8,126	)		—			(43,375	)
Income (loss) before income taxes		(101,675	)		(125,838	)		16,711			48,844			(161,958	)
Provision (benefit) for income taxes		(6,668	)		(45,136	)		(3,650	)		(4,473	)		(59,927	)
Income from continuing operations		(95,007	)		(80,702	)		20,361			53,317			(102,031	)
Discontinued operations, net of tax		(27	)		—			(17	)		—			(44	)
Net income (loss) applicable to Helix		(95,034	)		(80,702	)		20,344			53,317			(102,075	)
Less:net income applicable to noncontrolling interests		—			—			—			(1,273	)		(1,273	)
Preferred stock dividends		(94	)		—			—			—			(94	)
Net income (loss) applicable to Helix common shareholders	$	(95,128	)	$	(80,702	)	$	20,344		$	52,044		$	(103,442	)

	Six Months Ended June 30, 2009
	Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated

Net revenues	$	189,988		$	412,731		$	517,182		$	(54,287	)	$	1,065,614
Cost of sales		142,352			267,825			409,262			(50,791	)		768,648
Gross profit		47,636			144,906			107,920			(3,496	)		296,966
Gain on oil & gas derivative contracts		—			78,730			—			—			78,730
Gain on sale of assets		—			1,773			—			—			1,773
Selling and administrative expenses		(24,630	)		(15,880	)		(42,574	)		2,359			(80,725	)
Income (loss) from operations		23,006			209,529			65,346			(1,137	)		296,744
Equity in earnings of investments		180,826			(2,162	)		14,128			(179,025	)		13,767
Gain on sale of Cal Dive common stock		59,442			—			—			—			59,442
Net interest expense and other		(14,609	)		(6,115	)		(7,952	)		(987	)		(29,663	)
Income (loss) before income taxes		248,665			201,252			71,522			(181,149	)		340,290
Provision (benefit) for income taxes		36,562			69,622			16,413			(869	)		121,728
Income from continuing operations		212,103			131,630			55,109			(180,280	)		218,562
Discontinued operations, net of tax		(2,816	)		—			10,098			—			7,282
Net income (loss) applicable to Helix		209,287			131,630			65,207			(180,280	)		225,844
Less:net income applicable to noncontrolling interests		—			—			—			(18,173	)		(18,173	)
Preferred stock dividends		(563	)		—			—			—			(563	)
Preferred stock beneficial conversion charges		(53,439	)		—			—			—			(53,439	)
Net income (loss) applicable to Helix common shareholders	$	155,285		$	131,630		$	65,207		$	(198,453	)	$	153,669

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

	Six Months Ended June 30, 2010
			Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated

Cash flow from operating activities:
Net income (loss), including noncontrolling interests		$	(95,034	)	$	(80,702	)	$	20,344		$	53,317		$	(102,075	)
Adjustments to reconcile net income (loss), including noncontrolling interests to net cash provided by (used in) operating activities:
Equity in earnings of affiliates			64,736			(3,105	)		—			(61,631	)		—
Other adjustments			17,776			243,919			(13,057	)		(10,119	)		238,519
Cash provided by (used in) continuing operations			(12,522	)		160,112			7,287			(18,433	)		136,444
Cash provided by (used in) discontinued operations			—			—			(44	)		—			(44	)
Net cash provided by (used in) operating
activities			(12,522	)		160,112			7,243			(18,433	)		136,400

Cash flows from investing activities:
Capital expenditures			(47,963	)		(80,203	)		(7,446	)		—			(135,612	)
Distributions from equity investments, net			—			—			1,825			—			1,825
Insurance recovery			7,020			9,086			—			—			16,106
Other			—			109			—			—			109
Net cash used in investing activities			(40,943	)		(71,008	)		(5,621	)		—			(117,572	)

Cash flows from financing activities:
Repayments of debt			(2,163	)		—			(2,403	)		—			(4,566	)
Deferred financing costs			(2,792	)		—			—			—			(2,792	)
Preferred stock dividends paid and other			69			—			(1,167	)		—			(1,098	)
Repurchase of common stock			(9,127	)		—			—						(9,127	)
Excess tax benefit from stock-based compensation			(2,163	)		—			—			—			(2,163	)
Intercompany financing			62,654			(86,591	)		5,504			18,433			—
Net cash provided by (used in) financing activities			46,478			(86,591	)		1,934			18,433			(19,746	)
Effect of exchange rate changes on cash and cash equivalents			—			—			246			—			246
Net increase (decrease) in cash and cash equivalents			(6,987	)		2,513			3,802			—			(672	)
Cash and cash equivalents:
Balance, beginning of year			258,742			2,522			9,409			—			270,673
Balance, end of period		$	251,755		$	5,035		$	13,211		$	—		$	270,001

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(in thousands)

	Six Months Ended June 30, 2009
			Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated

Cash flow from operating activities:
Net income, including noncontrolling interests		$	209,287		$	131,630		$	65,207		$	(180,280	)	$	225,844
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Equity in losses of unconsolidated
affiliates			—			—			(4,058	)		361			(3,697	)
Equity in earnings of affiliates			(180,826	)		2,162			—			178,664			—
Other adjustments			10,172			132,121			(132,954	)		197,507			206,846
Cash provided by (used in) operating activities			38,633			265,913			(71,805	)		196,252			428,993
Cash provided by discontinued operations			—			—			(6,121	)		—			(6,121	)
Net cash provided by (used in)
operating activities			38,633			265,913			(77,926	)		196,252			422,872
Cash flows from investing activities:
Capital expenditures			(12,303	)		(117,238	)		(108,861	)		—			(238,402	)
Investments in equity investments			—			—			(454	)		—			(454	)
Distributions from equity investments, net			—			—			3,253			—			3,253
Proceeds from sale of Cal Dive common stock			282,656			—			(112,995	)		(86,000	)		83,661
Proceeds from sales of property			—			23,238			—			—			23,238
Other			—			(15	)		—			—			(15	)
Cash provided by (used in) investing activities			270,353			(94,015	)		(219,057	)		(86,000	)		(128,719	)
Cash provided by discontinued operations			—			—			20,874			—			20,874
Net cash used in investing activities			270,353			(94,015	)		(198,183	)		(86,000	)		(107,845	)

Cash flows from financing activities:
Borrowings on revolver			—			—			100,000			—			100,000
Repayments on revolver			(349,500	)		—			—			—			(349,500	)
Repayments of debt			(2,163	)		—			(22,081	)		—			(24,244	)
Deferred financing costs			(28	)		—			—			—			(28	)
Preferred stock dividends paid			(500	)		—			—						(500	)
Repurchase of common stock			(753	)		—			(86,000	)		86,000			(753	)
Excess tax benefit from stock-based compensation			(754	)		—			—			—			(754	)
Exercise of stock options, net															—
Intercompany financing			141,528			(174,436	)		229,160			(196,252	)		—
Net cash provided by (used in) financing activities			(212,170	)		(174,436	)		221,079			(110,252	)		(275,779	)
Effect of exchange rate changes on cash and cash equivalents			—			—			(931	)		—			(931	)
Net increase (decrease) in cash and cash equivalents			96,816			(2,538	)		(55,961	)		—			38,317
Cash and cash equivalents:
Balance, beginning of year			148,704			4,983			69,926			—			223,613
Balance, end of period		$	245,520		$	2,445		$	13,965		$	—		$	261,930

- Definition

Text block that encapsulates the detailed table comprising the condensed financial statements (balance sheet, income statement and statement of cash flows), normally using the registrant (parent) as the sole domain member. If condensed consolidating financial statements are being presented, other domain members (in addition to parent) such as guarantor subsidiaries, non-guarantor subsidiaries, and the consolidation eliminations, will be included in order that the respective monetary amounts for each of the domains will aggregate to the respective amounts on the consolidated financial statements. The line items are the various captions used to compile the condensed financial statements. Using extensions, most, if not all, of the elements representing condensed financial statement captions will be the same as those used for the consolidated financial statements captions.

+ References+ Details

Document Information	6 Months Ended
Document Information	Jun. 30, 2010
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2010

Entity Information (USD $)	6 Months Ended
Entity Information (USD $)	Jun. 30, 2010	Jul. 27, 2010	Jun. 30, 2009
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	No
Entity Voluntary Filers	No
Entity Current Reporting Status	No
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 999,789,870
Entity Common Stock, Shares Outstanding		105,443,450
Document Fiscal Year Focus	2010
Document Fiscal Period Focus	Q2