10-Q

 UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

[X]	Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
	For the quarterly period ended June 30, 2011
	or
[   ]	Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
	For the transition period from__________ to__________

Commission File Number 001-32936

HELIX ENERGY SOLUTIONS GROUP, INC.

(Exact name of registrant as specified in its charter)

Minnesota (State or other jurisdiction of incorporation or organization)	95–3409686 (I.R.S. Employer Identification No.)
400 North Sam Houston Parkway East Suite 400 Houston, Texas (Address of principal executive offices)	77060 (Zip Code)

(281) 618–0400

(Registrant's telephone number, including area code)

NOT APPLICABLE

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

     Yes   [ √ ]      No  [  ] 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

     Yes   [ √   ]      No  [  ] 

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

Large accelerated filer [ √ ]  Accelerated filer   [    ]      Non-accelerated filer  [    ] 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

     Yes   [   ]      No  [ √ ] 

As of July 21, 2011, 105,943,676 shares of common stock were outstanding.

TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION	PAGE
Item 1.	Financial Statements:
	Condensed Consolidated Balance Sheets –   June 30, 2011 (Unaudited) and December 31, 2010	1
	Condensed Consolidated Statements of Operations (Unaudited) –   Three months ended June 30, 2011 and 2010	2
	Condensed Consolidated Statements of Operations (Unaudited) –   Six months ended June 30, 2011 and 2010	3
	Condensed Consolidated Statements of Cash Flows (Unaudited) –   Six months ended June 30, 2011 and 2010	4
	Notes to Condensed Consolidated Financial Statements (Unaudited)	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	48
Item 4.	Controls and Procedures	49
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	49
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	49
Item 6.	Exhibits	49
	Signatures	50
	Index to Exhibits	51

PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements.

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

 (in thousands)

	June 30,			December 31,
	2011			2010
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	414,189		$	391,085
Accounts receivable —      Trade, net of allowance for uncollectible accounts          of $4,395 and $4,527, respectively		212,406			177,293
Unbilled revenue		18,325			33,712
Costs in excess of billing		1,978			15,699
Other current assets		110,334			123,065
Total current assets		757,232			740,854
Property and equipment		4,586,583			4,486,077
Less — accumulated depreciation		(2,111,273	)		(1,958,997	)
		2,475,310			2,527,080
Other assets:
Equity investments		188,772			187,031
Goodwill		62,902			62,494
Other assets, net		76,421			74,561
Total assets	$	3,560,637		$	3,592,020
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	148,142		$	159,381
Accrued liabilities		190,226			198,237
Current maturities of long-term debt		7,759			10,179
Total current liabilities		346,127			367,797
Long-term debt		1,239,893			1,347,753
Deferred income taxes		431,821			413,639
Asset retirement obligations		166,458			170,410
Other long-term liabilities		5,432			5,777
Total liabilities		2,189,731			2,305,376
Convertible preferred stock		1,000			1,000
Commitments and contingencies
Shareholders’ equity:
Common stock, no par, 240,000 shares authorized,            105,948 and 105,592 shares issued, respectively		911,393			906,957
Retained earnings		459,875			392,705
Accumulated other comprehensive loss		(27,956	)		(39,058	)
Total controlling interest shareholders’ equity		1,343,312			1,260,604
Noncontrolling interests		26,594			25,040
Total equity		1,369,906			1,285,644
Total liabilities and shareholders’ equity	$	3,560,637		$	3,592,020

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

1

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

 (in thousands, except per share amounts)

		Three Months Ended
		June 30,
		2011			2010
Net revenues:
Contracting services	$	165,861		$	196,676
Oil and gas		172,458			102,586
		338,319			299,262
Cost of sales:
Contracting services		116,521			140,126
Oil and gas		98,879			94,092
Oil and gas property impairments		22,721			159,862
		238,121			394,080
Gross profit (loss)		100,198			(94,818	)
Gain on oil and gas derivative contracts		—			2,482
Gain (loss) on the sale or acquisition of assets, net		(22	)		(14	)
Selling and administrative expenses		(23,758	)		(24,546	)
Income (loss) from operations		76,418			(116,896	)
Equity in earnings of investments		5,887			1,656
Net interest expense		(25,278	)		(20,523	)
Other income (expense)		1,253			(1,676	)
Income (loss) before income taxes		58,280			(137,439	)
Provision (benefit) for income taxes		16,171			(52,366	)
Net income (loss), including noncontrolling interests		42,109			(85,073	)
Less net income applicable to noncontrolling interests		(786	)		(444	)
Net income (loss) applicable to  Helix		41,323			(85,517	)
Preferred stock dividends		(10	)		(34	)
Net income (loss) applicable to Helix common shareholders	$	41,313		$	(85,551	)
Earnings (loss) per share of common stock:
Basic	$	0.39		$	(0.82	)
Diluted	$	0.39		$	(0.82	)
Weighted average common shares outstanding:
Basic		104,673			104,125
Diluted		105,140			104,125

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

2

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

 (in thousands, except per share amounts)

		Six Months Ended
		June 30,
		2011			2010
Net revenues:
Contracting services	$	288,609		$	307,531
Oil and gas		341,317			193,301
		629,926			500,832
Cost of sales:
Contracting services		223,428			226,374
Oil and gas		206,503			172,446
Oil and gas property impairments		22,721			170,974
		452,652			569,794
Gross profit (loss)		177,274			(68,962	)
Gain on oil and gas derivative contracts		—			2,482
Gain (loss) on sale or acquisition of assets, net		(6	)		6,233
Selling and administrative expenses		(48,739	)		(65,047	)
Income (loss) from operations		128,529			(125,294	)
Equity in earnings of investments		11,537			6,711
Gain on sale of Cal Dive common stock		753			—
Net interest expense		(49,514	)		(36,158	)
Other income (expense)		3,160			(7,261	)
Income (loss) before income taxes		94,465			(162,002	)
Provision (benefit) for income taxes		25,721			(59,927	)
Net income (loss), including noncontrolling interests		68,744			(102,075	)
Less net income applicable to noncontrolling interests		(1,554	)		(1,273	)
Net income (loss) applicable to Helix		67,190			(103,348	)
Preferred stock dividends		(20	)		(94	)
Net income (loss) applicable to Helix common shareholders	$	67,170		$	(103,442	)
Earnings (loss) per share of common stock:
Basic	$	0.63		$	(1.00	)
Diluted	$	0.63		$	(1.00	)
Weighted average common shares outstanding:
Basic		104,573			103,610
Diluted		105,024			103,610

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

3

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

 (in thousands)

		Six Months Ended
		June 30,
		2011			2010
Cash flows from operating activities:
Net income (loss), including noncontrolling interests	$	68,744		$	(102,075	)
Adjustments to reconcile net income (loss), including noncontrolling interests to net cash provided by operating activities
Depreciation and amortization		167,170			146,268
Asset impairment charge and dry hole expense		29,352			170,784
Amortization of deferred financing costs		4,777			3,768
Stock compensation expense		4,938			4,589
Amortization of debt discount		4,414			4,136
Deferred income taxes		23,864			(54,749	)
Excess tax benefit from stock-based compensation		1,196			2,163
Gain on investment in Cal Dive common stock		(753	)		—
(Gain) loss on sale or acquisition of assets		6			(6,233	)
Unrealized (gain) loss on derivative contracts		(34	)		2,813
Changes in operating assets and liabilities:
Accounts receivable, net		(18,207	)		(30,591	)
Other current assets		12,712			16,477
Income tax payable		(4,154	)		(10,811	)
Accounts payable and accrued liabilities		(27,070	)		28,027
Oil and gas asset retirement costs		(16,073	)		(28,727	)
Other noncurrent, net		(309	)		(9,439	)
Net cash provided by operating activities		250,573			136,400
Cash flows from investing activities:
Capital expenditures		(106,122	)		(135,612	)
Investments in equity investments		(2,699	)		(6,307	)
Distributions from equity investments, net		1,593			8,132
Proceeds from sale of Cal Dive common stock		3,588			—
Insurance recovery for capital items		—			16,106
Decrease in restricted cash		863			109
Net cash used in investing activities		(102,777	)		(117,572	)
Cash flows from financing activities:
Borrowing under revolving credit facility		109,400			—
Repayment of revolving credit facility		(109,400	)		—
Repayment of Helix Term Loan		(111,191	)		(2,163	)
Repayment of MARAD borrowings		(2,294	)		(2,403	)
Loan notes repayment		(1,213	)		(1,167	)
Deferred financing costs		(9,014	)		(2,792	)
Preferred stock dividends paid		(20	)		(94	)
Repurchases of common stock		(1,012	)		(9,127	)
Excess tax benefit from stock-based compensation		(1,196	)		(2,163	)
Exercise of stock options, net		1,672			163
Net cash used in financing activities		(124,268	)		(19,746	)
Effect of exchange rate changes on cash and cash equivalents		(424	)		246
Net increase (decrease) in cash and cash equivalents		23,104			(672	)
Cash and cash equivalents:
Balance, beginning of year		391,085			270,673
Balance, end of period	$	414,189		$	270,001

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

4

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 – Basis of Presentation

The accompanying condensed consolidated financial statements include the accounts of Helix Energy Solutions Group, Inc. and its majority-owned subsidiaries (collectively, "Helix" or the "Company"). Unless the context indicates otherwise, the terms "we," "us" and "our" in this report refer collectively to Helix and its majority-owned subsidiaries.   All material intercompany accounts and transactions have been eliminated. These unaudited condensed consolidated financial statements have been prepared pursuant to instructions for the Quarterly Report on Form 10-Q required to be filed with the Securities and Exchange Commission (“SEC”), and do not include all information and footnotes normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles.

The accompanying condensed consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles and are consistent in all material respects with those applied in our 2010 Annual Report on Form 10-K (“2010 Form 10-K”).  The preparation of these financial statements requires us to make estimates and judgments that affect the amounts reported in the financial statements and the related disclosures.  Actual results may differ from our estimates.  Management has reflected all adjustments (which were normal recurring adjustments unless otherwise disclosed herein) that it believes are necessary for a fair presentation of the condensed consolidated balance sheets, results of operations, and cash flows, as applicable. The operating results for the periods ended June 30, 2011 are not necessarily indicative of the results that may be expected for the year ending December 31, 2011. Our balance sheet as of December 31, 2010 included herein has been derived from the audited balance sheet as of December 31, 2010 included in our 2010 Form 10-K. These unaudited condensed consolidated financial statements should be read in conjunction with the annual audited consolidated financial statements and notes thereto included in our 2010 Form 10-K.

Certain reclassifications were made to previously reported amounts in the condensed consolidated financial statements and notes thereto to make them consistent with the current presentation format, including reclassifying the previously recorded results associated with our discontinued operations.  The discontinued operations results are now reflected as a component of other income (expense) in the accompanying condensed consolidated statement of operations as such amounts are immaterial for all the periods presented in this Quarterly Report on Form 10-Q.

Note 2 – Company Overview

We are an international offshore energy company that provides reservoir development solutions and other contracting services to the energy market as well as to our own oil and gas properties. Our Contracting Services segment utilizes our vessels, offshore equipment and methodologies to deliver services that may reduce finding and development costs and encompass the complete lifecycle of an offshore oil and gas field. Our Contracting Services are located primarily in 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 exclusively located in the Gulf of Mexico.

Contracting Services Operations

We seek to provide services and methodologies which we believe are critical to finding and developing offshore reservoirs and maximizing production economics.  Our “life of field” services are segregated into four disciplines: subsea construction, well operations, robotics and production facilities. We have disaggregated our contracting services operations into two reportable segments: Contracting Services and Production Facilities. Our Contracting Services business primarily includes subsea construction, deepwater pipelay, well operations and robotics activities.  Our Production Facilities business includes our investments in Deepwater Gateway, L.L.C. (“Deepwater Gateway”) and Independence Hub, LLC (“Independence Hub”) as well as our majority ownership of the Helix Producer I (“HP I”) vessel.   We have developed a response system that has been referenced as a designated spill response solution in Gulf of Mexico permit applications (see “Events in Gulf of Mexico” below).

5

Oil and Gas Operations

We began our oil and gas operations to provide a more efficient solution to offshore abandonment, to expand our off-season utilization of our contracting services assets and to achieve incremental returns. We have evolved this business model to include not only mature oil and gas properties but also proved and unproved reserves yet to be developed and explored. This has led to the assembly of services that allows us to create value at key points in the life of a reservoir from exploration through development, life of field management and operating through abandonment.

Events in Gulf of Mexico

In April 2010, an explosion occurred on the Deepwater Horizon drilling rig located on the site of the Macondo well at Mississippi Canyon Block 252.  The resulting events included loss of life, the complete destruction of the drilling rig and an oil spill, the magnitude of which was unprecedented in U.S. territorial waters.  In May 2010, the U.S. Department of Interior (“DOI”) announced a total moratorium on new drilling in the Gulf of Mexico.   In October 2010, the DOI lifted the drilling moratorium and instructed the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”) that it could resume issuing drilling permits conditioned on the requesting company’s compliance with all revised drilling, safety and environmental requirements.   No deepwater drilling permits were issued in the period from October 2010 through late February 2011.  In late February 2011, the BOEMRE commenced issuing deepwater permits.    At the time of this filing 24 deepwater permits have been issued, 14 of which were issued referencing the Helix Fast Response System as further discussed below.

We developed the Helix Fast Response System (“HFRS”) as a culmination of our experience as a responder in the Macondo oil spill response and containment efforts.  The HFRS centers on two vessels, the HP I and the Q4000, both of which played a key role in the Macondo oil spill response and containment efforts and are presently operating in the Gulf of Mexico.  In 2011, we signed an agreement with Clean Gulf Associates ("CGA"), a non-profit industry group, allowing, in exchange for a retainer fee, the HFRS to be named as a response resource in permit applications to federal and state agencies and making the HFRS available for a two-year term to certain CGA participants who have executed utilization agreements with us. In addition to the agreement with CGA, we currently have signed separate utilization agreements with 24 CGA participant member companies specifying the day rates to be charged should the HFRS solution be deployed in connection with a well control incident.  The retainer fee for the HFRS became effective April 1, 2011 and is a component of our Production Facilities business segment.   A total of 14 permits have been granted to CGA participants for deepwater drilling operations identifying the HFRS to fulfill the BOERME requirement to have a spill response solution included in the submitted permit applications.

New Accounting Pronouncement

In June 2011, the Financial Accounting Standards Board (“FASB”) issued an update to existing guidance on the presentation of comprehensive income. This update will require the presentation of the components of net income and other comprehensive income either in a single continuous statement or in two separate but consecutive statements. In addition, companies are also required to present reclassification adjustments for items that are reclassified from other comprehensive income to net income on the face of the financial statements. The update is effective for fiscal years and interim periods beginning after December 15, 2011. We will adopt the new disclosure requirements for comprehensive income beginning January 1, 2012 and are currently evaluating the provisions of this update.

6

Note 3 – Details of Certain Accounts

Other current assets consisted of the following as of June 30, 2011 and December 31, 2010:

	June 30,		December 31,
	2011		2010
	(in thousands)
Other receivables	$	854	$	1,247
Prepaid insurance		12,141		12,375
Other prepaids		12,692		11,623
Spare parts inventory		21,850		25,333
Current deferred tax assets		37,533		49,200
Hedging assets		5,988		5,472
Gas imbalance		5,961		6,001
Income tax receivable		9,059		6,099
Investment held for sale (a)		—		2,835
Other		4,256		2,880
	$	110,334	$	123,065

a.   In March 2011, we sold our remaining 500,000 shares of Cal Dive common stock.  These sales transactions resulted in net proceeds of approximately $3.6 million and a pre-tax gain of $0.8 million.   In the fourth quarter of 2010, we recognized a $2.2 million other than temporary loss on our investment in Cal Dive common shares (see Notes 2 and 3 of our 2010 Form 10-K for additional information regarding our former Investment in Cal Dive common stock).

Other assets, net, consisted of the following as of June 30, 2011 and December 31, 2010:

	June 30,		December 31,
	2011		2010
	(in thousands)
Restricted cash	$	34,476	$	35,339
Deferred drydock expenses, net		7,616		11,086
Deferred financing costs, net		30,127		25,697
Intangible assets with finite lives, net		602		636
Other		3,600		1,803
	$	76,421	$	74,561

Accrued liabilities consisted of the following as of June 30, 2011 and December 31, 2010:

	June 30,		December 31,
	2011		2010
	(in thousands)
Accrued payroll and related benefits	$	33,148	$	38,026
Royalties payable		17,115		15,008
Current asset retirement obligations		64,349		64,526
Unearned revenue		8,504		4,094
Billing in excess of cost		6,346		3,869
Accrued interest		27,347		27,308
Hedge liability		17,212		30,606
Other		16,205		14,800
	$	190,226	$	198,237

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Note 4 – Oil and Gas Properties

We follow the successful efforts method of accounting for our interests in oil and gas properties. Under the successful efforts method, the costs of drilling and equipping 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.

Impairments

During the three-month period ended June 30, 2011, we recorded impairment charges totaling $22.7 million, including $4.1 million for  our only non-domestic oil and gas property (see “United Kingdom Property” below), and for  six of our Gulf of Mexico oil and gas properties.   These impairment charges primarily reflect a premature end of these fields’ production life either through actual depletion or as a result of capital allocation decisions affecting our third party operated fields.  We did not have any impairment of our oil and gas properties in the first quarter of 2011. 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 U.K oil and gas property.  

Exploration and Other

As of June 30, 2011, we capitalized approximately $3.6 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, 2011 and 2010 (in thousands):

		Three Months Ended					Six Months Ended
		June 30,					June 30,
		2011		2010			2011			2010
Delay rental and geological and geophysical costs	$	1,299	$	1,182		$	1,654		$	1,528
Impairment of unproved properties (a)		6,640		—			6,640			—
Dry hole expense		—		(10	)		(9	)		(190	)
Total exploration expense	$	7,939	$	1,172		$	8,285		$	1,338

a.   Reflects costs associated with a deepwater lease in which the term expired during the second quarter of 2011.

8

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

Also in connection with this acquisition, we reassessed the fair value associated with our original 50% interest in the field. Based on these evaluations, we concluded that the Camelot field was impaired based on the unlikely probability of our expending the additional capital necessary to further develop the field.  As a result, we recorded a $4.1 million impairment charge to fully impair the property in the first quarter of 2010.  We are currently abandoning the field in accordance with applicable United Kingdom regulations. In connection with these activities, during the second quarter of 2011 we revised our estimated future field abandonment costs for the field, which resulted in our recording an incremental $4.1 million impairment charge to increase our asset retirement obligation to $12.1 million at June 30, 2011. We have incurred approximately $3.7 million of costs related to our reclamation activities at the Camelot field through June 30, 2011.

Asset retirement obligations

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

Asset retirement obligation at December 31, 2010	$	234,936
Liability incurred during the period		672
Liability settled during the period		(25,273	)
Revision in estimated cash flows		12,842
Accretion expense (included in depreciation and amortization)		7,630
Asset retirement obligations at June 30, 2011	$	230,807

Insurance

In September 2008, we sustained damage to certain of our oil and gas production facilities from Hurricanes Gustav and Ike.  We carried comprehensive insurance on all of our operated and non-operated producing and non-producing properties.  We record our hurricane-related costs as incurred. Insurance reimbursements are recorded when the realization of the claim for recovery of a loss is deemed probable.  We incurred $0.1 million of hurricane-related costs in the first half of 2011, which were totally offset by $4.7 million of insurance reimbursements.  Our hurricane-related costs, net of reimbursements totaled $1.6 million and $3.6 million for the three-month and six-month periods ended June 30, 2010.  Expense related to our hurricane catastrophic bond windstorm coverage was immaterial for all periods presented in this Quarterly Report on Form 10-Q.  On June 30, 2011, we renewed our hurricane catastrophic bond for the period July 1, 2011 to June 30, 2012 and made a payment of $10.6 million.   We will charge approximately $8.4 million of this payment to insurance expense in the third quarter of 2011 and $2.0 million in the fourth quarter of 2011 based upon the bond’s contractual intrinsic value at the end of each of those quarterly periods.

Note 5 – 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 $34.5 million at June 30, 2011 and $35.3 million at December 31, 2010,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. We have used a small portion of  these escrowed funds to pay for the initial reclamation activities at the South Marsh Island Block 130 field.  Reclamation activities at the field will occur over many years and will be  funded with these escrowed amounts.  These amounts are reflected in other assets, net in the accompanying condensed consolidated balance sheets.

9

The following table provides supplemental cash flow information for the six-month period ended June 30, 2011 and 2010 (in thousands):

		Six Months Ended
		June 30,
		2011		2010
Interest paid, net of capitalized interest(1)	$	40,220	$	27,847
Income taxes paid	$	7,236	$	6,642

Non-cash investing activities for the six-month periods ended June 30, 2011 and 2010 included $33.7 million and $32.0 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.

Note 6 – Equity Investments

As of June 30, 2011, we have three investments that we account for using the equity method of accounting: Deepwater Gateway, Independence Hub, and the Clough Helix Joint Venture Pty Ltd. (“Clough Helix JV”).  Deepwater Gateway and Independence Hub are included in our Production Facilities segment while the Clough Helix joint venture is a component of our Contracting Services segment.

·   Deepwater Gateway, L.L.C.  In June 2002, we, along with Enterprise Products Partners L.P. (”Enterprise”), formed Deepwater Gateway, each with a 50% interest, to design, construct, install, own and operate a tension leg platform production hub primarily for Anadarko Petroleum Corporation's Marco Polo field in the Deepwater Gulf of Mexico. Our investment in Deepwater Gateway totaled $98.3 million and $99.8 million as of June 30, 2011 and December 31, 2010, respectively (including capitalized interest of $1.4 million and $1.5 million at June 30, 2011 and December 31, 2010, respectively).  Distributions from Deepwater Gateway, net to our interest, totaled $1.8 million and $3.6 million for the respective three-month and six-month periods ended June 30, 2011.

·   Independence Hub, LLC.  In December 2004, we acquired a 20% interest in Independence Hub, an affiliate of Enterprise.  Independence Hub owns the "Independence Hub" platform located in Mississippi Canyon Block 920 in a water depth of 8,000 feet.  First production through the facility commenced in July 2007.  Our investment in Independence Hub was $81.0 million and $82.4 million as of June 30, 2011 and December 31, 2010, respectively (including capitalized interest of $5.1 million and $5.2 million at June 30, 2011 and December 31, 2010, respectively).  Distributions from Independence Hub, net to our interest, totaled $5.2 million and $9.6 million for the three-month and six-month periods ended June 30, 2011, respectively.

·   Clough Helix JV. In February 2010, we announced the formation of the Clough Helix JV with Australian-based engineering and construction company, Clough Projects Australia Pty Ltd (“Clough”), to provide a range of subsea services to offshore operators in the Asia Pacific region. The Clough Helix JV combines our well intervention equipment with Clough’s 12-man saturation diving system, which are deployed from the 118 meter long DP2 multiservice vessel, Normand Clough.   In the first quarter of 2011, the Clough Helix JV commenced an approximate six- to nine-month day rate project located offshore China.  Our 50% share of the earnings from the Clough Helix JV totaled $0.7 million and $1.1 million for the three- and six-month periods ended June 30, 2011, respectively as compared to losses of  $4.3 million and $5.7 million in the three- and six-month periods ended June 30, 2010, respectively.   The loss in the 2010 periods primarily represented the mobilization costs of transporting the Normand Clough from the Gulf of Mexico to Singapore and other start up costs.   Our investment in the Clough Helix JV was $9.5 million at June 30, 2011 and $4.9 million at December 31, 2010.

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Note 7 – Long-Term Debt

Scheduled maturities of long-term debt outstanding as of June 30, 2011 were as follows (in thousands):

	Term Loan			Revolving Loans		Senior Unsecured Notes		Convertible Senior Notes (1)			MARAD Debt			Total
Less than one year	$	3,000		$	─	$	─	$	─		$	4,759		$	7,759
One to two years		3,000			─		─		─			4,997			7,997
Two to three years		3,000			─		─		─			5,247			8,247
Three to four years		3,000			─		─		─			5,508			8,508
Four to five years		287,250			─		550,000		─			5,783			843,033
Over five years		─			─		─		300,000			86,222			386,222
Total debt		299,250			─		550,000		300,000			112,516			1,261,766
Current maturities		(3,000	)		─		─		─			(4,759	)		(7,759	)
Long-term debt, less    current maturities	$	296,250		$	─	$	550,000	$	300,000		$	107,757		$	1,254,007
Unamortized debt discount (2)		─			─		─		(14,114	)		─			(14,114	)
Long-term debt	$	296,250		$	─	$	550,000	$	285,886		$	107,757		$	1,239,893

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

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

At June 30, 2011, unsecured letters of credit issued totaled approximately $48.8 million (see “Credit Agreement” below).  These letters of credit primarily guarantee various contract bidding, contractual performance, including asset retirement obligations, and insurance activities.  The following table details our interest expense and capitalized interest for the three and six month periods ended June 30, 2011 and 2010:

		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2011			2010			2011			2010
		(in thousands)
Interest expense	$	26,029		$	24,597		$	50,796		$	48,946
Interest income		(499	)		(199	)		(975	)		(397	)
Capitalized interest		(252	)		(3,875	)		(307	)		(12,391	)
Interest expense, net	$	25,278		$	20,523		$	49,514		$	36,158

Included below is a summary of certain components of our indebtedness. For additional information regarding our debt see Note 9 of our 2010 Form 10-K.

Senior Unsecured Notes

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

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Credit Agreement

In July 2006, we entered into a credit agreement (the “Credit Agreement”) containing both a term loan (the “Term Loan”) and a revolving credit facility (the “Revolving Credit Facility”). The $835 million term loan was used to fund the cash portion of the acquisition of Remington Oil and Gas Corporation in July 2006.   The original borrowing capacity under the Revolving Credit Facility was $300 million.  In June 2011, we amended our Credit Agreement as further discussed below.  For additional information regarding the previous terms of our Credit Agreement see Note 9 of our 2010 Form 10-K.

The fourth amendment to our Credit Agreement, among other things:

·   increases the Revolving Credit Facility to $600.0 million (capacity was $435 million prior to the closing of the fourth amendment);

·   extends the maturity date of the Term Loan from July 1, 2013 to a maturity date that is the earlier of (A) July 1, 2016, or (B), if our currently outstanding Senior Unsecured Notes due in 2016 are not fully re-financed or repaid by July 1, 2015, July 1, 2015;

·   provided for the repayment of $109.4 million of the outstanding principal portion of the Term Loan together with accrued interest thereon and related costs;

·   extends the maturity date of the Revolving Credit Facility from November 30, 2012 to a maturity date that is the earlier of (A) January 1, 2016, or (B), if our currently outstanding Senior Unsecured Notes due in 2016 are not fully re-financed or repaid by July 1, 2015, July 1, 2015;

·   relaxes limitations on our right to dispose of certain Contracting Services assets comprising collateral to the Credit Agreement;

·   increases the amount of restricted payments in the form of stock repurchases or redemptions that we are permitted to repurchase or redeem up to $50 million of our common stock;

·   permits us to repurchase or redeem all or part of our Convertible Senior Notes or Senior Unsecured Notes assuming certain conditions are met pro forma for any such  transaction, including maintaining minimum levels of liquidity (defined as cash on hand and availability under our Revolving Credit Facility) of (A) $400 million with respect to the Convertible Senior Notes, and (B) $500 million with respect to the Senior Unsecured Notes; and

·   increases the maximum amount of all investments permitted in subsidiaries that are neither loan parties nor whose equity interests are pledged from $150 million to $200 million.

With the closing of the fourth amendment, the Term Loan currently bears interest either at the one-, two-, three- or six-month LIBOR or Base Rates at our election plus a margin of between 3.25% and 3.5%  (LIBOR margin) or 2.25% to 2.5% (Base Rate margin) depending on current leverage ratios.  Our average interest rate on the Term Loan for the six-month periods ended June 30, 2011 and 2010 was approximately 3.2% and 2.9%, respectively, including the effects of our interest rate swaps (Note 16).

The full amount of the Revolving Credit Facility may be used for issuances of letters of credit.  At June 30, 2011, we had no amounts drawn on the Revolving Credit Facility and our availability under the Revolving Credit Facility totaled $551.2 million, net of $48.8 million of letters of credit issued.

With the closing of the fourth amendment, the borrowings outstanding under the Revolving Credit Facility will  bear interest based on one-, two-, three- or six-month LIBOR rates or on Base Rates at our election plus an applicable margin. The LIBOR margin ranges from 2.5% to 3.5% and the Base Rate margin rates from 1.5% to 2.5%, depending on our consolidated leverage ratio. In connection with the

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closing of the fourth amendment to our Credit Agreement (as noted above), we borrowed $109.4 million under the Revolving Credit Facility and prepaid a portion of the Term Loan.   We subsequently repaid all borrowings under our Revolving Credit Facility with our available cash on hand at June 30, 2011.

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

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

Convertible Senior Notes

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

The Convertible Senior Notes can be converted prior to the stated maturity (March 2025) under certain triggering events specified in the indenture governing the Convertible Senior Notes.  To the extent we do not have long-term financing secured to cover the conversion, the Convertible Senior Notes would be classified as a current liability in the accompanying condensed consolidated balance sheet.  No conversion triggers were met during either the three or six-month periods ended June 30, 2011 or 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 (see Note 9 of our 2010 Form 10-K).   Effective January 1, 2009 we adopted certain new required accounting standards that required us to discount the principal amount of our Convertible Senior Notes. Following adoption of these accounting standards, the effective interest rate for the Convertible Senior Notes is 6.6%.

Our average share price was below the $32.14 per share conversion price for all the periods presented in this Quarterly Report on Form 10-Q.  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")  pursuant to Title XI of the Merchant Marine Act of 1936, which is administered by the Maritime Administration, was used to finance the construction of the Q4000. The MARAD Debt is payable in equal semi-annual installments beginning in August 2002 and matures in February 2027. 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 February 2027 maturity date.

Other

In accordance with our Credit Agreement and our Senior Unsecured Notes, Convertible Senior Notes and MARAD Debt agreements, we are required to comply with certain covenants, including the maintenance of minimum net worth, working capital and debt-to-equity requirements, and restrictions that limit our ability to incur certain types of additional indebtedness.  As of June 30, 2011, we were in compliance with these covenants and restrictions.

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Deferred financing costs of $30.1 million and $25.7 million are included in other assets, net as of June 30, 2011 and December 31, 2010, respectively, and are being amortized over the life of the applicable loan agreements.  We charged to expense $0.8 million of deferred financing costs associated with the repayment of $109.4 million of our Term Loan balance in June 2011 (see “Credit Agreement” above)

Note 8 – Income Taxes

         The effective tax rates for the three-month and six-month periods ended June 30, 2011 were 27.7% and 27.2%, respectively.  The effective tax rates for the three-month and six-month periods ended June 30, 2010 reflected benefits of 38.1% and 37.0%, respectively.  The variance primarily reflects the increased benefit derived from the effect of lower tax rates in certain foreign jurisdictions.  

     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.

Note 9 – Comprehensive Income (Loss)

The components of total comprehensive income (loss) for the three and six-month periods ended June 30, 2011 and 2010 were as follows (in thousands):

		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2011			2010			2011		2010
Net income (loss), including noncontrolling interests	$	42,109		$	(85,073	)	$	68,744	$	(102,075	)
Other comprehensive income (loss), net of tax
Foreign currency translation gain (loss)		(1,416	)		(3,106	)		699		(13,808	)
Unrealized gain on hedges, net		20,970			2,063			10,403		16,103
Unrealized loss on investment available for sale		─			(481	)		─		(556	)
Total other comprehensive income (loss)	$	61,663		$	(86,597	)	$	79,846	$	(100,336	)

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

	June 30,			December 31,
	2011			2010
Cumulative foreign currency translation adjustment	$	(21,563	)	$	(22,262	)
Unrealized loss on hedges, net		(6,393	)		(16,796	)
Accumulated other comprehensive loss	$	(27,956	)	$	(39,058	)

Note 10 – Earnings Per Share

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

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

	Three Months Ended				Three Months Ended
	June 30, 2011				June 30, 2010
	Income			Shares	Income			Shares
Basic:
Net income (loss) applicable to common shareholders	$	41,313			$	(85,551	)
Less: Undistributed net income allocable to participating securities		(514	)			─
Net income (loss) applicable to common stock	$	40,799		104,673	$	(85,551	)	104,125

	Three Months Ended				Three Months Ended
	June 30, 2011				June 30, 2010
	Income		Shares		Income			Shares
Diluted:
Net  income (loss) per common share – Basic	$	40,799		104,673	$	(85,551	)		104,125
Effect of dilutive securities:
Stock options		─		106		─			─
Undistributed earnings reallocated to participating securities		3		─		─			─
Convertible Senior Notes		─		─		─			─
Convertible preferred stock		10		361		─			─
Net income (loss) per common share – Diluted	$	40,812		105,140	$	(85,551	)		104,125

	Six Months Ended				Six Months Ended
	June 30, 2011				June 30, 2010
	Income			Shares	Income			Shares
Basic:
Net income (loss) applicable to common shareholders	$	67,170			$	(103,442	)
Less: Undistributed net income allocable to participating securities		(850	)			─
Net income (loss) applicable to common stock	$	66,320		104,573	$	(103,442	)	103,610

	Six Months Ended				Six Months Ended
	June 30, 2011				June 30, 2010
	Income		Shares		Income			Shares
Diluted:
Net  income (loss) per common share –  Basic	$	66,320		104,573	$	(103,442	)		103,610
Effect of dilutive securities:
Stock options		─		90		─			─
Undistributed earnings reallocated to participating securities		4		─
Convertible Senior Notes		─		─		─			─
Convertible preferred stock		20		361		─			─
Net income (loss) per common share –  Diluted	$	66,344		105,024	$	(103,442	)		103,610

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 had an anti-dilutive effect on our EPS calculation, meaning it would have increased 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):

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	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

Note 11 – Stock-Based Compensation Plans

We have two stock-based compensation plans: the 1995 Long-Term Incentive Plan, as amended (the “1995 Incentive Plan”) and the 2005 Long-Term Incentive Plan, as amended (the “2005 Incentive Plan”).  As of June 30, 2011, there were 967,435 shares available for grant under our 2005 Incentive Plan.

There were no stock option grants in the three- and six-month periods ended June 30, 2011 and 2010. During the six-month period ended June 30, 2011, we made the following restricted share grants to executive officers, selected management employees and non-employee members of the board of directors under the 2005 incentive plan:

Date of Grant	Shares		Market Value Per Share		Vesting Period
January 4, 2011		475,804	$	12.14	20% per year over five years
January 4, 2011		4,427		12.14	100% on January 1, 2013
April 1, 2011		2,907		17.20	100% on January 1, 2013
May 11, 2011		21,608		16.14	20% per year over five years

Compensation cost is recognized over the applicable vesting periods on a straight-line basis.

For the three- and six-month periods ended June 30, 2011, $2.0 million and $4.9 million, respectively, was recognized as compensation expense related to restricted shares as compared with $2.1 million and $4.6 million during the three- and six-month periods ended June 30, 2010, 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.  Some of the cash awards are indexed to our Company common stock and the payment amount at each vesting date will fluctuate based on the common stock’s performance as a result, the compensation expense associated with those awards is re-measured to fair value each reporting period with corresponding changes being recorded as a charge to earnings as appropriate.

Total compensation expense under the 2009 LTI plan totaled $1.6 million and $4.6 million for the three- and six-month periods ended June 30, 2011, respectively.  For the three- and six-month periods ended June 30, 2010, total compensation under the 2009 LTI plan totaled $0.9 million and $2.6 million, respectively.  The liability balance under the 2009 LTI Plan was $6.6 million at June 30, 2011 and $7.9 million at December 31, 2010, including $5.7 million at June 30, 2011 and $6.2 million at December 31, 2010 associated with the variable portion of the 2009 LTI plan.

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

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Note 12 – Business Segment Information

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

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

		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2011			2010			2011			2010
		(in thousands)
Revenues ─
Contracting Services	$	171,353		$	202,317		$	302,890		$	356,517
Production Facilities		20,545			21,391			36,115			22,711
Oil and Gas		172,458			102,586			341,317			193,301
Intercompany elimination		(26,037	)		(27,032	)		(50,396	)		(71,697	)
Total	$	338,319		$	299,262		$	629,926		$	500,832
Income (loss) from operations ─
Contracting Services	$	30,565		$	43,781		$	33,831		$	71,267
Production Facilities (1)		11,920			12,977			17,876			12,940
Oil and Gas		43,064			(154,943	)		96,304			(155,607	)
Corporate (2)		(9,112	)		(12,597	)		(19,553	)		(35,475	)
Intercompany elimination		(19	)		(6,114	)		71			(18,419	)
Total	$	76,418		$	(116,896	)	$	128,529		$	(125,294	)
Equity in earnings of equity investments (Note 6)	$	5,887		$	1,656		$	11,537		$	6,711

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

(2)   The six-month period ended June 30, 2010, included $13.8 million of $17.5 million settlement of a third party claim against us in March 2010 (Note 14).

Intercompany segment revenues during the three- and six-month periods ended June 30, 2011 and 2010 were as follows:

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2011		2010		2011		2010
		(in thousands)
Contracting Services	$	14,295	$	24,426	$	27,164	$	68,167
Production Facilities		11,742		2,606		23,232		3,530
Total	$	26,037	$	27,032	$	50,396	$	71,697

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Intercompany segment gross profit (losses) during the three- and six-month periods ended June 30, 2011 and 2010 were as follows:

		Three Months Ended					Six Months Ended
		June 30,					June 30,
		2011			2010		2011			2010
		(in thousands)
Contracting Services	$	63		$	3,701	$	39		$	15,143
Production Facilities		(44	)		2,413		(110	)		3,293
Total	$	19		$	6,114	$	(71	)	$	18,436

Our identifiable assets as of June 30, 2011 and December 31, 2010 were as follows:

	June 30, 2011		December 31, 2010
		(in thousands)
Identifiable Assets ─
Contracting Services	$	1,869,593	$	1,856,016
Production Facilities		518,220		512,990
Oil and Gas		1,172,824		1,223,014
Total	$	3,560,637	$	3,592,020

Note 13 – Related Party Transactions

In April 2000, we acquired a 20% working interest in Gunnison, a deepwater Gulf of Mexico prospect, from a third party.  Financing for the exploratory costs of approximately $20 million was provided by an investment partnership (OKCD Investments, Ltd. or “OKCD”), the investors of which include current and former Helix senior management, in exchange for a revenue interest that is an overriding royalty interest of 25% of Helix’s 20% working interest. Production began in December 2003. Our payments to OKCD totaled $2.7 million and $5.1 million for the three-month and six-month periods ended June 30, 2011, respectively, and $3.0 million and $6.1 million in the three-month and six-month periods ended June 30, 2010, respectively.  Our Chief Executive Officer, Owen Kratz, through Class A limited partnership interests in OKCD, personally owns approximately 80.7% of the partnership. In 2000, OKCD also awarded Class B income participations to key Helix employees, who are required to maintain their employment status with Helix in order to retain such income participations.

Note 14 – Commitments and Contingencies

Litigation and Claims

In March 2009, we were notified of a third party’s intention to terminate an international construction contract with one of our subsidiaries based on a claimed breach of that contract.  Under the terms of the contract, our potential liability was generally capped for actual damages at approximately 32 million Australian dollars (“AUD”).  We asserted a counterclaim that in the aggregate approximated $12 million U.S. dollars.  On March 30, 2010, an out of court settlement of these claims was reached.  In April 2010, pursuant to the terms of the settlement, we paid the third party 15 million AUD to settle all its damage claims against us.   We also agreed not to seek any further payment of our counter claims against them.   In the first quarter of 2010, our results included approximately $17.5 million in expenses associated with this settlement agreement, including $13.8 million for the litigation settlement payment and $3.7 million to write off our remaining trade receivable from the third party.  These amounts were recorded as selling, general and administrative expenses in the accompanying condensed consolidated statements of operations.

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Loss Contract

As discussed in Note 16 of the 2010 Form 10-K, in 2010 our Australian subsidiary contracted for a project to plug, abandon and salvage subsea wells in an oil and gas field located offshore China.  As previously reported as of the year ended December 31, 2010, we had recorded an aggregate pre-tax loss of approximately $30 million related to this project which reflected the difficulty we had in plugging the wells because of certain structural issues, start-up issues with our recently repaired subsea intervention device and significant weather related delays.  In the first quarter of 2011, this project ended and we recorded an additional pre-tax loss of approximately $0.2 million.  Our remaining trade receivable related to this project is $6.7 million.  We believe this amount is collectable, however, if we are unable to collect any of this amount any variance would increase the recorded loss for the project.

Contingencies and Claims

We were subcontracted to perform development work for a large gas field offshore India.  Work commenced in the fourth quarter of 2007 and we completed our scope of work in the third quarter of 2009.  To date we have collected approximately $303 million related to this project with an amount of trade receivables and claims yet to be collected.  We have requested arbitration in India pursuant to the terms of the subcontract to pursue our claims and the prime contractor has also requested arbitration and has asserted certain counterclaims against us.  If we are not successful in resolving these matters through ongoing discussions with the prime contractor, then arbitration in India remains a potential remedy.  Based on number of factors associated with the ongoing negotiations with the prime contractor, in 2010 we established an allowance against our trade receivable balance that reduces its balance to an amount we believe is ultimately realizable (see Notes 16 and 18 of our 2010 Form 10-K).  However, at the time of this filing no final commercial resolution of this matter has been reached.

We have received value added tax (VAT) assessments from the State of Andhra Pradesh, India (the “State”) in the amount of approximately $28 million related to our subsea and diving contract entered into in December 2006 in India for the tax years 2007, 2008, 2009, and  2010. The State claims we owe unpaid taxes related to products consumed by us during the period of the contract.  We are of the opinion that the State has arbitrarily assessed this VAT tax and has no foundation for the assessment, and believe that we have complied with all rules and regulations as it relates to VAT in the State. We also believe that our position is supported by law and intend to vigorously defend our position. However, the ultimate outcome of this assessment and our potential liability from it, if any, cannot be determined at this time. If the current assessment is upheld, it may have a material negative effect on our consolidated results of operations while also impacting our financial position.

We are involved in various legal proceedings, primarily involving claims for personal injury under the General Maritime Laws of the United States and the Jones Act based on alleged negligence. In addition, from time to time we incur other claims, such as contract disputes, in the normal course of business.

Note 15 – Fair Value Measurements

Fair Value Measurements

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

• Level 1.  Observable inputs such as quoted prices in active markets;

• Level 2.  Inputs, other than the quoted prices in active markets, that are observable either directly or indirectly; and

• Level 3.  Unobservable inputs in which there is little or no market data, which require the reporting entity to develop its own assumptions.

19

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, 2011 (in thousands):

	Level 1		Level 2 (1)		Level 3		Total		Valuation Technique
Assets:
Oil and gas swaps and collars	$	–	$	7,531	$	–	$	7,531	(c)
Foreign currency forwards		–		305		–		305	(c)
Liabilities:
Oil and gas swaps and collars		–		16,680		–		16,680	(c)
Fair value of long term debt(2)		1,182,173		122,417		–		1,304,590	(a), (b)
Interest rate swaps		–		1,157		–		1,157	(c)
Total net liability	$	1,182,173	$	132,418	$	–	$	1,314,591

(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)   We have elected not to record our debt at fair value in the accompanying condensed consolidated balance sheets. See Note 7 for additional information regarding our long term debt.   The fair value of our long term debt at June 30, 2011 is as follows:

	Fair Value		Carrying Value
Term Loan (matures July 2015)	$	299,998	$	299,250
Revolving Credit Facility (matures July 2015)		─		─
Convertible Senior Notes (matures March 2025)		299,175		300,000	(a)
Senior Unsecured Notes (matures January 2016)		583,000		550,000
MARAD Debt (matures February 2027) (b)		122,417		112,516
Total	$	1,304,590	$	1,261,766

(a)   Amount excludes the $14.1 million of unamortized discount recorded on the Convertible Senior Notes at June 30, 2011.

(b)   The estimated fair value of all debt, other than MARAD Debt, 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.

20

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

In the second quarter of 2011, we recorded impairment charge on seven of our oil and gas properties.  These impairment charges reduced these oil and gas properties to their estimated fair value, which, for six of the properties, including our only U.K. oil and gas property, was zero and for the remaining property its  estimated fair value was $2.9 million at June 30, 2011.  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 amounts 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 amounts of the impairment charges were $7.0 million, which reduced these properties to their aggregate fair value of $28.2 million. See Note 4 for additional information regarding our oil and gas property impairment charges.

Note 16 – Derivative Instruments and Hedging Activities

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

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

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

Commodity Price Risks

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

As of June 30, 2011, we have the following volumes under derivative contracts related to our oil and gas producing activities totaling approximately 3.5 MMBbl of oil and 9.4 Bcf of natural gas:

21

Production Period	Instrument Type	Average Monthly Volumes	Weighted Average Price
Crude Oil:			(per barrel)
July 2011 — December 2011	Swap	175.8 MBbl	$	82.49
July 2011 — December 2011	Collar	53.3 MBbl	$	95.00 — $124.70
October 2011 — December 2011	Collar	12.5 MBbl	$	100.00 — $122.80	a
January 2012 — December 2012	Collar	75.0 MBbl	$	96.67 — $118.57
January 2012 — December 2012	Collar	91.7 MBbl	$	100.00 — $120.25	a
Natural Gas:			(per Mcf)
July 2011 — December 2011	Swap	725.8 Mmcf	$	4.97
January 2012 — December 2012	Swap	250.0 Mmcf	$	4.77
January 2012 — December 2012	Collar	166.7 Mmcf	$	4.75 — $5.09

a.   The prices quoted in the table above are primarily NYMEX Henry Hub for natural gas or NYMEX West Texas Intermediate for crude oil.   As footnoted above these costless collar contracts are priced as Brent crude oil.

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

Variable Interest Rate Risks

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

Foreign Currency Exchange Risks

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

Quantitative Disclosures Related to Derivative Instruments

The following tables present the fair value and balance sheet classification of our derivative instruments as of June 30, 2011 and December 31, 2010.  The fair value amounts below are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements.

Derivatives designated as hedging instruments are as follows:

	As of June 30, 2011			As of December 31, 2010
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
	(in thousands)
Asset Derivatives:
Oil contracts	Other current assets	$	3,381	Other current assets	$	—
Natural gas contracts	Other current assets		2,302	Other current assets		5,324
Natural gas contracts	Other assets, net		32	Other assets, net		—
Oil contracts	Other assets, net		1,816	Other assets, net		—
Interest rate swaps	Other assets, net		—	Other assets, net		—
		$	7,531		$	5,324

22

	As of June 30, 2011			As of December 31, 2010
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
	(in thousands)
Liability Derivatives:
Oil contracts	Accrued liabilities	$	16,055	Accrued liabilities	$	28,855
Interest rate swaps	Accrued liabilities		1,157	Accrued liabilities		1,751
Oil contracts	Other long-term liabilities		399	Other long-term liabilities		—
Natural gas contracts	Other long-term liabilities		226	Other long-term liabilities		913
Interest rate swaps	Other long-term liabilities		—	Other long-term liabilities		115
		$	17,837		$	31,634

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

	As of June 30, 2011			As of December 31, 2010
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
	(in thousands)
Asset Derivatives:
Foreign exchange forwards	Other current assets	$	305	Other current assets	$	148
Foreign exchange forwards	Other assets, net		—	Other assets, net		42
		$	305		$	190
Liability Derivatives:
		$	—		$	—

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, 2011 and 2010.

		Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)
		Three Months Ended June 30,					Six Months Ended June 30,
		2011(1)		2010(1)			2011(1)		2010(1)
		(in thousands)
Oil and natural gas commodity contracts	$	20,720	$	2,575		$	9,942	$	17,205
Interest rate swaps		250		(512	)		461		(1,102	)
	$	20,970	$	2,063		$	10,403	$	16,103

(1)   All unrealized gains (losses) related to our derivatives are expected to be reclassified into earnings by no later than December 31, 2012.  The last of our interest swaps will mature in January 2012 and we have foreign exchange forwards and oil and natural gas commodity contracts that have maturities through June and December 2012, respectively.

23

	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,
			2011			2010			2011			2010
Oil and natural gas commodity contracts	Oil and gas revenue	$	(11,860	)	$	9,663		$	(18,185	)	$	10,464
Interest rate swaps	Net interest expense		(591	)		(469	)		(1,071	)		(887	)
		$	(12,451	)	$	9,194		$	(19,256	)	$	9,577

The following table presents the impact of derivative instruments that no longer qualify for hedge accounting or were not designated as hedges on our condensed consolidated income statement for the three and six month periods ended June 30, 2011 and 2010:

	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,
			2011		2010			2011		2010
			(in thousands)
Natural gas contracts	Gain on oil and gas derivative contracts	$	—	$	2,482		$	—	$	2,482
Foreign exchange forwards	Other income (expense)		6		(398	)		614		(3,305	)
		$	6	$	2,084		$	614	$	(823	)

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

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

24

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(in thousands)

(Unaudited)

	As of June  30, 2011
			Helix		Guarantors		Non-Guarantors			Consolidating        Entries			Consolidated
ASSETS:
Current assets:
Cash and cash equivalents		$	387,772	$	2,413	$	24,004		$	—		$	414,189
Accounts receivable, net			54,325		106,506		51,575			—			212,406
Unbilled revenue			2,219		—		18,084			—			20,303
Income taxes receivable			63,514		—		13,075			(67,530	)		9,059
Other current assets			47,610		42,191		12,712			(1,238	)		101,275
Total current assets			555,440		151,110		119,450			(68,768	)		757,232
Intercompany			1,294		294,433		(212,007	)		(83,720	)		—
Property and equipment, net			221,300		1,554,186		704,756			(4,932	)		2,475,310
Equity investments in unconsolidated affiliates			—		—		188,772			—			188,772
Equity investments in affiliates			1,947,501		28,432		—			(1,975,933	)		—
Goodwill, net			—		45,107		17,795			—			62,902
Other assets, net			48,499		38,119		19,639			(29,836	)		76,421
Due from subsidiaries/parent			90,965		275,900		—			(366,865	)		—
		$	2,864,999	$	2,387,287	$	838,405		$	(2,530,054	)	$	3,560,637
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable		$	41,121	$	82,403	$	24,618		$	—		$	148,142
Accrued liabilities			58,787		96,184		35,255			—			190,226
Income taxes payable			—		84,684		—			(84,684	)		—
Current maturities of long-term debt			3,000		—		4,759			—			7,759
Total current liabilities			102,908		263,271		64,632			(84,684	)		346,127
Long-term debt			1,132,136		—		107,757			—			1,239,893
Deferred income taxes			213,232		126,992		97,650			(6,053	)		431,821
Asset retirement obligations			—		166,458		—			—			166,458
Other long-term liabilities			1,335		3,480		617			—			5,432
Due to parent			—		—		116,451			(116,451	)		—
Total liabilities			1,449,611		560,201		387,107			(207,188	)		2,189,731
Convertible preferred stock			1,000		—		—			—			1,000
Total equity			1,414,388		1,827,086		451,298			(2,322,866	)		1,369,906
		$	2,864,999	$	2,387,287	$	838,405		$	(2,530,054	)	$	3,560,637

25

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(in thousands)

	As of December 31, 2010
			Helix		Guarantors		Non-Guarantor			Consolidating Entries			Consolidated
ASSETS
Current assets:
Cash and cash equivalents		$	376,434	$	3,294	$	11,357		$	—		$	391,085
Accounts receivable, net			61,846		91,659		23,788			—			177,293
Unbilled revenue			11,990		—		37,421			—			49,411
Income taxes receivable			19,334		—		7,195			(20,430	)		6,099
Other current assets			63,306		49,557		12,889			(8,786	)		116,966
Total current assets			532,910		144,510		92,650			(29,216	)		740,854
Intercompany			1,906		263,920		(171,513	)		(94,313	)		—
Property and equipment, net			217,153		1,605,906		709,082			(5,061	)		2,527,080
Other assets:
Equity investments in unconsolidated affiliates			—		—		187,031			—			187,031
Equity investments in affiliates			1,998,289		29,899		—			(2,028,188	)		—
Goodwill, net			—		45,107		17,387			—			62,494
Other assets, net			43,971		38,324		21,900			(29,634	)		74,561
Due from subsidiaries/parent			95,398		105,434		—			(200,832	)		—
		$	2,889,627	$	2,233,100	$	856,537		$	(2,387,244	)	$	3,592,020
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable		$	60,308	$	56,107	$	42,966		$	—		$	159,381
Accrued liabilities			58,074		107,874		32,289			—			198,237
Income taxes payable			—		36,678		—			(36,678	)		—
Current maturities of long-term debt			4,326		—		14,301			(8,448	)		10,179
Total current liabilities			122,708		200,659		89,556			(45,126	)		367,797
Long-term debt			1,237,587		—		110,166			—			1,347,753
Deferred income taxes			185,453		135,101		98,968			(5,883	)		413,639
Asset retirement obligations			—		170,410		—			—			170,410
Other long-term liabilities			1,421		3,691		665			—			5,777
Due to parent			—		—		120,884			(120,884	)		—
Total liabilities			1,547,169		509,861		420,239			(171,893	)		2,305,376
Convertible preferred stock			1,000		—		—			—			1,000
Total equity			1,341,458		1,723,239		436,298			(2,215,351	)		1,285,644
		$	2,889,627	$	2,233,100	$	856,537		$	(2,387,244	)	$	3,592,020

26

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(in thousands)

(Unaudited)

	Three Months Ended June 30, 2011
	Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated
Net revenues	$	20,545		$	247,855		$	92,926		$	(23,007	)	$	338,319
Cost of sales		15,123			173,897			71,730			(22,629	)		238,121
Gross profit (loss)		5,422			73,958			21,196			(378	)		100,198
Gain on oil & gas derivative contracts		—			—			—			—			—
Gain (loss) on sale or acquisition of assets		(22	)		—			—			—			(22	)
Selling, general and administrative expenses		(9,574	)		(9,915	)		(4,658	)		389			(23,758	)
Income (loss) from operations		(4,174	)		64,043			16,538			11			76,418
Equity in earnings of investments		58,929			4,194			5,887			(63,123	)		5,887
Net interest expense and other		(18,243	)		(5,890	)		108			—			(24,025	)
Income (loss) before income taxes		36,512			62,347			22,533			(63,112	)		58,280
Provision (benefit) for income taxes		(4,790	)		20,319			637			5			16,171
Net income (loss), including noncontrolling interests		41,302			42,028			21,896			(63,117	)		42,109
Less net income applicable to noncontrolling interests		—			—			—			(786	)		(786	)
Preferred stock dividends		(10	)		—			—			—			(10	)
Net income (loss) applicable to Helix common shareholders	$	41,292		$	42,028		$	21,896		$	(63,903	)	$	41,313

	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
Gain (loss) on sale or acquisition of assets		—			—			(14	)		—			(14	)
Selling, general 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		(15,319	)		(5,002	)		(1,878	)		—			(22,199	)
Income (loss) before income taxes		(82,994	)		(137,652	)		23,974			59,233			(137,439	)
Provision (benefit) for income taxes		(1,872	)		(49,351	)		1,221			(2,364	)		(52,366	)
Net income (loss), including noncontrolling interests		(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	)

27

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(in thousands)

(Unaudited)

	Six Months Ended June 30, 2011
	Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated
Net revenues	$	36,127		$	489,897		$	150,802		$	(46,900	)	$	629,926
Cost of sales		31,716			339,128			128,008			(46,200	)		452,652
Gross profit (loss)		4,411			150,769			22,794			(700	)		177,274
Gain on oil & gas derivative contracts		—			—			—			—			—
Gain (loss) on sale or acquisition of assets		(6	)		—			—			—			(6	)
Selling, general and administrative expenses		(20,760	)		(19,951	)		(8,812	)		784			(48,739	)
Income (loss) from operations		(16,355	)		130,818			13,982			84			128,529
Equity in earnings of investments		107,036			(1,468	)		11,537			(105,568	)		11,537
Net interest expense and other		(35,527	)		(10,599	)		525			—			(45,601	)
Income (loss) before income taxes		55,154			118,751			26,044			(105,484	)		94,465
Provision (benefit) for income taxes		(11,963	)		42,060			(4,404	)		28			25,721
Net income (loss), including noncontrolling interests		67,117			76,691			30,448			(105,512	)		68,744
Less net income applicable to noncontrolling interests		—			—			—			(1,554	)		(1,554	)
Preferred stock dividends		(20	)		—			—			—			(20	)
Net income (loss) applicable to Helix common shareholders	$	67,097		$	76,691		$	30,448		$	(107,066	)	$	67,170

	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 (loss) on sale or acquisition of assets		—			287			5,946			—			6,233
Selling, general 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		(22,708	)		(12,568	)		(8,143	)		—			(43,419	)
Income (loss) before income taxes		(101,702	)		(125,838	)		16,694			48,844			(162,002	)
Provision (benefit) for income taxes		(6,668	)		(45,136	)		(3,650	)		(4,473	)		(59,927	)
Net income (loss), including noncontrolling interests		(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	)

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HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

Six Months Ended June 30, 2011
	Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated
Cash flow from operating activities:
Net income (loss), including noncontrolling interests	$	67,117		$	76,691		$	30,448		$	(105,512	)	$	68,744
Adjustments to reconcile net income (loss), including noncontrolling interests to net cash provided by (used in) operating activities:
Equity in earnings of affiliates		(107,036	)		1,468			—			105,568			—
Other adjustments		21,261			180,193			(14,149	)		(5,476	)		181,829
Net cash provided by (used in) operating
activities		(18,658	)		258,352			16,299			(5,420	)		250,573
Cash flows from investing activities:
Capital expenditures		(15,699	)		(76,331	)		(14,092	)		—			(106,122	)
Investments in equity investments		—			—			(2,699	)		—			(2,699	)
Distributions from equity investments, net		—			—			1,593			—			1,593
Proceeds from sale of Cal Dive common stock		3,588			—			—			—			3,588
Decrease (increase) in restricted cash		—			863			—			—			863
Net cash used in investing activities		(12,111	)		(75,468	)		(15,198	)		—			(102,777	)
Cash flows from financing activities:
Repayments of debt		(111,191	)		—			(3,507	)		—			(114,698	)
Deferred financing costs		(9,014	)		—			—			—			(9,014	)
Preferred stock dividends paid		(20	)		—			—			—			(20	)
Repurchase of common stock		(1,012	)		—			—			—			(1,012	)
Excess tax benefit from stock-based  compensation		(1,196	)		—			—			—			(1,196	)
Exercise of stock options, net		1,672			—			—			—			1,672
Intercompany financing		162,868			(183,765	)		15,477			5,420			—
Net cash provided by (used in) financing activities		42,107			(183,765	)		11,970			5,420			(124,268	)
Effect of exchange rate changes on cash and cash equivalents		—			—			(424	)		—			(424	)
Net increase (decrease) in cash and cash equivalents		11,338			(881	)		12,647			—			23,104
Cash and cash equivalents:
Balance, beginning of year		376,434			3,294			11,357			—			391,085
Balance, end of period	$	387,772		$	2,413		$	24,004		$	—		$	414,189

29

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(in thousands)

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			(13,101	)		(10,119	)		238,475
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	)
Investments in equity investments		—			—			(6,307	)		—			(6,307	)
Distributions from equity investments, net		—			—			8,132			—			8,132
Insurance recovery		7,020			9,086			—			—			16,106
Decrease (increase) in restricted cash		—			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	)		—			(3,570	)		—			(5,733	)
Deferred financing costs		(2,792	)		—			—			—			(2,792	)
Preferred stock dividends paid		(94	)		—			—			—			(94	)
Repurchases of common stock		(9,127	)		—			—						(9,127	)
Excess tax benefit from stock-based  compensation		(2,163	)		—			—			—			(2,163	)
Exercise of stock options, net		163			—			—			—			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

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Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations.

FORWARD-LOOKING STATEMENTS AND ASSUMPTIONS

 This Quarterly Report on Form 10-Q contains various statements that contain forward-looking information regarding Helix Energy Solutions Group, Inc. and represent our expectations and beliefs concerning future events.   This forward looking information is intended to be covered by the safe harbor for “forward-looking statements” provided by the Private Securities Litigation Reform Act of 1995 as set forth in Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements included herein or incorporated herein by reference; that are predictive in nature, that depend upon or refer to future events or conditions, or that use terms and phrases such as “achieve,” “anticipate,” “believe,” “estimate,” “expect,” “forecast,” “plan,” “project,” “propose,” “strategy,” “predict,” “envision,” “hope,” “intend,” “will,” “continue,” “may,” “potential,” “should,” “could” and similar terms and phrases are forward-looking statements. Included in forward-looking statements are, among other things:    

• statements regarding our business strategy, including the potential sale of assets and/or other investments in our subsidiaries and facilities, or any other business plans, forecasts or objectives, any or all of which is subject to change;

• statements regarding our anticipated production volumes, results of exploration, exploitation, development, acquisition or  operations expenditures, and current or prospective reserve levels with respect to any oil and gas property or well;

• statements related to commodity prices for oil and gas or with respect to the supply of and demand for oil and gas;

• statements relating to our proposed exploration, development and/or production of oil and gas properties, prospects or other interests and any anticipated costs related thereto;

• statements related to environmental risks, exploration and development risks, or drilling and operating risks;

• statements regarding projections of revenues, gross margin, expenses, earnings or losses, working capital or other financial items;

• statements regarding any financing transactions or arrangements, or ability to enter into such transactions;

• statements regarding anticipated legislative, governmental, regulatory, administrative or other public body actions, requirements, permits or decisions;

• statements regarding the collectability of our trade receivables;

• statements regarding anticipated developments, industry trends, performance or industry ranking;

• statements regarding general economic or political conditions, whether international, national or in the regional and local market areas in which we do business; 

• statements related to our ability to retain key members of our senior management and key employees;

• statements related to the underlying assumptions related to any projection or forward-looking statement; and

• any other statements that relate to non-historical or future information.

Although we believe that the expectations reflected in these forward-looking statements are reasonable and are based on reasonable assumptions, they do involve risks, uncertainties and other factors that could cause actual results to be materially different from those in the forward-looking statements.  These factors include, among other things:

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• impact of the weak economic conditions and the future impact of such conditions on the oil and gas industry and the demand for our services;

• uncertainties inherent in the development and production of oil and gas and in estimating reserves;

• the geographic concentration of our oil and gas operations;

• the effect of new regulations on the offshore Gulf of Mexico oil and gas operations;

• uncertainties regarding our ability to replace depletion;

• unexpected future capital expenditures (including the amount and nature thereof);

• impact of oil and gas price fluctuations and the cyclical nature of the oil and gas industry;

• the effects of indebtedness, which could adversely restrict our ability to operate, could make us vulnerable to general adverse economic and industry conditions, could place us at a competitive disadvantage compared to our competitors that have less debt and could have other adverse consequences to us;

• the effectiveness of our hedging activities;

• the results of our continuing efforts to control or reduce costs, and improve performance;

• the success of our risk management activities;

• the effects of competition;

• the availability (or lack thereof) of capital (including any financing) to fund our business strategy and/or operations and the terms of any such financing;

• the impact of current and future laws and governmental regulations including tax and accounting developments;

• the effect of adverse weather conditions or other risks associated with marine operations;

• the effect of environmental liabilities that are not covered by an effective indemnity or insurance;

• the potential impact of a loss of one or more key employees; and

• the impact of general, market, industry or business conditions.

Our actual results could differ materially from those anticipated in any forward-looking statements as a result of a variety of factors, including those described in Item 1A. “Risk Factors” in our 2010 Form 10-K.  All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. Forward-looking statements are only as of the date they are made, and other than as required under the securities laws, we assume no obligation to update or revise these forward-looking statements or provide reasons why actual results may differ.

EXECUTIVE SUMMARY

Our Business

We are an international offshore energy company that provides reservoir development solutions and other contracting services to the energy market as well as to our own oil and gas properties. Our oil and gas business is a prospect generation, exploration, development and production company. Employing our own key services and methodologies, we seek to lower finding and development costs relative to industry norms.

Our Strategy

Over the past few years, we have focused on improving our balance sheet by increasing our liquidity through disposition of non-core business assets and reductions in our planned capital spending.  In June 2011, we amended our current Credit Agreement to extend its maturity to at least July 1, 2015 and increases the amount we can potentially borrow under our Revolving Credit Facility to $600 million. For complete information regarding our fourth amendment to our Credit Agreement see Note 7 included elsewhere herein.  At June 30, 2011, our cash on hand totaled $414.2 million and our liquidity was $965.4 million. Our capital expenditures for full year 2011 are expected to total approximately $275 million, which primarily reflects development of certain of our oil and gas properties (but is exclusive of expenditures related to our asset retirement obligations).   Over the coming twelve months, we believe that we have sufficient liquidity to successfully implement our business plan without incurring additional indebtedness beyond the existing capacity under the Revolving Credit Facility.

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In March 2010, we announced the engagements of advisors to assist us with evaluating potential alternatives for the disposition of our oil and gas business.  As previously disclosed, certain events in the Gulf of Mexico compromised the efforts to dispose of our entire oil and gas business.   As a result, we are no longer actively seeking to divest our oil and gas business and have shifted our strategy to develop our significant proved undeveloped reserve portfolio and drill certain of our exploration prospects with a focus on crude oil prospects given the favorable price environment for this commodity.   We may from time to time sell certain of our individual oil and gas properties that we consider to be in our best interest in terms of economic returns and/or risk mitigation.

Economic Outlook and Industry Influences

Demand for our contracting services operations is primarily influenced by the condition of the oil and gas industry, and in particular, the willingness of oil and gas companies to make capital expenditures for offshore exploration, drilling and production operations. Generally, spending for our contracting services fluctuates directly with the direction of oil and natural gas prices. However, some of our Contracting Services will often lag drilling operations by a period of 6 to 18 months, meaning that even if there were a sudden increase in deepwater permitting and subsequent drilling in the Gulf of Mexico, it probably would still be some time before we would start securing any awarded projects. The performance of our oil and gas operations is also largely dependent on the prevailing market prices for oil and natural gas, which are impacted by global economic conditions, hydrocarbon production and capacity, geopolitical issues, weather, and several other factors, including but not limited to:

• worldwide economic activity, including available access to global capital and capital markets;

• demand for oil and natural gas, especially in the United States, Europe, China and India;

• economic and political conditions in the Middle East and other oil-producing regions;

• the effect of new regulations on the offshore Gulf of Mexico oil and gas operations;

• actions taken by the Organization of Petroleum  Exporting Countries (“OPEC”) ;

• the availability and discovery rate of new oil and natural gas reserves in offshore areas;

• the cost of offshore exploration for and production and transportation of oil and gas;

• the ability of oil and natural gas companies to generate funds or otherwise obtain external capital for exploration, development and production operations;

• the sale and expiration dates of offshore leases in the United States and overseas;

• technological advances affecting energy exploration production transportation and consumption;

• weather conditions;

• environmental and other governmental regulations; and

• tax policies.

Oil prices increased significantly in 2011 (the average WTI price was $98.33 per barrel in the first half of 2011).  Beginning in the later part of the first quarter of 2011, the price that we received for the majority of our crude oil sales volumes increased significantly over the WTI market price (by anywhere from $11-$15 per barrel).    Historically the price we receive for most of our crude oil, as priced using a number of Gulf Coast crude oil price indexes, closely correlated with current market prices of WTI crude oil; however, because of a substantial increase in crude oil inventories at Cushing, Oklahoma the price of Gulf Coast crude is now substantially higher than WTI.    Currently the price we receive for our crude oil more closely correlates with the Brent crude oil price in the North Sea.    We do not know how long the market price of our crude oil and WTI will continue at this unusually high price variance but most analysts believe this will continue over at least the remainder of 2011.

The NYMEX Henry Hub natural gas price averaged $4.32 per Mmbtu for the three-month period ended June 30, 2011 and $4.22 per Mmbtu for the six-month period ended June 30, 2011.  Prices for natural gas have decreased significantly from the record highs in mid 2008 primarily reflecting the increased supply from non-traditional sources of natural gas such as production from shale formations and tight sands as well as decreased demand following the economic downturn that commenced in mid-to-late 2008.  Although there have been signs that the economy is improving, most economists believe the recovery will be slow and will take time to recover to levels previously achieved.   The oil and natural gas industry has been adversely affected by the uncertainty of the general timing and level of the economic recovery as well  the more recent uncertainties concerning increased government regulation of the industry in the United States (as further discussed below).

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In April 2010, an explosion occurred on the Deepwater Horizon drilling rig located on the site of the Macondo well at Mississippi Canyon Block 252 (Note 1).  The resulting events included loss of life, the complete destruction of the drilling rig and an oil spill, the magnitude of which was unprecedented in U.S. territorial waters.  In October 2010, the DOI lifted the drilling moratorium and instructed the BOEMRE that it could resume issuing drilling permits conditioned on the requesting company’s compliance with all revised drilling, safety and environmental requirements.  No deepwater drilling permits were issued in the period from October 2010 through late February 2011.   In late February 2011, the BOEMRE commenced issuing deepwater permits.    At the time of this filing 24 deepwater permits have been issued, 14 of which were issued referencing the Helix Fast Response System (see below).

While we did not have plans to drill any additional deepwater wells during the period covered by the drilling moratorium, our contracting services businesses rely heavily on industry investment in the Gulf of Mexico and the results of the moratorium and subsequent delay in the drilling permit process has adversely affected our results of operations and financial position.   Although our contracting services activities during 2010 remained substantially unaffected, delays in restarting drilling in the deepwater of the Gulf of Mexico, due to the failure to issue permits or otherwise, have resulted in a deferral or cancellation of portions of our contracted backlog and have decreased opportunities for future contracts for work in the Gulf of Mexico.  Furthermore, the impact of the deepwater drilling moratorium, continuing delays in the permitting process and any subsequent related developments in the Gulf of Mexico could require us to pursue relocation of our vessels located in the Gulf of Mexico to international locations, such as the North Sea, West Africa, Southeast Asia, Brazil and Mexico.

 Although we are still feeling the effects of the recent global recession and are experiencing the consequences of the additional regulatory requirements resulting from the aftermath of the oil spill in the Gulf of Mexico, we believe that the long-term industry fundamentals are positive based on the following factors: (1) long term increasing world demand for oil and natural gas requires the need for continual replenishment of oil and gas production; (2) peaking global production rates; (3) globalization of the natural gas market; (4) increasing number of mature and small reservoirs; (5) increasing global offshore activity, particularly in deepwater; and (6) increasing number of subsea developments. Our strategy of combining contracting services operations and oil and gas operations allows us to focus on trends (4) through (6) in that we pursue long-term sustainable growth by applying specialized subsea services to the broad external offshore market but with a complementary focus on marginal fields and new reservoirs in which we currently have an ownership stake.

 Over the longer-term, the fundamentals for our business remain generally favorable as the need for the continual replenishment of oil and gas production is the primary driver of demand for our services.

Helix Fast Response System

We developed the Helix Fast Response System (“HFRS”) as a culmination of our experience as a responder in the Macondo oil spill response and containment efforts.  The HFRS centers on two vessels, the HP I and the Q4000, both of which played a key role in the Macondo oil spill response and containment efforts and are presently operating in the Gulf of Mexico.  In 2011, we signed an agreement with Clean Gulf Associates ("CGA"), a non-profit industry group, allowing, in exchange for a retainer fee,  the HFRS to be named as a response resource in permit applications to federal and state agencies and making the HFRS available for a two-year term to certain CGA participants who have executed utilization agreements with us. In addition to the agreement with CGA, we currently have signed separate utilization agreements with 24 CGA participant member companies specifying the day rates to be charged should the HFRS solution be deployed in connection with a well control incident.  The retainer fee associated with HFRS was effective April 1, 2011 and is a component of our Production Facilities business segment.   A total of 14 permits have been granted to CGA participants for deepwater drilling operations identifying the HFRS to fulfill the BOERME requirement to have a spill response solution included in the submitted permit applications.

34

RESULTS OF OPERATIONS

We have disaggregated our contracting services operations into two reportable segments Contracting Services and Production Facilities.  Our third business segment, Oil and Gas represents our operations within that industry.  All material intercompany transactions between the segments have been eliminated in our consolidated financial statements, including our consolidated results of operations.

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 Contracting Services segment includes operations such as subsea construction, deepwater pipelay, well operations and robotics.   Our Contracting Services business operates primarily in the Gulf of Mexico, the North Sea, Asia Pacific and West Africa regions, with services that cover the lifecycle of an offshore oil or gas field.  Our Production Facilities business includes our investments in Deepwater Gateway, L.L.C. (“Deepwater Gateway”) and Independence Hub, LLC (“Independence Hub”) as well as our majority ownership of the HP I.   Our Production Facilities segment also includes HFRS response system (see “Helix Fast Response System” above).   As of June 30, 2011, our contracting services operations had backlog of approximately $423.0 million, including $255.3 million for the remainder of 2011.  Backlog for the HP I totaled $67.3 million at June 30, 2011, including $18.0 million for the remainder of 2011.  At December 31, 2010, our contracting services operations backlog totaled approximately $267.3 million, including $218.8 million for 2011.  These backlog contracts are cancellable without penalty in many cases.  Backlog is not a reliable indicator of total annual revenue for our Contracting Services and Production Facilities businesses as contracts may be added, cancelled and in many cases modified while in progress.

Oil and Gas Operations

We began our oil and gas operations to provide a more efficient solution to offshore abandonment, to expand our off-season utilization of our contracting services assets and to achieve incremental returns.  We have evolved this business model to include not only mature oil and gas properties but also proved and unproved reserves yet to be developed and explored.  By owning oil and gas reservoirs and prospects, we are able to utilize the services we otherwise provide to third parties to create value at key points in the life of our own reservoirs including during the exploration and development stages, the field management stage and the abandonment stage.  It is also a feature of our business model to opportunistically monetize part of the created reservoir value through sales of working interests, in order to help fund field development and reduce gross profit deferrals from our Contracting Services operations.  Thus, the reservoir value we create is realized through oil and gas production and/or monetization of working interest stakes.

Impairments

During the three-month period ended June 30, 2011, we recorded impairment charges totaling $22.7 million, including $4.1 million for  our only U.K. oil and gas property, and for six of our Gulf of Mexico oil and gas properties.  These impairment changes primarily reflect a premature end of these fields’ production life either through actual depletion or capital allocation decisions affecting our  third party operated fields.  We did not have any impairment of our properties in the first quarter of 2011. 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.   See Note 4 for more information regarding our impairment charges recorded in the first half of 2011 and 2010.

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Non-GAAP Financial Measures

A non-GAAP financial measure is generally defined by the SEC as one that purports to measure historical or future performance, financial position, or cash flows, but excludes amounts that would not be so adjusted in the most comparable measures under generally accepted accounting principles (GAAP).   We measure our operating performance based on EBITDAX, a non-GAAP financial measure, that is commonly used in the oil and natural gas industry but is not a recognized accounting term under GAAP.  We use EBITDAX to monitor and facilitate the internal evaluation of the performance of our business operations, to facilitate external comparison of our business results to those of others in our industry, to analyze and evaluate financial and strategic planning decisions regarding future operating investments and acquisitions, to plan and evaluate operating budgets, and in certain cases, to report our results to the holders of our debt as required under our debt covenant requirements.   We believe our measure of EBITDAX provides useful information to the public regarding our ability to service debt and fund capital expenditures and may help our investors understand our operating performance and make it easier to compare our results to other companies that have different financing, capital and tax structures.

We define EBITDAX as income (loss) from continuing operations plus income taxes, net interest expense and other, depreciation, depletion and amortization expense and exploration expenses.  We separately disclose our non cash oil and gas property impairment charges, which, if not material, would be reflected as a component of our depreciation, depletion and amortization expense. Because such impairment charges are material for most of the periods presented, we have reported them as a separate line item in the accompanying consolidated statements of operations.  Non cash impairment charges related to goodwill are also added back if applicable.

In our reconciliation of income (loss) including noncontrolling interests, we provide amounts as reflected in our accompanying condensed consolidated financial statements, unless otherwise footnoted.  This means that such amounts are recorded at 100% even if we do not own 100% of all of our subsidiaries.  Accordingly, to arrive at our measure of Adjusted EBITDAX, we deduct the non-controlling interests related to the adjustment components of EBITDAX, the adjustment components of EBITDAX of any discontinued operations, the gain or loss on the sale of assets, and the portion of our asset impairment charges that are considered cash-related charges.  Asset impairment charges that are considered cash are those that affect future cash outflows most notably those related to adjustment to our asset retirement obligations.

Other companies may calculate their measures of EBITDAX and Adjusted EBITDAX differently than we do, which may limit its usefulness as a comparative measure.  Because EBITDAX is not a financial measure calculated in accordance with GAAP, it should not be considered in isolation or as a substitute for net income (loss) attributable to common shareholders, but used as a supplement to that GAAP financial measure.  A reconciliation of our net income (loss) attributable to common shareholders to EBITDAX is as follows:

		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2011			2010			2011			2010
		(in thousands)
Income (loss), including noncontrolling interests	$	42,109		$	(85,073	)	$	68,744		$	(102,075	)
Adjustments:
Income tax provision (benefit)		16,171			(52,366	)		25,721			(59,927	)
Net interest expense and other		24,025			22,199			46,354			43,419
Depreciation, depletion and amortization expense		75,027			85,441			167,170			146,268
Asset impairment charges		22,721			159,862			22,721			170,974
Exploration expenses		7,939			1,172			8,285			1,338
EBITDAX		187,992			131,235			338,995			199,997
Adjustments:
Non-controlling interest Kommandor LLC		(1,026	)		(710	)		(2,041	)		(1,805	)
Discontinued operations		—			—			—			(15	)
(Gain) loss on sales of assets		22			14			(747	)		(6,233	)
Asset retirement costs		(11,148	)		—			(11,148	)		—
ADJUSTED EBITDAX	$	175,840		$	130,539		$	325,059		$	191,944

36

Comparison of Three Months Ended June 30, 2011 and 2010

The following table details various financial and operational highlights for the periods presented:

		Three Months Ended
		June 30,						Increase/
		2011			2010			(Decrease)
Revenues (in thousands) –
Contracting Services	$	171,353		$	202,317		$	(30,964	)
Production Facilities		20,545			21,391			(846	)
Oil and Gas		172,458			102,586			69,872
Intercompany elimination		(26,037	)		(27,032	)		995
	$	338,319		$	299,262		$	39,057
Gross profit (loss) (in thousands) –
Contracting Services	$	38,049		$	50,333		$	(12,284	)
Production Facilities		12,070			13,078			(1,008	)
Oil and Gas		50,858			(151,368	)		202,226
Corporate		(760	)		(747	)		(13	)
Intercompany elimination		(19	)		(6,114	)		6,095
	$	100,198		$	(94,818	)	$	195,016
Gross Margin –
Contracting Services		22	%		25	%		(3) pts
Production Facilities		59	%		61	%		(2) pts
Oil and Gas		30	%		(148	)%		178 pts
Total company		30	%		(32	)%		62 pts
Number of vessels(1)/ Utilization(2) –
Contracting Services:
Construction vessels		8/71	%		10/74	%
Well operations		3/89	%		3/98	%
ROVs		46/54	%		46/61	%

(1)   Represents number of vessels as of the end of the period excluding acquired vessels prior to their in-service dates, vessels taken out of service prior to their disposition and vessels jointly owned with a third party.

(2)   Average vessel utilization rate is calculated by dividing the total number of days the vessels in this category generated revenues by the total number of calendar days in the applicable period.

Intercompany segment revenues during the three-month periods ended June 30, 2011 and 2010 were as follows (in thousands):

		Three Months Ended
		June 30,				Increase/
		2011		2010		(Decrease)
Contracting Services	$	14,295	$	24,426	$	(10,131	)
Production Facilities		11,742		2,606		9,136
	$	26,037	$	27,032	$	(995	)

37

Intercompany segment profit during the three-month periods ended June 30, 2011 and 2010 was as follows (in thousands):

		Three Months Ended
		June 30,					Increase/
		2011			2010		(Decrease)
Contracting Services	$	63		$	3,701	$	(3,638	)
Production Facilities		(44	)		2,413		(2,457	)
	$	19		$	6,114	$	(6,095	)

The following table details various financial and operational highlights related to our Oil and Gas segment for the periods presented:

		Three Months Ended
		June 30,					Increase/
		2011			2010		(Decrease)
Oil and Gas information–
Oil production volume (MBbls)		1,430			790		640
Oil sales revenue (in thousands)	$	145,074		$	57,366	$	87,708
Average oil sales price per Bbl (excluding hedges)	$	111.23		$	75.39	$	35.84
Average realized oil price per Bbl (including hedges)	$	101.43		$	72.59	$	28.84
Increase in oil sales revenue due to:
Change in prices (in thousands)	$	22,794
Change in production volume (in thousands)		64,914
Total increase in oil sales revenue (in thousands)	$	87,708
Gas production volume (MMcf)		4,075			7,147		(3,072	)
Gas sales revenue (in thousands)	$	25,121		$	43,591	$	(18,470	)
Average gas sales price per mcf (excluding hedges)	$	5.63		$	4.44	$	1.19
Average realized gas price per mcf (including hedges)	$	6.17		$	6.10	$	0.07
Increase (decrease) in gas sales revenue due to:
Change in prices (in thousands)	$	472
Change in production volume (in thousands)		(18,942	)
Total decrease in gas sales revenue (in thousands)	$	(18,470	)
Total production (MMcfe)		12,656			11,889		767
Price per Mcfe	$	13.45		$	8.49	$	4.96
Oil and Gas revenue information (in thousands)–
Oil and gas sales revenue	$	170,195		$	100,957	$	69,238
Other revenues(1)		2,263			1,629		634
	$	172,458		$	102,586	$	69,872

(1)   Other revenues include fees earned under our process handling agreements.

 Presenting the expenses of our Oil and Gas segment on a cost per Mcfe of production basis normalizes for the impact of production gains/losses and provides a measure of expense control efficiencies.  The following table highlights certain relevant expense items in total converted to Mcfe at a ratio of one barrel of oil to six Mcf:

38

	Three Months Ended June 30,
	2011						2010
	Total			Per Mcfe			Total		Per Mcfe
	(in thousands, except per Mcfe amounts)
Oil and gas operating expenses(1):
Direct operating expenses(2)	$	29,390		$	2.32		$	15,763	$	1.33
Workover		2,236			0.18			3,504		0.29
Transportation		1,391			0.11			1,036		0.09
Repairs and maintenance		2,980			0.24			1,730		0.15
Overhead and company labor		3,296			0.26			1,579		0.13
	$	39,293		$	3.11		$	23,612	$	1.99
Depletion expense	$	48,526		$	3.83		$	63,330	$	5.33
Abandonment		227			0.02			401		0.03
Accretion expense		3,844			0.30			4,012		0.34
Net hurricane costs (reimbursements)		(950	)		(0.08	)		1,563		0.13
Impairment		22,721			1.80			159,862		13.45
		74,368			5.87			229,168		19.28
Total	$	113,661		$	8.98		$	252,780	$	21.27

(1)   Excludes exploration expense of $7.9 million and $1.2 million for the three-month periods ended June 30, 2011 and 2010, respectively.  Exploration expense is not a component of lease operating expense.

(2)   Includes production taxes.

Revenues.   Our Contracting Services revenues decreased 15% for the three-month period ended June 30, 2011 compared to the same period in 2010 reflecting decreased subsea construction activity in the Gulf of Mexico, primarily attributable to delays in permitting of projects since the Macondo oil spill in April 2010.   Separately, in the second quarter of 2010, we performed a greater scope of internal work related to our oil and gas operations, most notably development activities at the Phoenix field, than what we performed in the second quarter of 2011.  Overall utilization levels for subsea construction assets decreased significantly as the Intrepid was quayside for most of the second quarter of 2011 and the Caesar is continuing its capital upgrades at a U.S. shipyard, which are expected to continue through the third quarter of 2011.  Our ROV utilization rate decreased by approximately 7% from rates achieved during the second quarter of 2010.  The decrease in our utilization rates for our pipelay and robotics support vessels and ROVs primarily reflects the lower number of projects with approved permits in the Gulf of Mexico region.  Our well operations vessels’ utilization decreased slightly as a result of a few days of unplanned maintenance for the both the Seawell and Q4000 during the second quarter of 2011.  Demand for our well intervention vessels remains strong in both the Gulf of Mexico and North Sea regions.  Our second quarter 2010 revenues included amounts earned by the contracting of the Q4000, the Express and the HP I to assist in the Gulf oil spill response and containment efforts.

Oil and Gas revenues increased 68% during the three-month period ended June 30, 2011 as compared to the same period in 2010.   The increase in revenues reflects increased oil production and higher oil prices.   Our production was 0.8 billion cubic feet of natural gas equivalent (Bcfe) more in the second quarter of 2011 as compared to the same period in 2010, primarily reflecting oil production from our Phoenix field at Green Canyon Blocks 236, 237, 238 and 282 which commenced production in October 2010, offset in part by lower natural gas production, most notably from our Bushwood field.  Production from the Phoenix field impacted  a portion of July due to  scheduled downtime of a third party pipeline servicing the fields in the vicinity including our Phoenix field.   The pipeline is back on line and the Phoenix field is back on production.  Our net production rate through July 24, 2011approximated 114 MMcfe/d as compared to an approximate average of 139 MMcfe/d for the three-month period ended June 30, 2011.   First sustained production from our Little Burn well commenced on July 21, 2011.   On July 24, 2011, our net production rate totaled approximately 155 MMcfe/d.

Our Production Facilities revenues reflect the HP I being placed in service in June 2010, following the final installation of its production processing facility upgrades and receipt of its certification by U.S. Coast Guard.  The HP I was initially used in the Gulf oil spill containment efforts where it remained until October 2010 at which time it moved to our Phoenix field in which we own a 70% working interest.   The HP I continues to be utilized in the Phoenix field, where it is expected to remain until the field depletes (currently anticipated to be sometime in 2013, based on future successful development of existing proved reserves in the field).   Our revenues also include one quarter of retainer fees associated with the HFRS.

39

Gross Profit.   Our Contracting Services gross profit decreased by 24% in the three month period ended June 30, 2011 as compared to the same period last year.   This decrease primarily reflected the weak subsea construction industry conditions in the Gulf of Mexico region, which contributed significantly to our lower pipelay and robotics support vessel and ROV utilization rates.   Separately, our margin in the second quarter of 2010 benefitted from the Express and Q4000 on hire to BP in the Gulf oil spill containment efforts.

Oil and Gas gross profit increased by $202.2 million for the three-month period ended June 30, 2011  as compared to the same period in 2010, which was primarily attributable to increased oil production and higher oil price realizations. The increase in our production is primarily related to the commencement of production from our Phoenix field in October 2010.  Our oil and gas gross profit was adversely affected by impairment charges totaling $22.7 million for the three-month period ended June 30, 2011 and $159.9 million for the three month period ended June 30, 2010, as previously discussed in “Oil and Gas Operations” above.  Our exploration expenses totaled $7.9 million in the second quarter of 2011, which included an offshore lease expiration impairment charge of $6.6 million, as compared to $1.2 million in the second quarter of 2010.

Our gross profit for Production Facilities decreased for the three month period ended June 30, 2011, as compared to same period in 2010, reflecting our current of use of HP I for primarily internal usage within the Phoenix field as compared to the vessel’s utilization in the Gulf oil spill containment efforts in June 2010.

Selling and Administrative Expenses.  Selling and administrative expenses of $23.8 million for the second quarter of 2011 were $0.8 million lower than the $24.5 million incurred in the same prior year period.   The decrease includes the lower costs related to our reduction in efforts to divest our oil and gas business.

Equity in Earnings of Investments.  Equity in earnings of investments increased by $4.2 million during the three-month period ended June 30, 2011 as compared to the same prior year period.  This increase was primarily due to $0.7 million of income related to project work in China performed by the CloughHelix JV in Australia (Note 3) as compared to $4.3 million of CloughHelix JV losses in the second quarter of 2010, which primarily reflected certain start-up costs.

Net Interest Expense.  Our net interest expense was $25.3 million in second quarter 2011 as compared to $20.5 million in the same prior year period. Gross interest expense of $26.0 million during the three-month period ended June 30, 2011 was greater than the $24.6 million incurred in the comparable 2010 period reflecting slightly higher interest rates and a $0.8 million of interest expense charge to accelerate the amortization of a portion of the deferred financing costs associated with the repayment of a portion of our Term Loan in June 2011 (Note 7).  Capitalized interest totaled $0.3 million for the three- month period ended June 30, 2011 compared with $3.9 million for the same period last year.  The decrease in our capitalized interest was primarily attributable to the completion of our major capital projects, including the Caesar and HP I vessels being placed in service during the second quarter of 2010.  Interest income totaled $0.5 million for the three-month period ended June 30, 2011, as compared with $0.2 million in the same prior year period, reflecting our higher cash balances.

Other Income (Expense).   We incurred foreign exchange gains related to the strengthening of our non U.S dollar functional currencies and currency contracts totaling $1.3 million in the second quarter of 2011 compared to $1.7 million in second quarter of 2010.  We had no losses on our foreign exchange forward contracts in the second quarter of 2011 and losses of $0.4 million in the second quarter of 2010 (Note 16).  

Provision for Income Taxes.We recordedincome taxes expense of $16.2 million in the second quarter of 2011, as compared to income tax benefit of $52.4 million in the same prior year period. The variance primarily reflects increased profitability in the current year period.  The effective tax rate for the second quarter of 2011 was 27.7% as compared to a benefit rate of 38.1%  for the second quarter of 2010 reflecting the increased benefit derived from the effect of lower tax rates in certain foreign jurisdictions.

40

Comparison of Six Months Ended June 30, 2011 and 2010

The following table details various financial and operational highlights for the periods presented:

		Six Months Ended
		June 30,						Increase/
		2011			2010			(Decrease)
Revenues (in thousands) –
Contracting Services	$	302,890		$	356,517		$	(53,627	)
Production Facilities		36,115			22,711			13,404
Oil and Gas		341,317			193,301			148,016
Intercompany elimination		(50,396	)		(71,697	)		21,301
	$	629,926		$	500,832		$	129,094
Gross profit  (loss) (in thousands) –
Contracting Services	$	48,561		$	87,955		$	(39,394	)
Production Facilities		18,206			13,099			5,107
Oil and Gas		112,093			(150,119	)		262,212
Corporate		(1,657	)		(1,461	)		(196	)
Intercompany elimination		71			(18,436	)		18,507
	$	177,274		$	(68,962	)	$	246,236
Gross Margin –
Contracting Services		16	%		25	%		(9) pts
Production Facilities		50	%		58	%		(8) pts
Oil and Gas		33	%		(78	)%		111  pts
Total company		28	%		(14	)%		42  pts
Number of vessels(1)/ Utilization(2) –
Contracting Services:
Construction vessels		8/61	%		10/78	%
Well operations		3/83	%		3/79	%
ROVs		46/52	%		46/60	%

(1)    Represents number of vessels as of the end of the period excluding acquired vessels prior to their in-service dates, vessels taken out of service prior to their disposition and vessels jointly owned with a third party.

(2)    Average vessel utilization rate is calculated by dividing the total number of days the vessels in this category  generated revenues by the total number of calendar days in the applicable period.

Intercompany segment revenues during the six month periods ended June 30, 2011 and 2010 were as follows (in thousands):

		Six Months Ended
		June 30,				Increase/
		2011		2010		(Decrease)
Contracting Services	$	27,164	$	68,167	$	(41,003	)
Production Facilities		23,232		3,530		19,702
	$	50,396	$	71,697	$	(21,301	)

Intercompany segment profit during the six month periods ended June 30, 2011 and 2010 was as follows (in thousands):

		Six Months Ended
		June 30,					Increase/
		2011			2010		(Decrease)
Contracting Services	$	39		$	15,143	$	(15,104	)
Production Facilities		(110	)		3,293		(3,403	)
	$	(71	)	$	18,436	$	(18,507	)

41

The following table details various financial and operational highlights related to our Oil and Gas segment for the periods presented:

		Six Months Ended
		June 30,					Increase/
		2011			2010		(Decrease)
Oil and Gas information–
Oil production volume (MBbls)		2,931			1,445		1,486
Oil sales revenue (in thousands)	$	280,910		$	104,374	$	176,536
Average oil sales price per Bbl (excluding hedges)	$	103.92		$	75.53	$	28.39
Average realized oil price per Bbl (including hedges)	$	95.83		$	72.24	$	23.59
Increase in oil sales revenue due to:
Change in prices (in thousands)	$	34,086
Change in production volume (in thousands)		142,450
Total increase in oil sales revenue (in thousands)	$	176,536
Gas production volume (MMcf)		9,477			14,490		(5,013	)
Gas sales revenue (in thousands)	$	56,282		$	85,775	$	(29,493	)
Average gas sales price per mcf (excluding hedges)	$	5.35		$	4.87	$	0.48
Average realized gas price per mcf (including hedges)	$	5.94		$	5.92	$	0.02
Increase (decrease) in gas sales revenue due to:
Change in prices (in thousands)	$	277
Change in production volume (in thousands)		(29,770	)
Total decrease in gas sales revenue (in thousands)	$	(29,493	)
Total production (MMcfe)		27,065			23,159		3,906
Price per Mcfe	$	12.46		$	8.21	$	4.25
Oil and Gas revenue information (in thousands)–
Oil and gas sales revenue	$	337,192		$	190,149	$	147,043
Other revenues(1)		4,125			3,152		973
	$	341,317		$	193,301	$	148,016

(1)   Other revenues include fees earned under our process handling agreements.

Presenting the expenses of our Oil and Gas segment on a cost per Mcfe of production basis normalizes for the impact of production gains/losses and provides a measure of expense control efficiencies.  The following table highlights certain relevant expense items in total converted to Mcfe at a ratio of one barrel of oil to six Mcf:

	Six Months Ended June 30,
	2011						2010
	Total			Per Mcfe			Total		Per Mcfe
	(in thousands, except per Mcfe amounts)
Oil and gas operating expenses(1):
Direct operating expenses(2)	$	60,050		$	2.22		$	30,321	$	1.31
Workover		4,804			0.18			15,117		0.65
Transportation		3,802			0.14			2,329		0.10
Repairs and maintenance		5,247			0.19			3,532		0.15
Overhead and company labor		6,613			0.24			3,473		0.15
	$	80,516		$	2.97		$	54,772	$	2.36
Depletion expense	$	114,239		$	4.22		$	103,607	$	4.47
Abandonment		385			0.01			1,166		0.05
Accretion expense		7,630			0.28			7,943		0.34
Net hurricane costs (reimbursements)		(4,552	)		(0.17	)		3,618		0.16
Impairment		22,721			0.84			170,974		7.38
		140,423			5.18			287,308		12.40
Total	$	220,939		$	8.15		$	342,080	$	14.76

(1)   Excludes exploration expense of $8.3 million and $1.3 million for the six-months periods ended June 30, 2011 and 2010, respectively.  Exploration expense is not a component of lease operating expense.

(2)   Includes production taxes.

42

Revenues.   Our Contracting Services revenues decreased 15% for the six-month period ended June 30, 2011 compared to the same period in 2010 reflecting the decreased subsea construction activity in the Gulf of Mexico, primarily attributable to delays in permitting of projects since the Macondo oil spill in April 2010 as well as the decreased amount of internal vessel utilization to develop our oil and gas properties in 2011.   Overall utilization levels for our subsea construction and well operations vessels and ROVs decreased.  As previously noted our Q4000, Express and HP I vessels were involved in the Gulf oil spill response in the second quarter of 2010.

Oil and Gas revenues increased 77% during the six-month period ended June 30, 2011, as compared to the same period in 2010, reflecting increased oil production and higher oil prices.  Our production increased by 3.9 Bcfe in the first half of 2011, as compared to the same period in 2010.  Our production in the first half of 2011 benefited from production from our Phoenix field that commenced production in October 2010 partially offset by decreased production from our Bushwood field.

Our Production Facilities revenues increased for the six-month period ended June 30, 2011 reflecting full utilization of the HP I  at the Phoenix field  in 2011, as compared to it being utilized in the Gulf oil spill containment efforts in June 2010.   Our revenues also include one quarter of retainer fees related to the HFRS.

Gross Profit.   In the first half of 2011, our Contracting Services gross profit decreased by 45% as compared to first half of 2010 primarily reflecting the weak subsea construction industry conditions in the Gulf of Mexico region, which contributed significantly to our lower pipelay and robotics support vessel and ROV utilization rates.   Our contracting services rates in the first half of 2010 benefitted from our increased scope of internal work related to our oil and gas properties.

The Oil and Gas gross profit increase of $262.2 million in first half of 2011, as compared to the same period in 2010 was due primarily to increased oil production and higher oil price realizations. The increase in our production is primarily related to the commencement of production from our Phoenix field in October 2010.  Our oil and gas gross profit was adversely affected by impairment charges totaling $22.7 million for the six-month period ended June 30, 2011 and $171.0 million for the six-month period ended June 30, 2010, including $159.9 million in the second quarter of 2010 as previously discussed in “Oil and Gas Operations” above.  In the first quarter of 2010, following decreases in natural gas prices we recorded impairment charges totaling $7.0 million related to three of our U.S Gulf of Mexico oil and gas properties.  We separately recorded a $4.1 million impairment charge related to our only non-domestic (U.K.) oil and gas property.   See Note 4 for additional disclosure regarding our impairment charges covering the periods covered by this Quarterly Report on Form 10-Q.

The increase in our Production Facilities gross profit in the six-month period ended June 30, 2011, as compared to the same period in 2010, reflects full utilization of the HP I  in 2011 as opposed to one month at the Gulf oil spill containment efforts in the six-month period ended June 30, 2010.

  Gain on Sale or Purchase of Assets, Net. The gain in the first half of 2010 was primarily associated with the acquisition of the remaining 50% working interest related to the Camelot field in the United Kingdom (Note 4).

Selling and Administrative Expenses.  Selling and administrative expenses of $48.7 million for the six-month period ended June 30, 2011 were $16.3 million lower than the $65.0 million incurred in the same prior year period.   The decrease primarily reflects the $17.5 million related to our settlement of litigation claims in Australia in 2010 (Note 14).

Equity in Earnings of Investments.  Equity in earnings of investments increased by $4.8 million during the six-month period ended June 30, 2011, as compared to the same prior year period.  This increase was mostly due to the CloughHelix JV having equity earnings of $1.1 million in 2011 associated with project work in China while in the 2010 period the joint venture incurred $5.7 million of losses related primarily to start-up costs (Note 6).

43

Net Interest Expense.  We reported net interest of $49.5 million for the six-month period ended June 30, 2011, as compared to $36.2 million in the same prior year period. Gross interest expense of $50.8 million during the six-month period ended June 30, 2011 was higher than the $48.9 million incurred in the first half of 2010 reflecting slightly higher interest rates.  Capitalized interest totaled $0.3 million for the six-month period ended June 30, 2011, as compared with $12.4 million for the same period last year.  The decrease in our capitalized interest was primarily attributable to the completion of our major capital projects during the first half of 2010, including our Caesar and HP I vessels being placed in service in the second quarter of 2010.  Interest income totaled $1.0 million for the six-month period ended June 30, 2011, as compared to $0.4 million for the first half of 2010, reflecting the increase in our cash balances.

Other Income (Expense). We incurred foreign exchange gains related to the strengthening of our non U.S dollar functional currencies and currency contracts totaling $3.2 million for the six-month period ended June 30, 2011 compared to losses of $7.3 million for the six-month period ended June 30, 2010.  Gains on our foreign exchange forward contracts totaled $0.6 million in the first half of 2011 compared losses of $3.3 million for the same period last year (Note 16).

Provision for Income Taxes.We hadincome taxes expense of $25.7 million in the six-month period ended June 30, 2011, as compared to income tax benefit of $59.9 million in the same prior year period. The variance primarily reflects increased profitability in the current year period. The effective tax rate for the six-month period ending June 30, 2011 was 27.2%, as compared to a benefit rate of 37.0% for the six-month period ending June 30, 2010 reflecting the increased benefit derived from the effect of lower tax rates in certain foreign jurisdictions.

LIQUIDITY AND CAPITAL RESOURCES

Overview

The following tables present certain information useful in the analysis of our financial condition and liquidity for the periods presented:

	June 30,  2011		December 31, 2010
	(in thousands)
Net working capital	$	411,105	$	373,057
Long-term debt(1)		1,239,893		1,347,753
Liquidity(2)		965,386		787,296

(1)   Long-term debt does not include the current maturities portion of the long-term debt as such amount is included in net working capital.   It is also net of unamortized debt discount on our Convertible Senior Notes (Note 7).

(2)   Liquidity, as defined by us, is equal to cash and cash equivalents plus available capacity under our revolving credit facility.

The carrying amount of our debt, including current maturities as of June 30, 2011 and December 31, 2010 follows:

	June 30,		December 31,
	2011		2010
	(in thousands)
Term Loan (matures July 2015)(1)	$	299,250	$	410,441
Revolving Credit Facility (matures July 2015) (1)	─		─
Convertible Senior Notes (matures March 2025) (2)		285,886		281,472
Senior Unsecured Notes (matures January 2016)		550,000		550,000
MARAD Debt (matures February 2027)		112,516		114,811
Loan Notes	─			1,208
Total	$	1,247,652	$	1,357,932

44

(1)   Represents earliest date debt would mature see Note 7 for conditions that would provide further extension of maturity date.

(2)   This amount is net of the unamortized debt discount of $14.1 million and $18.5 million, respectively.   The notes will increase to $300 million face amount through accretion of non-cash interest charges through 2012.  Notes may be redeemed by the holders beginning in December 2012 (Note 7).

The following table provides summary data from our consolidated statement of cash flows:

		Six Months Ended
		June 30,
		2011			2010
		(in thousands)
Net cash provided by (used in):
Operating activities	$	250,573		$	136,400
Investing activities	$	(102,777	)	$	(117,572	)
Financing activities	$	(124,268	)	$	(19,746	)

Our current requirements for cash primarily reflect the need to fund capital expenditures to allow the growth of our current lines of business and to service our existing debt.  We also intend to repay debt with any additional free cash flow from operations and/or cash received from any dispositions of our non- core business assets.  Historically, we have funded our capital program, including acquisitions, with cash flow from operations, borrowings under credit facilities and use of project financing along with other debt and equity alternatives.

We remain focused on maintaining a strong balance sheet and adequate liquidity.  We may reduce planned capital spending and seek further additional dispositions of our non-core business assets (see “Executive Summary” above).  We also have a reasonable basis for estimating our future cash flow supported by our remaining contracting services operations backlog and the significant hedged portion of our estimated oil and gas production through 2011 and 2012.  We believe that internally generated cash flow and available borrowing capacity under our amended Revolving Credit Facility will be sufficient to fund our operations over the foreseeable future.  We have no borrowings drawn on our Revolving Credit Facility as of June 30, 2011.

In accordance with our Credit Agreement, Senior Unsecured Notes, Convertible Senior Notes and the MARAD debt, we are required to comply with certain covenants and restrictions, including certain financial ratios (such as collateral coverage, interest coverage, consolidated leverage), and the maintenance of minimum net worth, working capital and debt-to-equity requirements. The Credit Agreement and Senior Unsecured Notes also contain provisions that limit our ability to incur certain types of additional indebtedness. These provisions effectively prohibit us from incurring any additional secured indebtedness or indebtedness guaranteed by the Company. The Credit Agreement does permit us to incur certain unsecured indebtedness, and also provides for our subsidiaries to incur project financing indebtedness (such as our MARAD loans) secured by the underlying asset, provided that the indebtedness is not guaranteed by us. Upon the occurrence of certain dispositions or the issuance or incurrence of certain types of indebtedness, we may be required to prepay a portion of the Term Loan equal to the amount of proceeds received from such occurrences (or at least 60% of the proceeds in certain dispositions of assets).  Such prepayments will be applied first to the Term Loan, and any excess will then be applied to the Revolving Loans.  As of June 30, 2011 and December 31, 2010, we were in compliance with all of our debt covenants and restrictions.

A prolonged period of weak economic activity may make it difficult to comply with our covenants and other restrictions in the agreements governing our debt.  Our ability to comply with these covenants and other restrictions is affected by economic conditions and other events beyond our control.  If we fail to comply with these covenants and other restrictions, such failure could lead to an event of default, the possible acceleration of our repayment of outstanding debt and the exercise of certain remedies by the lenders, including foreclosure on our pledged collateral.

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Our Convertible Senior Notes can be converted prior to stated maturity under certain triggering events specified in the indenture governing the Convertible Senior Notes.  To the extent we do not have long-term financing secured to cover the conversion, the Convertible Senior Notes would be classified as a current liability in the accompanying condensed consolidated balance sheet.  No conversion triggers were met during the three-month and six-month periods ended June 30, 2011.  The holders may redeem the Convertible Senior Notes beginning December 2012 (Note 7 as well as Note 9 of our 2010 Form

10-K).

 In June 2011, the Credit Agreement was amended to, among other things, to extend its maturity and increase the availability under our Revolving Credit Facility (Note 7).    See Note 9 of our 2010 Form 10-K for additional information related to our long-term debt, including more information regarding other amendments of our Credit Agreement and our requirements and obligations under the debt agreements including our covenants and collateral security.

Working Capital

Cash flow from operating activities increased by $114.2 million in the six-month period ended June 30, 2011 as compared to the same period in 2010.  This increase primarily reflects the effect of increased oil production as well as the substantially higher oil prices.

Investing Activities

Capital expenditures have consisted principally of strategic asset acquisitions related to the purchase or construction of dynamically positioned vessels, acquisition of select businesses, improvements to existing vessels, acquisition and development of oil and gas properties and investments in our production facilities.  Significant sources (uses) of cash associated with investing activities for the six-month period ended June 30, 2011 and 2010 were as follows:

		Six Months Ended
		June 30,
		2011			2010
		(in thousands)
Capital expenditures:
Contracting Services	$	(30,840	)	$	(29,720	)
Production Facilities(1)		(14,688	)		(41,000	)
Oil and Gas(1)		(60,594	)		(48,786	)
Investments in equity investments		(2,699	)		(6,307	)
Distributions from equity investments, net(2)		1,593			8,132
Sales of shares of Cal Dive common stock		3,588			─
Decrease (increase) in restricted cash		863			109
Cash used in investing activities	$	(102,777	)	$	(117,572	)

(1)   Amounts for the six-month period ended June 30, 2010 are net of insurance recoveries ($7.0 million for Production Facilities and $9.1 million for Oil and Gas).   This insurance recovery is related to damages sustained to Phoenix field in 2005 and which we remediated upon our acquisition of the field in 2007.

(2)   Distributions from equity investments are net of undistributed equity earnings from our equity investments.  Gross distributions from our equity investments are detailed below.

Restricted Cash

As of June 30, 2011 and December 31, 2010, we had $34.5 million and $35.3 million of restricted cash, all of which related to the funds contractually required to be escrowed to cover the asset retirement obligations associated with the South Marsh Island Block 130 field.  We have fully satisfied the escrow requirements under the escrow agreement.  We have used a small portion of these escrowed funds to pay for the initial reclamation activities at the South Marsh Island Block 130 field.  Reclamation activities at the field will occur over many years and will be funded with these escrowed amounts. These amounts are reflected in other assets, net in the accompanying condensed consolidated balance sheets.

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Equity Investments

Our investment in the Clough Helix joint venture (Note 6) totaled $9.5 million at June 30, 2011 and $4.9 million at December 31, 2010.  Our investment in the Clough Helix joint venture is in the form of a loan, which is a fixed non-interest bearing with no stated maturity.  We received the following distributions from our equity investments during the six-month periods ended June 30, 2011 and 2010:

		Six Months Ended
		June 30,
		2011		2010
		(in thousands)
Deepwater Gateway	$	3,550	$	3,875
Independence Hub		9,580		10,700
Total	$	13,130	$	14,575

Outlook

We anticipate capital expenditures for the remainder of 2011 will total between $140 million and $170 million.  The estimates for these capital expenditures may increase or decrease based on various economic factors and opportunities.   However, we may reduce the level of our planned capital expenditures given a prolonged economic downturn.  We believe internally generated cash flow, cash from potential future sales of our non-core business assets, and borrowing availability under our existing credit facilities will provide the capital necessary to fund our 2011 initiatives.

The following table summarizes our contractual cash obligations as of June 30, 2011 and the scheduled years in which the obligations are contractually due:

	Total (1)		Less Than 1 year		1-3 Years		3-5 Years		More Than 5 Years
	(in thousands)
Convertible Senior Notes(2)	$	300,000	$	─	$	─	$	─	$	300,000
Senior Unsecured Notes		550,000		─		─		550,000		─
Term Loan (3)		299,250		3,000		6,000		290,250		─
MARAD debt		112,516		4,759		10,244		11,291		86,222
Revolving Credit Facility(4)		─		─		─		─		─
Interest related to long-term debt		487,422		85,062		165,991		125,364		111,005
Drilling and development costs		50,565		50,565		─		─		─
Property and equipment		15,032		15,032		─		─		─
Operating leases(5)		57,624		48,727		7,253		1,644		─
Total cash obligations	$	1,872,409	$	207,145	$	189,488	$	978,549	$	497,227

(1)   Excludes unsecured letters of credit outstanding at June 30, 2011 totaling $48.8 million. These letters of credit primarily guarantee various contract bidding, insurance activities and shipyard commitments.

(2)   Contractual maturity in 2025 (Notes can be redeemed by us or we may be required to purchase them beginning in December 2012). Notes can be converted prior to stated maturity if closing sale price of Helix’s common stock for at least 20 days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter exceeds 120% of the closing price on that 30th trading day (i.e. $38.56 per share) and under certain triggering events as specified in the indenture governing the Convertible Senior Notes.  Upon the occurrence of a triggering event, to the extent we do not have alternative long-term financing secured to cover the conversion, the Convertible Senior Notes would be classified as a current liability in the accompanying balance sheet.  At June 30, 2011, the conversion trigger was not met.

(3)   Our Term Loan will mature no earlier than July 1, 2015 and may extend to July 1, 2016 if our Senior Unsecured Notes are either refinanced or repaid in full by July 1, 2015 (Note 7).

(4)   Our Revolving Credit Facility will mature no earlier than July 1, 2015 and may extend to January 1, 2016 if our Senior Unsecured Notes are either refinanced or repaid in full by July 1, 2015 (Note 7).

(5)   Operating leases included facility leases and vessel charter leases.  Vessel charter lease commitments at June 30, 2011 were approximately $47.9 million.

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Contingencies

In March 2009, we were notified of a third party’s intention to terminate an international construction contract with one of our subsidiaries based on a claimed breach of that contract.  Under the terms of the contract, our potential liability was generally capped for actual damages at approximately $32 million Australian dollars (“AUD”).  We asserted a counterclaim that in the aggregate approximated $12 million U.S. dollars.  On March 30, 2010, an out of court settlement of these claims was reached.  On April 19, 2010, pursuant to the terms of the settlement, we paid the third party $15 million AUD to settle all its damage claims against us.   We also agreed not to seek any further payment of our counter claims against them.   Our results for the three-month period ended March 31, 2010 included approximately $17.5 million in expenses associated with this settlement agreement, including $13.8 million for the litigation settlement payment and $3.7 million to write off our remaining trade receivable from the third party.  These amounts were recorded as selling, general and administrative expenses in the accompanying condensed consolidated statements of operations.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements. We prepare these financial statements in conformity with accounting principles generally accepted in the United States. As such, we are required to make certain estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. We base our estimates on historical experience, available information and various other assumptions we believe to be reasonable under the circumstances.  These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes.    Please read the following discussion in conjunction with our “Critical Accounting Policies and Estimates” as disclosed in our 2010 Form 10-K.

Item 3.  Quantitative and Qualitative Disclosure about Market Risk

We are currently exposed to market risk in three major areas: interest rates, commodity prices and foreign currency exchange rates.

Commodity Price Risk.  As of June 30, 2011, we had the following volumes under derivative contracts related to our oil and gas producing activities totaling approximately 3.5 MMBbl of oil and 9.4 Bcf of natural gas:

Production Period	Instrument Type	Average Monthly Volumes	Weighted Average Price
Crude Oil:			(per barrel)
July 2011 — December 2011	Swap	175.8 MBbl	$	82.49
July 2011 — December 2011	Collar	53.3 MBbl	$	95.00 — $124.70
October 2011 — December 2011	Collar	12.5 MBbl	$	100.00 — $122.80	a
January 2012 — December 2012	Collar	75.0 MBbl	$	96.67 — $118.57
January 2012 — December 2012	Collar	91.7 MBbl	$	100.00 — $120.25	a
Natural Gas:			(per Mcf)
July 2011 — December 2011	Swap	725.8 Mmcf	$	4.97
January 2012 — December 2012	Swap	250.0 Mmcf	$	4.77
January 2012 — December 2012	Collar	166.7 Mmcf	$	4.75 — $5.09

a)   The prices quoted in the table above are primarily NYMEX Henry Hub for natural gas or NYMEX West Texas Intermediate for crude oil.   As footnoted above these costless collar contracts are priced as Brent crude oil.

All of commodity derivative contracts were designated as cash flow hedges and all remain effective and qualify for hedge accounting as of June 30, 2010 (Note 16).

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Item 4.  Controls and Procedures

(a)   Evaluation of disclosure controls and procedures.  Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Exchange Act) as of the end of the fiscal quarter ended June 30, 2011.  Based on this evaluation, the principal executive officer and the principal financial officer have concluded that our disclosure controls and procedures were effective as of the end of the fiscal quarter ended June 30, 2011 to ensure that information that is required to be disclosed by us in the reports we file or submit under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms and (ii) accumulated and communicated to our management, as appropriate, to allow timely decisions regarding required disclosure.

(b)   Changes in internal control over financial reporting. There have been no changes in our internal control over financial reporting, as defined in Rule 13a-15(f) of the Exchange Act, in the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.  Resulting impacts on internal controls over financial reporting were evaluated and determined not to be significant for the fiscal quarter ended June 30, 2011.

Part II.  OTHER INFORMATION

Item 1.  Legal Proceedings

On July 8, 2011, a shareholder derivative lawsuit styled City of Sterling Heights Police & Fire Retirement System v. Owen Kratz, et al. was filed in the United States District Court for the Southern District of Texas, Houston Division.  In the suit, the plaintiff makes claims against our board of directors, certain of our former directors, our top current and former executives and the independent  compensation consultant to the Compensation Committee of our board of directors, for breaches of fiduciary duty of loyalty, unjust enrichment and aiding and abetting breaches of fiduciary duty relating to the company’s compensation practices.  The plaintiff seeks monetary damages and injunctive relief on behalf of the company.  The case is in its preliminary stages.

See Part I, Item 1, Note 14 to the Condensed Consolidated Financial Statements, which is incorporated herein by reference.

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

Period	(a) Total number of shares purchased		(b) Average price paid per share		(c) Total number of shares purchased as part of publicly announced program (2)		(d) Maximum value of shares that may yet be purchased under the program (2)
April 1 to April 30, 2011(1)		61	$	16.54		─		475,804
May 1 to May 31, 2011(1)		114		17.16		─		497,412
June 1 to June 30, 2011(1)		5,140		15.97		─		497,412
		5,315	$	16.00		─		497,412

(1)	Represents shares subject to restricted share awards withheld to satisfy tax obligations arising upon the vesting of restricted shares.
(2)	Represents amounts of restricted shares issued to certain of our employees in 2011 (Note 11).  Under the terms of our stock repurchase program, these grants increase the amount of shares available for repurchase.  For additional information regarding our stock repurchase program see Note 14 of the 2010 Form 10-K.

Item 6.  Exhibits

The exhibits to this report are listed in the Exhibit Index beginning on Page 51 hereof.

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SIGNATURES

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

		HELIX ENERGY SOLUTIONS GROUP, INC. (Registrant)
Date: July 27, 2011	By:	/s/ Owen Kratz
		Owen Kratz President and Chief Executive Officer (Principal Executive Officer)
Date: July 27, 2011	By:	/s/ Anthony Tripodo
		Anthony Tripodo Executive Vice President and Chief Financial Officer (Principal Financial Officer)

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INDEX TO EXHIBITS

OF

HELIX ENERGY SOLUTIONS GROUP, INC.

3.1	2005 Amended and Restated Articles of Incorporation, as amended, of registrant, incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed by registrant with the Securities and Exchange Commission on March 1, 2006.
3.2	Second Amended and Restated By-Laws of Helix, as amended, incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K, filed by the registrant with the Securities and Exchange Commission on September 28, 2006.
10.1	Amendment No. 4 to Credit Agreement, dated as of June 8, 2011, by and among Helix, as borrower, Bank of America, N.A., as administrative agent, swing line lender and L/C issuer, and the lenders named thereto.  Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by registrant with Securities and Exchange Commission on June 8, 2011.
10.2	Employment Agreement by and between Helix Energy Solutions Group, Inc. and Johnny Edwards dated May 11, 2011.  Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed by registrant with the Securities and Exchange Commission on May 13, 2011.
10.3	Employment Agreement by and between Helix Energy Solutions Group, Inc. and Clifford Chamblee dated May 11, 2011. (1)
15.1	Independent Registered Public Accounting Firm’s Acknowledgement Letter.(1)
31.1	Certification Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934 by Owen Kratz, Chief Executive Officer.(1)
31.2	Certification Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934 by Anthony Tripodo, Chief Financial Officer.(1)
32.1	Certification of Helix’s Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.(2)
99.1	Report of Independent Registered Public Accounting Firm.(1)
101.INS	XBRL Instance Document(2)
101.SCH	XBRL Schema Document(2)
101.CAL	XBRL Calculation Linkbase Document(2)
101.LAB	XBRL Label Linkbase Document(2)
101.PRE	XBRL Presentation Linkbase Document
101.DEF	XBRL Definition Linkbase Document(2)
	(1) Filed herewith
	(2) Furnished herewith

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EX-10.3

EXHIBIT 10.3

EMPLOYMENT AGREEMENT

This Employment Agreement (the “Agreement”) is made effective May 11, 2011, by and between Helix Energy Solutions Group, Inc., a Minnesota corporation (the “Company”), and Clifford Chamblee  (“Executive”), an individual residing in Cypress, Texas.  The Company and Executive are collectively referred to herein as the “Parties,” and individually referred to as a “Party.”

RECITALS:

WHEREAS, the Company and Executive mutually desire to enter into an employment agreement setting forth the terms and conditions of Executive’s employment with the Company.

NOW, THEREFORE, in consideration of the mutual covenants herein contained, it is AGREED as follows:

1.   Purpose.  The purpose of this Agreement is to set forth the terms and conditions of Executive’s employment with the Company.  This Agreement represents both Parties’ intentions with respect to the terms and conditions of Executive’s employment with the Company.

2.   Definitions.  For the purposes of this Agreement, the following words shall have the following meanings:

(a)   “Affiliate” means any Person that, directly or indirectly, through one or more intermediaries, controls or is controlled by, or is under common control with, another Person.  The term “control” includes, without limitation, the possession, directly or indirectly, of the power to direct the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.  With respect to any amount under this Agreement that is deferred compensation subject to Code Section 409A, for the purposes of Code Section 409A only, Affiliate shall mean all Persons with whom the Company would be considered a single employer under Code Section 414(b) or 414(c) and for the purposes of a Separation from Service (as defined in Section 2(o)) and determining the controlled group but using fifty percent (50%) instead of eighty percent (80%) pursuant to Treasury Regulation § 1.409A-1(h)(3).

(b)   “AICP” or “Annual Incentive Compensation Plan” means any Company annual incentive compensation cash bonus plan in which Executive participates, as in effect from time to time.

(c)   “Annual Cash Compensation” means, with respect to a Change in Control, the sum of (i) the amount of Executive’s Base Annual Salary for the year in which the Change in Control occurs and (ii) the target AICP bonus which could be payable to Executive under the AICP for the calendar year in which the Change in Control occurs assuming that the Company and Executive have fully met all performance criteria (financial, personal or otherwise) but not including a multiplier that may be applicable to result in a maximum bonus, and annualized for the purpose of this calculation; provided, however, that if the target bonus opportunity or the performance criteria for an AICP bonus has not been established for the year of the Change in Control, the AICP amount under this definition shall be calculated using the target bonus opportunity from the immediately preceding calendar year.

(d)   “Base Annual Salary” means Executive’s base annual salary as described in Section 5(a) hereof.

(e)   “Board” means the board of directors of the Company.

(f)   “Cause” means in connection with a termination of Executive’s employment by the Company:  (i) embezzlement or theft by Executive of any property of the Company or its Affiliates; (ii) any breach by Executive of any material provision of this Agreement; (iii) any act by Executive constituting a felony or otherwise involving theft, fraud, gross dishonesty, or moral turpitude; (iv) negligence or willful misconduct on the part of Executive in the performance of his duties as an employee, officer, or director of the Company or its Affiliates; (v) Executive’s breach of his fiduciary obligations to the Company or its Affiliates; (vi) Executive’s material violation or breach of the policies or procedures of the Company and its Affiliates (including but not limited to blackout periods for trading Common Stock); or (vii) any chemical dependence of Executive which adversely affects the performance of his duties and responsibilities to the Company or its Affiliates.

(g)   “Change in Control” means a “Change in Control Event” within the meaning of Treasury Regulation § 1.409A-3(i)(5) and described in paragraphs (i), (ii) or (iii) below or any combination thereof as permitted in the Treasury Regulations with respect to the Company:

(i)   A change in ownership that occurs when one person or a group (as determined for the purposes of Code Section 409A) acquires stock that, combined with stock previously owned, controls more than fifty percent (50%) of the value or voting power of the stock of the Company (incremental increases in ownership by a person or group that already owns fifty percent (50%) of the Company prior to such increase do not result in a change in ownership);

(ii)   A change in effective control that occurs on the date that, during any 12-month period, either (x) any person or group acquires stock possessing forty-five percent (45%) or more of the voting power of the Company, or (y) the majority of the Board (or, if applicable, the board of directors of the Company’s ultimate parent) is replaced by persons whose appointment or election is not endorsed by a majority of the Board (or, if applicable, the board of directors of such ultimate parent) prior to the date of the appointment or election; or

(iii)   A change in ownership of a substantial portion of the assets that occurs on the date that a person or a group acquires, during any 12-month period, assets of the Company having a total gross fair market value equal to eighty-five percent (85%) or more of the total gross fair market value of all of the Company’s assets; provided, however, that there is no change in control event under this paragraph (iii) when there is a transfer to:  (w) a shareholder of the Company (immediately before the asset transfer) in exchange for or with respect to its stock; (x) an entity, fifty percent (50%) or more of the total value or voting power of which is owned, directly or indirectly, by the Company immediately after the asset transfer; (y) a person, or more than one person acting as a group, that owns immediately after the asset transfer, directly or indirectly, fifty percent (50%) or more of the total value or voting power of all the outstanding stock of the Company; or (z) an entity, at least fifty percent (50%) of the total value or voting power of which is owned, directly or indirectly, by a person described in item (y) within the meaning of Code Section 409A.For the purposes of this paragraph (iii), “gross fair market value” shall have the meaning as provided in Code Section 409A.

(h)   “Code” means the Internal Revenue Code of 1986, as amended.

(i)   “Common Stock” means common stock, no par value, of the Company, or any successor security issued in lieu thereof.

(j)   “Compensation Committee” means the compensation committee of the Board.

(k)   “Confidential Information” means information (i) disclosed to or known by Executive as a consequence of or through his employment with the Company; (ii) not generally known outside the Company; and (iii) which relates to any aspect of the Company, its Affiliates or their business, research, or development. “Confidential Information” includes, but is not limited to, the Company’s and its Affiliate’s trade secrets, proprietary information, business plans, marketing plans, financial information, compensation and benefit information, cost and pricing information, customer contacts, suppliers, vendors, and information provided to the Company or its Affiliates by a third party under restrictions against disclosure or use by the Company, its Affiliates or others.

(l)   “Conflict of Interest” means any activity which might adversely affect the Company or its Affiliates, including ownership of a material interest in any supplier, contractor, distributor, subcontractor, customer, or other entity with which the Company or its Affiliates does business.

(m)   “Copyright Works” means materials for which copyright protection may be obtained including, but not limited to: literary works (including all written material), computer programs, artistic and graphic works (including designs, graphs, drawings, blueprints, and other works), recordings, models, photographs, slides, motion pictures, and audio-visual works, regardless of the form or manner in which documented or recorded.

(n)   “Company” means Helix Energy Solutions Group, Inc., a Minnesota corporation.

(o)   “Date of Termination” means the date of termination of Executive’s employment by the Company and that is a “Separation from Service” within the meaning of Code Section 409A, which means a termination of Executive’s employment with the Company (and its controlled group within the meaning of Treasury Regulation § 1.409A-1(h)(3)) in accordance with the Company’s policies and procedures; provided, however, that the Company and Executive reasonably anticipate that no further services will be performed after the termination date or that the level of bona fide services Executive will perform after such date (whether as an employee or an independent contractor) would permanently decrease to no more than twenty percent (20%) of the average level of bona fide services performed (whether as an employee or an independent contractor) over the immediately preceding 36-month period or the full period of service to the Company if Executive has been providing services to the Company for less than 36 months.

(p)   “Disability” or “Disabled” means any physical or mental incapacity, disease or affliction, as determined by a legally qualified medical practitioner selected by the Company which prevents Executive to a substantial degree from performing his obligations after reasonable accommodation from the Company.

(q)   “Effective Date” means May 11, 2011.

(r)   “Equity-Based Awards” means stock options, restricted stock, restricted stock units, performance vesting stock, performance stock units, and any other award granted by the Company, which derives its value based upon the Common Stock, regardless whether such award is ultimately intended to be settled in stock or cash.

(s)   “Good Reason” means, in connection with a termination of employment by Executive, the occurrence of any of the following without Executive’s written consent (except in connection with the termination of employment of Executive by the Company for Cause or Disability):

(i)   a material diminution in Executive’s Base Annual Salary;

(ii)   a material diminution in Executive’s authority, duties, or responsibilities;

(iii)   a material change in geographic location at which Executive must perform the services; or

(iv)   any other action or inaction that constitutes a material breach by the Company of the terms of this Agreement.

(t)   “Inventions” means inventions (whether patentable or not), discoveries, improvements, designs, and ideas (whether or not shown or described in writing or reduced to practice) including, and in addition to any such Confidential Information or Copyright Works.

(u)   “LTIP” or “Long Term Incentive Plan” means the Company’s 2005 Long-Term Incentive Plan or other long-term incentive plan of the Company pursuant to which Executive receives Equity Based Awards, as in effect from time to time.

(v)   “Person” means, for the purposes of the term Affiliate in Section 2(a) hereof, and as used in Section 7(e) hereof, any partnership, corporation, limited liability company, group, trust or other legal entity.

(w)   “Retirement” means a termination of Executive’s employment under circumstances as shall constitute retirement from the Company based on age and/or years of employment, as determined by the Board, in its sole discretion, in accordance with written policies adopted by the Board from time to time; in absence of the adoption of such policy, Executive’s resignation on or after attainment of age 65 shall be deemed to be “Retirement” for purposes of this Agreement.

3.   Duration.  This Agreement shall become effective on the Effective Date and shall terminate on the second (2nd) anniversary of the Effective Date, unless earlier terminated as hereinafter provided, provided that commencing on the second anniversary date of the Effective Date and each second anniversary date thereafter, the term of this Agreement shall automatically be extended for two additional years unless, no later than ninety (90) days prior to the applicable anniversary date, the Company or Executive shall give written notice to the other that it or he, respectively, does not wish to extend the term of this Agreement, in which case this Agreement shall terminate on the applicable anniversary date.

4.   Duties and Responsibilities.  Commencing on the Effective Date of this Agreement, Executive shall diligently render his services to the Company as Executive Vice President – Contracting Services in a manner customary for such officers or equivalent positions and in accordance with the Company’s directives, and shall use his best efforts and good faith in fulfilling such responsibilities and in accomplishing such directives.  Executive agrees to devote his full-time efforts, abilities, and attention to the business of the Company, and shall not engage in any activities which will interfere with such efforts.  Executive shall well and faithfully serve the Company during the continuance of his employment hereunder and shall use his best efforts to promote the interests of the Company.  Executive’s principal place of employment will be at the Company’s corporate headquarters in Houston, Texas.  Executive hereby acknowledges that he is a fiduciary with respect to the Company and its Affiliates and shall act in accordance and otherwise comply with his fiduciary obligation to the Company and its Affiliates.

5.   Compensation and Benefits.  In return for the services to be provided by Executive pursuant to this Agreement, the Company agrees to pay Executive as follows:

(a)   Base Annual Salary.  Executive shall receive a Base Annual Salary annually of Three Hundred Fifty Thousand Dollars ($350,000) payable every two weeks, subject to deduction of statutorily required amounts, including but not limited to, withholding for federal, state and local income taxes, and amounts payable by employees of the Company for employee benefits.  The annual salary to be paid by the Company to Executive shall be reviewed at least annually and may from time to time be increased (but may not be decreased) as approved by the Company (any such increased amount shall then be referred to as “Base Annual Salary” for the purposes of this Agreement).

(b)   Annual Incentive Compensation Plan.  Executive shall be eligible to receive an Annual Incentive Compensation Plan bonus, with the components, target and maximum amounts based on a percentage of Executive’s Base Annual Salary, each as determined by the Board or Compensation Committee, in its sole discretion, subject to the terms of the AICP.  Subject to the foregoing, a portion of the annual AICP bonus may be based upon the Company’s financial performance and a portion of the AICP may be based upon achievement of Executive’s individual performance objectives, all as may be determined by the Board or Compensation Committee, in its sole discretion, provided that Executive’s target AICP bonus opportunity for the 2012 service year shall be no less than $375,000. AICP bonuses for each calendar year shall be payable in the following calendar year as determined by the Board or Compensation Committee; provided, however, that payment, if any, shall be made no later than March 15th of such following year.  Executive agrees that upon the Effective Date Executive shall no longer be entitled to earn an enhanced bonus with respect to the 2011 service year, as described in the letter to Executive from the Company dated January 24, 2011, and such letter shall be of no further force or effect.

(c)   Long Term Incentive Plan.  As a senior management executive of the Company, Executive shall participate annually in the Long Term Incentive Plan as determined by and on such terms approved by the Company, the Board or the Compensation Committee, in its sole discretion.The LTIP may include stock options, restricted stock, restricted stock units and/or other types of compensation. In addition, upon the Effective Date, Executive will receive a long term incentive award with a total value of $775,000, consisting of  (i) an award of restricted stock with a value of $348,750 issued under the Company’s 2005 Long Term Incentive Plan, with the number of shares of stock to be determined by the closing price of the Company’s common stock on the day prior to the award, the award and terms and conditions thereof (including but not limited to the pro-rata vesting of such shares over a five-year period beginning on the anniversary of the date of grant) to be  evidenced by a separate Restricted Stock Award Agreement between the Company and Executive, and (ii) a cash opportunity award in the amount of $426,250 issued under the Company’s 2009 Long Term Incentive Cash Plan, the award and terms and conditions thereof (including but not limited to the pro-rata vesting of such award over a five-year period beginning on the anniversary of the date of the grant) to be evidenced by a separate 2009 Long-Term Incentive Cash Plan Award Letter between the Company and Executive.

(d)   Benefits.  Executive shall be entitled to participate in the Company’s various employee benefit plans as the same may be constituted from time to time, including without limitation, the Company’s 401(k) plan, any health insurance plans and any other employee welfare benefit programs, in the same manner as other senior management executives of the Company, subject to the terms and conditions of the plans, as same may be amended or terminated pursuant to their terms from time to time as determined by the Company in its sole discretion.

(e)   Expenses.  Executive shall be reimbursed by the Company for all reasonable business expenses incurred by Executive in performance of his duties hereunder upon the submission of appropriate vouchers, bills or receipts for such expenses in accordance with the Company’s policy, and upon Executive’s reasonable documentation of such expenses, the expenses shall be paid in a cash lump sum payment as soon as reasonably practicable, but in no event later than March 15th of the calendar year following the calendar year in which the expenses are incurred.

(f)   Vacation.  Executive will be provided four (4) weeks’ paid vacation in each calendar year, to be accrued at a prorata monthly rate, and additional paid holidays and similar rights and privileges as are enjoyed generally by Company’s senior management executives.  Vacation shall be subject to the Company’s policy and vacation days must be taken in accordance with the Company’s policy for senior management executives, as may be amended from time to time.

6.   Termination.

(a)   Death, Disability or Retirement.  The Company may terminate Executive’s employment if he is Disabled for six (6) consecutive months or for a total of six (6) months during any 12-month period.  Executive’s employment will be automatically terminated upon his death or Retirement.

(b)   Termination for Cause.  The Company may terminate Executive’s employment immediately for Cause by written notice to Executive.

(c)   Termination Without Cause.  The Company may terminate Executive’s employment without Cause and for any reason upon written notice to Executive.

(d)   Termination by Executive Without Good Reason.  Executive may terminate his employment upon 30 days’ written notice to the Company. In the event Executive terminates his employment in this manner, he shall remain in the Company’s employ subject to all terms and conditions of this Agreement for the entire 30-day period unless instructed otherwise by the Company in writing.

(e)   Termination by Executive for Good Reason.  Executive may terminate his employment for “Good Reason” by giving the Company advance written notice of such intent and the grounds thereof within a period not to exceed 30 days after the existence of the event constituting Good Reason.  After Executive gives such notice, the Company shall have 30 days to correct the Good Reason event, and if the Company does not correct the Good Reason event within the prescribed time, Executive must terminate his employment within 61 days of the date of the event constituting Good Reason in order to be entitled to any benefits under Section 7(d) of this Agreement.  In addition, once an event constitutes Good Reason, if the Company does not correct the event and if Executive does not give notice (as described above) and terminate his employment within 61 days of the event, such specific instance of the event shall no longer constitute Good Reason under this Agreement.

(f)   Resignation of All Positions.  Executive agrees that after any termination of his employment, he will tender his resignation from any position he may hold as an officer or director of the Company or any Affiliate or otherwise associated companies.

7.   Severance and Change in Control Payments and Benefits.  Executive shall be entitled to the following compensation under the following circumstances:

(a)   Death, Disability or Retirement.  In the event Executive’s employment is terminated as a result of his death, Disability or Retirement, Executive’s rights under any Equity-Based Awards or other compensation rights or awards shall be determined in accordance with the controlling plan documents and award agreements and his unpaid Base Annual Salary shall be paid through the Date of Termination in accordance with the Company’s normal payroll practices.  Any unpaid AICP bonus for a calendar year preceding the calendar year of Executive’s Date of Termination shall be paid when the AICP bonus for other participants is paid but in no event later than March 15th of the calendar year following the end of the calendar year of the applicable AICP bonus.  Executive’s award under any AICP to which he would otherwise be entitled in the calendar year of his Date of Termination shall be prorated for the period of his participation in the AICP during the relevant calendar year, and payable at the same time other participants in the AICP receive payment but in no event later than March 15th of the calendar year following the calendar year of the Date of Termination.  Executive shall be reimbursed for all expenses incurred and in accordance with Section 5(e); Executive shall be paid all accrued unused vacation in accordance with the Company’s vacation policy, as amended from time to time, and Executive shall be entitled to all benefits under Section 5(d) subject to the terms and conditions of the applicable plan documents and arrangements, as amended from time to time.

(b)   Termination for Cause or Resignation of Executive Without Good Reason.  If Executive is terminated by the Company for Cause or if Executive resigns or otherwise terminates without Good Reason, no AICP bonus for the calendar year of his Date of Termination will be paid, all other benefits and rights, including Equity-Based Awards shall be determined under the then governing plans and award agreements, and his unpaid Base Annual Salary shall be paid through to the Date of Termination in accordance with the Company’s normal payroll practices.  Any unpaid AICP bonus for a calendar year preceding the calendar year of Executive’s Date of Termination shall be paid in accordance with the terms of the applicable AICP and when the AICP bonus for other participants is paid but in no event later than March 15th of the calendar year following the end of the calendar year of the applicable AICP bonus.  Executive shall be reimbursed for all expenses incurred and in accordance with Section 5(e); Executive shall be paid all accrued unused vacation in accordance with the Company’s vacation policy, as amended from time to time, and Executive shall be entitled to all benefits under Section 5(d) subject to the terms and conditions of the applicable plan documents and arrangements, as amended from time to time.

(c)   Termination Without Cause.  In the event Executive’s employment with the Company is terminated by the Company without Cause, the Company shall pay Executive an amount equal to his Base Annual Salary for the year in which the termination occurs in a lump sum cash payment as soon as administratively feasible following the Date of Termination but no later than 70 days after the Date of Termination (subject to Section 7(h)). There shall be an automatic acceleration of the vesting of any Equity-Based Awards granted to Executive by the Company that were scheduled to vest by their terms within 12 months following the Date of Termination, and to the extent the provisions of this Section 7(c) change the terms of such Equity-Based Awards held by Executive now or in the future, this Section 7(c) shall be deemed an amendment to the agreement between Company and Executive setting forth the terms of such awards and shall form part of such agreement. Except as provided in the previous sentence, Executive’s rights under any Equity-Based Awards or other compensation rights or awards shall be determined according to the controlling plan documents and award agreements, and the benefits provided in this Section 7(c) regarding Executive’s Equity-Based Awards shall be in addition to, and not in limitation of, the value or benefit of any Equity-Based Awards, the exercisability, vesting or payment of which is accelerated or otherwise enhanced pursuant to the terms of the LTIP or agreement heretofore or hereafter adopted between Executive and the Company regarding Equity-Based Awards granted to Executive.  Executive’s unpaid Base Annual Salary shall be paid through his Date of Termination in accordance with the Company’s normal payroll practices. Any unpaid AICP bonus for a year preceding the calendar year of Executive’s Date of Termination shall be paid when the AICP bonus for other participants is paid but in no event later than March 15th of the calendar year following the end of the calendar year of the applicable AICP bonus.  In addition, the Company shall pay Executive his award under any AICP for the calendar year of his Date of Termination  (a) calculated on the basis of the Company and Executive having fully met all performance criteria (financial, personal or otherwise) for a target bonus (which will not include any multiplier that may be applicable to result in a maximum bonus), (b) paid on the basis of a deemed 12-month calendar year participation in the plan, and (c) payable at the same time other participants in the plan receive payment but no later than March 15th of the calendar year following the end of the calendar year of the Date of Termination.  Executive shall be reimbursed for all expenses incurred and in accordance with Section 5(e); Executive shall be paid all accrued unused vacation in accordance with the Company’s vacation policy, as amended from time to time, and Executive shall be entitled to all benefits under Section 5(d) subject to the terms and conditions of the applicable plan documents and arrangements, as amended from time to time.

(d)   Termination by Executive for Good Reason. In the event that Executive terminates his employment with the Company for Good Reason, the Company shall pay Executive an amount equal to his Base Annual Salary for the year in which the termination occurs in a lump sum cash payment as soon as administratively feasible following the Date of Termination but no later than 70 days after the Date of Termination (subject to Section 7(h)). There shall be an automatic acceleration of the vesting of any Equity-Based Awards granted to Executive by the Company that were scheduled to vest by their terms within 12 months following the Date of Termination, and to the extent the provisions of this Section 7(d) change the terms of such Equity-Based Awards held by Executive now or in the future, this Section 7(d) shall be deemed an amendment to the agreement between Company and Executive setting forth the terms of such awards and shall form part of such agreement. Except as provided in the previous sentence, Executive’s rights under any Equity-Based Awards or other compensation rights or awards or benefits shall be determined according to the controlling plan documents and award agreements, and the benefits provided in this Section 7(d) regarding Executive’s Equity-Based Awards shall be in addition to, and not in limitation of, the value or benefit of any Equity-Based Awards, the exercisability, vesting or payment of which is accelerated or otherwise enhanced pursuant to the terms of the LTIP or agreement heretofore or hereafter adopted between Executive and the Company regarding Equity-Based Awards granted to Executive.  Executive’s unpaid Base Annual Salary shall be paid through his Date of Termination in accordance with the Company’s normal payroll practices. Any unpaid AICP bonus for a year preceding the calendar year of Executive’s Date of Termination shall be paid when the AICP bonus for other participants is paid but in no event later than March 15th of the calendar year following the end of the calendar year of the applicable AICP bonus.  In addition, the Company shall pay Executive his award under any AICP for the calendar year of his Date of Termination  (a) calculated on the basis of the Company and Executive having fully met all performance criteria (financial, personal or otherwise) for a target bonus (which will not include any multiplier that may be applicable to result in a maximum bonus), (b) paid on the basis of a deemed 12-month calendar year participation in the plan, and (c) payable at the same time other participants in the plan receive payment but no later than March 15th of the calendar year following the end of the calendar year of the Date of Termination.  Executive shall be reimbursed for all expenses incurred and in accordance with Section 5(e); Executive shall be paid all accrued unused vacation in accordance with the Company’s vacation policy, as amended from time to time, and Executive shall be entitled to all benefits under Section 5(d) subject to the terms and conditions of the applicable plan documents and arrangements, as amended from time to time.

(e)   Change in Control. Notwithstanding the foregoing subsections (a) – (d) of this Section 7 and in lieu thereof, if within the period beginning with the date of a Change in Control and continuing through the second anniversary thereof, the Company terminates Executive’s employment without Cause or Executive terminates his employment for Good Reason, then:

(i)   The Company shall pay Executive as soon as administratively feasible after the date of the Change in Control but no later than 70 days following the date of the Change in Control a lump sum cash amount equal to two (2) times Executive’s Annual Cash Compensation;

(ii)   Executive’s rights under any Equity-Based Awards or other compensation rights, benefits or awards shall be as provided in the governing plan and/or award agreements (subject to paragraph (iv) below);

(iii)   Any unpaid AICP bonus for a calendar year preceding the calendar year of the Change in Control shall be paid when the AICP bonus for other participants is paid but in no event later than March 15th of the calendar year following the end of the calendar year of the applicable AICP bonus;

(iv)   Notwithstanding the provision of any agreement to the contrary, the Company shall cause all of Executive’s existing unvested Equity-Based Awards to be accelerated and vested immediately as of the date of the Change in Control and payment or issuance of shares of Common Stock shall be made pursuant to the applicable plans and/or award agreements (for the avoidance of doubt, the benefits provided for in this Section 7(e)(iv) regarding Executive’s Equity-Based Awards shall be in addition to, and not in limitation of, the value or benefit of any Equity-Based Awards, the exercisability, vesting or payment of which is accelerated or otherwise enhanced pursuant to the terms of the LTIP or other agreement heretofore or hereafter adopted between Executive and the Company regarding Equity-Based Awards granted to Executive).

(v)   Executive shall be promptly reimbursed all reasonable business expenses incurred by him upon reasonable documentation and in accordance with Company policy prior to the date of the Change in Control to be paid no later than March 15th following the end of the calendar year in which the expenses were incurred;

(vi)   Company shall pay a lump sum amount equal to the cost of continuation of group health coverage under COBRA for a period of 18 months based upon the rates of such COBRA coverage for the coverage as in effect for Executive (and his dependents, if applicable) on the date of the Change in Control to be paid in a cash lump sum payment at the same time payment under Section 7(e)(i) is made;

(vii)   If any payments are payable under this Section 7(e), in no event will any amounts be paid or payable under Section 7(a)-(d).

Notwithstanding any other provision of this Agreement, Executive’s employment shall be deemed to have been terminated by the Company without Cause or by Executive with Good Reason following a Change of Control if A) Executive’s employment is terminated by the Company without Cause prior to a Change of Control (whether or not a Change of Control actually occurs) and such termination was at the request of a Person who has entered into an agreement with the Company or its shareholder(s) the consummation of which would constitute a Change of Control, B) Executive terminates his employment with the Company for Good Reason prior to a Change of Control (whether or not a Change of Control actually occurs) and the act, circumstances or event which constitutes Good Reason occurs at the request or direction of such Person or shareholder, or (C) Executive’s employment is terminated by the Company without Cause or by Executive for Good Reason and such termination without Cause or the act, circumstance or event which constitutes Good Reason is otherwise in connection with or in anticipation of a Change of Control and occurred after either a letter of intent or similar agreement with respect to such a transaction or a public announcement of a proposed transaction is made, provided that in the case of (C) above, any requirement that the Company pay the amounts required by Section 7(e)(i) shall only be required if the transaction is in fact consummated, and if the proposed transaction is abandoned or terminated by the Company or the Person or shareholder(s) prior to consummation, then Executive’s entitlement to a payout under Section 7(e)(i) shall revert to that required by Section 7(c) or 7(d), as applicable (as if a deemed Change of Control had not occurred).

(f)   Release of All Claims.  In order to receive any payments (other than any unpaid Base Annual Salary and accrued vacation through to his Date of Termination, if applicable) pursuant to Section 7(c) or (d), Executive shall first be required to execute and return a release in a form and substance satisfactory to the Company which releases the Company and its Affiliates, and their officers, employees, and directors and any employee benefit plan (and any other Company related person as specified in the release) (the “Company Group”) of any claims which Executive may have as against the Company Group and such release must be effective and not revoked within the time prescribed in the release and the release must be returned and effective within the time period specified by the Company in the release but in no event later than 60 days after Executive’s Date of Termination if payments are made pursuant to Section 7(c) or (d).

(g)   No Duty to Mitigate. Executive shall not be required to mitigate the amount of any payment or other benefit required to be paid to Executive pursuant to this Agreement, whether by seeking other employment or otherwise, nor shall the amount of any such payment or other benefit be reduced on account of any compensation earned by Executive as a result of employment.  The Company’s obligation to make the payments provided for in this Agreement (including, but not limited to, the payments under Section 7(c), (d) or (e)) and otherwise perform its obligations hereunder shall not be affected by any counterclaim, recoupment, defense or other claim, right or action which the Company may have against Executive or others, exclusive of payroll withholdings required by law.

(h)   Specified Employees.  Notwithstanding any other provision herein, if Executive is a “Specified Employee” (as that term is defined in Code Section 409A) as of his Date of Termination, then any amounts under this Agreement which are payable upon his “Separation from Service” (within the meaning of Code Section 409A) and subject to the provisions of Code Section 409A and not otherwise excluded under Code Section 409A, shall not be paid until the first (1st) business day that is at least six (6) months after the date after Executive’s Date of Termination (the “Waiting Period”).  Any payments that would have been made to Executive during the Waiting Period but for this Section 7(h) shall instead be made to Executive in the form of a lump sum payment on the date that payments commence pursuant to the preceding sentence with interest (calculated at the short-term applicable federal rate compounded semi-annually) on the amount not paid during the Waiting Period from the Date of Termination through the date of payment.

8.   Inventions, Confidential Information, Patents, and Copyright Works.

(a)   Notification of Company. Upon conception, all Inventions, Confidential Information, and Copyright Works shall become the property of the Company (or the United States Government where required by law) whether or not patent or copyright registration applications are filed for such subject matter. Executive will communicate to the Company promptly and fully all Inventions, or suggestions (whether or not patentable), all Confidential Information or Copyright Works made, designed, created, or conceived by Executive (whether made, designed, created, or conceived solely by Executive or jointly with others) during the period of his employment with the Company: (a) which relate to the actual or anticipated business, research, activities, or development of the Company at the time of the conception; or (b) which result from or are suggested by any work which Executive has done or may do for or on behalf of the Company; or (c) which are developed, tested, improved, or investigated either in part or entirely on time for which Executive was paid by the Company, or using any resources of the Company.

(b)   Transfer of Rights.  Executive agrees, during his employment with the Company, to assign and transfer to and does hereby assign and transfer to the Company Executive’s entire right, title, and interest in all Inventions, Confidential Information, Copyright Works and patents prepared, made or conceived by or in behalf of Executive (solely or jointly with others): (a) which relate in any way to the actual or anticipated business of the Company, or (b) which relate in any way to the actual or anticipated research or development of the Company, or (c) which are suggested by or result, directly or indirectly, from any task assigned to Executive or in which Executive otherwise engages in behalf of the Company. Executive also agrees to do all things necessary to transfer to the Company Executive’s entire right, title, and interest in and to all such Inventions, Confidential Information, Copyright Works or patents as the Company may request, on such forms as the Company may provide, at any time during or after Executive’s employment. Executive will promptly and fully assist the Company during and subsequent to his employment in every lawful way to obtain, protect, and enforce the Company’s patent, copyrights, trade secret or other proprietary rights for Inventions, Confidential Information, Copyright Works or patents in any and all countries.

(c)   Notice of Rights Under State Statutes.  No provision in this Agreement is intended to require assignment of any of Executive’s rights in an Invention for which no equipment, supplies, facilities, Confidential Information, Copyright Works, Inventions, patents or information of the Company was used, and which was (1) developed entirely on Executive’s own time; (2) does not relate directly or indirectly to the business of the Company or to the actual or demonstrably anticipated research or development of the Company; and (3) does not result from any work performed by Executive for the Company or assigned to Executive by the Company.

(d)   Rights in Copyrights.  Unless otherwise agreed in writing by the Company, all Copyright Works prepared wholly or partially by Executive (alone or jointly with others) within the scope of his employment with the Company, shall be deemed a “work made for hire” under the copyright laws and shall be owned by the Company. Executive understands that any assignment or release of such works can only be made by the Company. Executive will do everything reasonably necessary to enable the Company or its nominee to protect its rights in such works. Executive agrees to execute all documents and to do all things necessary to vest in the Company Executive’s right and title to copyrights in such works. Executive shall not assist or work with any third party that is not an employee of the Company to create or prepare any Copyright Works without the prior written consent of the Company.

(e)   Assistance in Preparation of Applications.  During and after employment Executive will promptly and fully assist, if requested by the Company, in the preparation and filing of patents and Copyright Works registrations in any and all countries selected by the Company and will assign to the Company Executive’s entire right, title, and interest in and to such patents and Copyright Works registrations, as well as all Inventions or Copyright Works to which such patents and Copyright Works registrations pertain, to enable any such properties to be prosecuted under the direction of the Company and to ensure that any patent or Copyright Works registration obtained will validly issue to the Company.

(f)   Execute Documents.  During and after employment Executive will promptly sign any and all lawful papers, take all lawful oaths, and do all lawful acts, including testifying, at the request of the Company, in connection with the procurement, grant, enforcement, maintenance, exploitation, or defense against assertion of any patent, trademark, copyright, trade secret or related rights, including applications for protection or registration thereof. Such lawful papers include, but are not limited to, any and all powers, assignments, affidavits, declarations and other papers deemed by the Company to be necessary or advisable.

(g)   Keep Records.  Executive will keep and regularly maintain adequate and current written records of all Inventions, Confidential Information, and Copyright Works he participates in creating, conceiving, developing, and manufacturing. Such records shall be kept and maintained in the form of notes, sketches, drawings, reports, or other documents relating thereto, bearing at least the date of preparation and the signatures or name of each employee contributing to the subject matter reflected in the record. Such records shall be and shall remain the exclusive property of the Company and shall be available to the Company at all times.

(h)   Return of Documents, Equipment, Etc.  All writings, records, and other documents and things comprising, containing, describing, discussing, explaining, or evidencing any Inventions, Confidential Information, or Copyright Works and all equipment, components, parts, tools, and the like in Executive’s custody or possession that have been obtained or prepared in the course of Executive’s employment with the Company shall be the exclusive property of the Company, shall not be copied and/or removed from the premises of the Company, except in pursuit of the business of the Company, and shall be delivered to the Company, without Executive retaining any copies, upon notification of the termination of Executive’s employment or at any other time requested by the Company.  The Company shall have the right to retain, access, and inspect all property of Executive of any kind in the office, work area, and on the premises of the Company upon termination of Executive’s employment and at any time during employment by the Company, to ensure compliance with the terms of this Agreement.

(i)   Other Contracts.  Executive represents and warrants that he is not a Party to any existing contract relating to the granting or assignment to others of any interest in Inventions, Confidential Information, Copyright Works or patents hereafter made by Executive except insofar as copies of such contracts, if any, are attached to this Agreement.

(j)   Assignment After Termination.  Executive recognizes that ideas, Inventions, Confidential Information, Copyright Works, Copyright Works registrations or patents relating to his activities while working for the Company that are conceived or made by Executive, alone or with others, within one (1) year after termination of his employment may have been conceived in significant part while Executive was employed by the Company.  Accordingly, Executive agrees that such ideas, Inventions, Confidential Information, Copyright Works, Copyright Works registrations or patents shall be presumed to have been conceived and made during his employment with the Company and are to be assigned to the Company in accordance with this Section 8.

(k)   Prior Conceptions.  At the end of this Section 8(k), Executive has set forth, if any, what he represents and warrants to be a complete list of all Inventions, if any, patented or unpatented, or Copyright Works, including a brief description thereof (without revealing any confidential or proprietary information of any other Party) which Executive participated in the conception, creation, development, or making of prior to his employment with the Company and for which Executive claims full or partial ownership or other interest, or which are in the physical possession of a former employer and which are therefore excluded from the scope of this Agreement.

Prior Conceptions:  None

9.   Non-Competition, Non-Solicitation, and Confidentiality.  The Company and Executive acknowledge and agree that while Executive is employed pursuant to this Agreement, the Company will give Executive access to Confidential Information of the Company and its Affiliates to which Executive did not have access prior to signing this Agreement and which Executive may need and use during such employment, the receipt of which is hereby acknowledged by Executive; Executive will be provided under this Agreement (i) specialized training on how to perform his duties and (ii) contact with the Company’s and its Affiliates’ customers and potential customers.  In consideration of all of the foregoing, the Company and Executive agree as follows:

(a)   Non-Competition During Employment.  Executive agrees that for the duration of this Agreement, he will not compete with the Company by engaging in (i) the conception, design, development, production, marketing, or servicing in the offshore energy construction services industry in the Gulf of Mexico; or (ii) the oil and gas exploration and production business in the Gulf of Mexico or other fields in which the Company owns interests (for purposes of this Section 9, the “Services”), and that he will not work for, in any capacity, assist, or become affiliated with as an owner, partner, employee, contractor, joint venture or otherwise, either directly or indirectly, any individual or business which performs the Services.

(b)   Non-Competition After Employment.  Executive agrees that for a period of one (1) year after termination of his employment with the Company for any reason he will not compete with the Company by engaging in the conception, design, development, production, marketing, or servicing in the Services, and that he will not work for, in any capacity, assist, or become affiliated with as an owner, partner, employee, contractor, joint venture or otherwise, either directly or indirectly, any individual or business which performs the Services; provided, however, that Executive may accept employment with a business which performs the Services if Executive is employed by a division, affiliate, or subsidiary that does not perform the Services and Executive understands and agrees that he cannot perform any services for the division, subsidiary, or affiliate which does compete with the Company in the provision of the Services.

(c)   Conflicts of Interest.  Executive agrees that for the duration of this Agreement, he will not engage, either directly or indirectly, in any Conflict of Interest, and that Executive will promptly inform a corporate officer of the Company as to each offer received by Executive to engage in any such activity. Executive further agrees to disclose to the Company any other facts of which Executive becomes aware which might involve or give rise to a Conflict of Interest or potential Conflict of Interest.

(d)   Non-Solicitation of Customers.  Executive further agrees that, for the duration of this Agreement, and for a period of one (1) year after the termination of his employment with the Company for any reason, he will not solicit or accept any business for the provision of the Services from any customer or client or prospective customer or client with whom Executive dealt, had contact with or during the time Executive was employed by the Company.

(e)   Non-Solicitation of Employees.  Executive agrees that for the duration of this Agreement, and for a period of one (1) year after the termination of his employment with the Company for any reason, he will not either directly or indirectly, on his own behalf or on behalf of others, solicit, attempt to hire, or hire any person employed by the Company to work for Executive or for any other entity, firm, corporation, or individual; provided, however, that nothing in this Section 9(e) shall prohibit a future employer of Executive from soliciting, attempting to hire, or hiring any person employed by the Company so long as Executive is not directly or indirectly involved in the process including, but not limited to providing or suggesting (directly or indirectly) names of such employees to anyone for purposes of possible employment and/or directing such employees to contact anyone for purposes of possible employment.

(f)   Confidential Information.  Executive further agrees that he will not, except as the Company may otherwise consent or direct in writing, reveal or disclose, sell, use, lecture upon, publish, or otherwise disclose to any third party any Confidential Information or proprietary information of the Company, or authorize anyone else to do these things at any time either during or subsequent to his employment with the Company.  This Section 9(f) shall continue in full force and effect after termination of Executive’s employment and after the termination of this Agreement for any reason.  Executive’s obligations under this Section 9(f) of this Agreement with respect to any specific Confidential Information and proprietary information shall cease when that specific portion of Confidential Information and proprietary information becomes publicly known, in its entirety and without combining portions of such information obtained separately.  It is understood that such Confidential Information and proprietary information of the Company include matters that Executive conceives or develops, as well as matters Executive learns from other employees of the Company.

(g)   Confidential Information of Prior Employer.  Executive will not disclose or use during the period of his employment with the Company any proprietary or confidential information or copyright works, which Executive may have acquired because of employment with an employer other than the Company.

(h)   Time Period Tolled.  The time periods referenced in this Section 9 during which Executive is restrained from competing against the Company shall not include any period of time during which Executive is in breach of this Agreement.  Said time periods referenced in this Section 9 will be tolled, such that the Company will receive the full benefit of the time period in the event Executive breaches this Agreement.

(i)   Breach.  Executive agrees that any breach of Sections 9(a), (b), (c), (d), (e) or (f) above cannot be remedied solely by money damages, and that in addition to any other remedies the Company may have, the Company is entitled to obtain injunctive relief against Executive.  Nothing herein, however, shall be construed as limiting the Company’s right to pursue any other available remedy at law or in equity, including recovery of damages and termination of this Agreement.

(j)   Independent Covenants.  All covenants contained in this Section 9 shall be construed as agreements independent of any other provision of this Agreement, and the existence of any claim or cause of action by Executive against the Company, whether predicated on this Agreement or otherwise, shall not constitute a defense to the enforcement by the Company of such covenants.

10.   Return of Company Property.  Executive agrees to execute and deliver such documents and take all other actions as the Company may request from time to time in order to effect the transfer and delivery to the Company of any of the Company’s or its Affiliate’s assets in the possession or subject to the control of Executive including, without limitation, the Company’s or its Affiliate’s computers, printers, books, records, files, databases, software, Confidential Information, and other documents in whatever form or medium and wherever located, and the Company’s or its Affiliate’s credit cards, travel authority cards, parking and identification badges.

11.   Right to Enter Agreement.  Executive represents and covenants to the Company that he has full power and authority to enter into this Agreement and that the execution of this Agreement will not breach or constitute a default of any other agreement or contract to which he is a Party or by which he is bound.

12.   Assignment.  This Agreement may be assigned by the Company, but cannot be assigned by Executive.  An assignment of this Agreement by the Company shall not relieve the Company of any liability or obligation under this Agreement except any such assignment in connection with or as a result of a Change in Control (including, but not limited to, by operation of law).

13.   Binding Agreement.  The Parties acknowledge that this Agreement shall be binding upon and inure to the benefit of (a) Executive’s heirs, successors, personal representatives, and legal representatives and (b) any successor of the Company.  Any such successor of the Company shall be deemed substituted for the Company under the terms of this Agreement for all purposes.  As used herein, “successor” shall include any person, firm, corporation, or other business entity which at any time, whether by purchase, merger or otherwise, directly or indirectly acquires all or substantially all of the assets or business of the Company.

14.   Notices.  All notices pursuant to this Agreement shall be in writing and sent certified mail, return receipt requested, by hand delivery or by overnight delivery service addressed as follows:

If to Executive: Clifford Chamblee

17303 East Blooming Ct.

Cypress, TX 77429

If to the Company: Helix Energy Solutions Group, Inc.

Attn: President and Chief Executive Officer

400 North Sam Houston Parkway East, Suite 400

Houston, TX  77060

With a copy to: Helix Energy Solutions Group, Inc.

Attn:  General Counsel

400 North Sam Houston Parkway East, Suite 400

Houston, TX 77060

15.   Waiver.  No waiver by either Party to this Agreement of any right to enforce any term or condition of this Agreement, or of any breach hereof, shall be deemed a waiver of such right in the future or of any other right or remedy available under this Agreement.

16.   Severability.  If any provision of this Agreement is determined to be void, invalid, unenforceable, or against public policy, such provisions shall be deemed severable from the Agreement, and the remaining provisions of the Agreement will remain unaffected and in full force and effect.  Furthermore, any breach by the Company of any provision of this Agreement shall not excuse Executive’s compliance with the requirements of Sections 8 or 9, to the extent they are otherwise enforceable.

17.   Arbitration.  Except with respect to injunctive relief which may be sought by the Company or Executive from a court in Harris County, Texas, to which the Parties hereby submit to personal jurisdiction, the Parties agree to resolve any and all claims or controversies past, present, or future arising out of or relating to this Agreement, Executive’s employment and/or termination of employment with the Company, including but not limited to claims for wrongful termination of employment, and claims under the Civil Rights Act of 1866, Title VII of the Civil Rights Act of 1964, the Americans with Disabilities Act, the Age Discrimination in Employment Act, the Family Medical Leave Act, the Sarbanes-Oxley Act, the Equal Pay Act, the Fair Labor Standards Act, Chapter 21 of the Texas Labor Code, formerly known as the Texas Commission on Human Rights Act, the retaliatory discharge provisions of the Texas Worker’s Compensation Act, the Texas Pay Day Act, and any similar state law or local ordinance to binding arbitration under the Federal Arbitration Act, before one neutral arbitrator in the City of Houston, State of Texas, under the American Arbitration Association (“AAA”) National Rules for the Resolution of Employment Disputes.  If the Parties cannot agree on one arbitrator, a list of seven (7) arbitrators will be requested from AAA, and the arbitrator will be selected using alternate strikes with Executive striking first.  The Parties further agree that (i) except as expressly awarded in arbitration and subject to Section 25 below, each party shall be responsible for its own expenses, including but not limited to attorneys’ fees in connection with the cost of the arbitration except that the fees of the arbitrators shall be shared equally by Executive and the Company, (ii) collective actions are not permissible unless agreed upon by the parties in writing, (iii) administrative proceedings under the National Labor Relations Act and Title VII of the Civil Rights Act are not precluded, (iv) the work of Executive involves interstate commerce, and (v) the award rendered by the arbitrator is final and binding, and judgment thereon may be entered in any court having jurisdiction thereof.  The invalidity or unenforceability of any provision of this Section shall not affect the validity or enforceability of any other provision of this Agreement which shall remain in full force and effect; provided, however, that any claim the Company has for breach of the covenants contained in Sections 8 and 9 of this Agreement shall not be subject to mandatory arbitration, and may be pursued in a court of law or equity.

18.   Entire Agreement.  The terms and provisions contained herein shall constitute the entire agreement between the Parties with respect to Executive’s employment with the Company during the time period covered by this Agreement.  This Agreement replaces and supersedes any and all existing agreements entered into between Executive and the Company relating generally to the same subject matter.

19.   Modification of Agreement.  This Agreement may not be changed or modified or released or discharged or abandoned or otherwise terminated, in whole or in part, except by an instrument in writing signed by Executive and an officer or other authorized executive of the Company.

20.   Understand Agreement.  Executive represents and warrants that he has read and understood each and every provision of this Agreement, acknowledges that he has obtained independent legal advice from attorneys of his choice, and confirms that Executive has freely and voluntarily entered into this Agreement.

21.   Governing Law.  This Agreement shall be governed by and construed in accordance with the internal laws of the State of Texas without giving any effect to the conflict of laws provisions thereof.

22.   Code Section 409A.  The Parties agree that the Company may amend and/or operate this Agreement to be exempt from or to comply with Code Section 409A including, but not limited to, using the definitions or other terms required by Code Section 409A and including without limitation any notices, rulings, interpretations or regulations issued under Code Section 409A after the date hereof to avoid the application of penalty taxes under Code Section 409A.  The Company and Executive shall cooperate in good faith for the adoption of such amendments and/or the operation of the Agreement to avoid the application of penalty taxes under Code Section 409A.  The Parties agree that Executive shall have no right to specify the calendar year during which any payment hereunder shall be made.

23.   No Guarantee of Tax Consequences.  None of the Company nor any of its Affiliates or their officers, directors or employees guarantees or shall be responsible or liable for the federal, state, local, domestic and foreign, tax consequences to Executive respecting any payments or benefits provided to Executive under this Agreement, including but not limited to, any excise taxes that may be imposed under Code Section 409A.  Executive acknowledges that the Company has advised him to consult his own counsel and/or tax advisor respecting all of the terms of this Agreement, including but not limited to, Sections 7, 8 and 9.

24.   Withholding Taxes.  The Company may withhold from all salary, bonuses, or other benefits or payments under this Agreement all federal, state, local, domestic and foreign, taxes as shall be required pursuant to any law or governmental ruling or regulation as reasonably determined by the Company.

25.   Legal Fees on Change in Control.  If a Date of Termination occurs after a Change in Control occurs, the Company agrees, upon reasonable documentation, to reimburse to the full extent permitted by law, all legal fees and expenses to a maximum of fifty thousand dollars ($50,000.00) which Executive, Executive’s legal representatives or Executive’s family may reasonably incur arising out of or in connection with any arbitration or litigation, if applicable, concerning the validity or enforceability of any provision of the Agreement, or any action by Executive, Executive’s legal representatives, or Executive’s family to enforce his or their rights under this Agreement, regardless of the outcome of such arbitration or litigation.  The expenses that may be reimbursed under this Section 25 shall in no way modify Executive’s duty to arbitrate any such claims or the arbitration provisions under Section 17.  Notwithstanding the foregoing, to the extent that Code Section 409A is applicable to the expenses under this subsection, and to the extent that no exception under Code Section 409A is applicable, the following shall apply:  (a) all expenses that are includable in income to be paid under this subsection shall only be paid if such expenses are incurred prior to the last day of the second (2nd) calendar year following the calendar year in which the Date of Termination occurs; (b) all expenses must be paid by the end of the third (3rd) calendar year following the calendar year in which the Date of Termination occurs; (c) Executive (or his legal representative or family) must provide the Company with reasonable documentation of such expenses; (d) payments for such expenses will be made within 15 business days after reasonable documentation of the expenses incurred has been provided to the Company (and such documentation must be provided within 45 days after the expenses are incurred) but in no event later than the end of Executive’s taxable year following the year in which the expenses were incurred; and (e) the payments under this subsection cannot be substituted for another benefit.

26.   Disputed Payments and Refusals to Pay.  If following the Date of Termination, the Company fails to make a payment due under Section 7(e) or Section 25 of this Agreement in whole or in part as of the payment date specified in this Agreement, either intentionally or unintentionally, other than with the express or implied consent of Executive, the Company shall owe Executive interest on the delayed payment, compounded quarterly, if  Executive (i) accepts the portion (if any) of the payment that the Company is willing to make (unless such acceptance will result in a relinquishment of the claim to all or part of the remaining amount) and (ii) makes prompt and reasonable good faith efforts to collect the remaining portion of the payment (determined utilizing the standards set forth in Treasury Regulation § 1.409A-3(g)).  Any such interest payments shall become due and payable effective as of the applicable payment date(s) specified in (i) Section 7(e) with respect to the delinquent payment(s) due under Section 7(e) and (ii) Section 25 with respect to the delinquent payment(s) due under Section 25.  Such interest payable under this Section 26 shall be calculated at a rate equal to an amount equal to two percentage points in excess of the prime commercial lending rate announced from time to time by J.P. Morgan Chase Bank or its successor during the period of such nonpayment, compounded quarterly.  The Company shall pay such interest payable under this Section 26 no later than the deadline specified in Treasury Regulation § 1.409A-3(g).

27.   Counterparts.  Any number of counterparts of this Agreement may be executed and each such counterpart shall be deemed to be an original instrument, but all such counterparts together shall constitute but one instrument.  This Agreement may be executed by portable document format (PDF) or facsimile signature which signature shall be binding upon the Parties.

28. Outside Interests. The Company acknowledges that it has been advised that Executive is, and will continue to be, a shareholder and member of the board of directors of UTEC International Limited and Pipeline Services Inc.  The Company agrees that such current and continuing ownership and membership on the same basis on which Executive currently participates in such organizations (i.e., Executive has a passive interest in each of such entities, and does not and will not participate in the award by the Company of any work or contract to such entities), shall not be considered a violation of any provision of this Agreement.

IN WITNESS WHEREOF, the Parties have executed this Agreement effective as of the Effective Date first written above.

EXECUTIVE                                                             THE COMPANY

 HELIX ENERGY SOLUTIONS GROUP, INC.

By:       /s/ Clifford Chamblee      By:   /s/ Owen Kratz                                                   

       ----------------------------------                                               ------------------------------------------------

Name: Clifford Chamblee                                                                                  Owen Kratz

                                President and Chief Executive Officer

Date:  May 11, 2011                                                                     Date: May 11, 2011

EX-15.1

EXHIBIT 15.1

INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM’S

ACKNOWLEDGEMENT LETTER

July 27, 2011

To the Board of Directors and Shareholders

of Helix Energy Solutions Group, Inc.

We are aware of the incorporation by reference in Registration Statement Forms S-3 (Nos. 333-157785, 333-103451 and 333-125276) and Forms S-8 (Nos. 333-126248, 333-58817, 333-50289 and 333-50205) of Helix Energy Solutions Group, Inc. of our report dated July 27, 2011 relating to the unaudited condensed consolidated interim financial statements of Helix Energy Solutions Group, Inc. and subsidiaries that is included in its Form 10-Q for the quarter ended June 30, 2011.

Very truly yours,

 /s/ ERNST & YOUNG LLP

Houston, Texas

EX-31.1

EXHIBIT 31.1

SECTION 302 CERTIFICATION

I, Owen Kratz, the President and Chief Executive Officer of Helix Energy Solutions Group, Inc., certify that:

1.           I have reviewed this quarterly report on Form 10-Q of Helix Energy Solutions Group, Inc.;

2.           Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.           Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.           The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)           designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)           designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)           evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)           disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.           The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)           all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)           any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  July 27, 2011

/s/  Owen Kratz                                                      

Owen Kratz

President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

SECTION 302 CERTIFICATION

I, Anthony Tripodo, the Executive Vice President and Chief Financial Officer of Helix Energy Solutions Group, Inc., certify that:

1.           I have reviewed this quarterly report on Form 10-Q of Helix Energy Solutions Group, Inc.;

2.           Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.           Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.           The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)           designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)           designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)           evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)           disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.           The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)           all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)           any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  July 27, 2011

/s/  Anthony Tripodo                                                      

Anthony Tripodo

Executive Vice President and

Chief Financial Officer

EX-32.1

EXHIBIT 32.1

CERTIFICATION OF CEO AND CFO PURSUANT TO 18 U.S.C. SECTION 1350

(Adopted Pursuant to Section 906 of Sarbanes-Oxley Act of 2002)

Pursuant to section 1350 of chapter 63 of title 18 of the United States Code, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, Owen Kratz, as President and Chief Executive Officer, and Anthony Tripodo, as Executive Vice President and Chief Financial Officer, each hereby certifies that the Quarterly Report of Helix Energy Solutions Group, Inc. (“Helix”) on Form 10-Q for the period ended June 30, 2011, as filed with the Securities and Exchange Commission on the date hereof (the “Report”):

(1)           The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

(2)           The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Helix.

Date:  July 27, 2011

/s/  Owen Kratz                                                      

Owen Kratz

President and Chief Executive Officer

Date:  July 27, 2011

/s/  Anthony Tripodo                                                                

Anthony Tripodo

Executive Vice President and

Chief Financial Officer

EX-99.1

EXHIBIT 99.1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of

Helix Energy Solutions Group, Inc.

We have reviewed the condensed consolidated balance sheet of Helix Energy Solutions Group, Inc. and subsidiaries as of June 30, 2011, and the related condensed consolidated statements of operations for the three-month and six-month periods ended June 30, 2011 and 2010 and the related condensed consolidated statements of cash flows for the six-month periods ended June 30, 2011 and 2010. These financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the condensed consolidated financial statements referred to above for them to be in conformity with U.S. generally accepted accounting principles.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Helix Energy Solutions Group, Inc. and subsidiaries as of December 31, 2010, and the related consolidated statements of operations, shareholders’ equity, and cash flows for the year then ended, not presented herein, and in our report dated February 25, 2011, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2010, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

 /s/ Ernst & Young LLP

Houston, Texas

July 27, 2011

XML



Document and Entity Information	6 Months Ended
	Jun. 30, 2011	Jul. 21, 2011
Document and Entity Information
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2011
Document Fiscal Period Focus	Q2
Document Fiscal Year Focus	2011
Entity Registrant Name	HELIX ENERGY SOLUTIONS GROUP INC
Entity Central Index Key	0000866829
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		105,943,676

XML



Statement of Cash Flow Information

6 Months Ended

Jun. 30, 2011

Statement of Cash Flow Information

Statement of Cash Flow Information

Note 5 – 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 $34.5 million at June 30, 2011 and $35.3 million at December 31, 2010, 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. We have used a small portion of  these escrowed funds to pay for the initial reclamation activities at the South Marsh Island Block 130 field.  Reclamation activities at the field will occur over many years and will be funded with these escrowed amounts.  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 six-month period ended June 30, 2011 and 2010 (in thousands):          

		Six Months Ended
		June 30,
		2011		2010
Interest paid, net of capitalized interest (1)	$	40,220	$	27,847
Income taxes paid	$	7,236	$	6,642

Non-cash investing activities for the six-month periods ended June 30, 2011 and 2010 included $33.7 million and $32.0 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.

XML



Equity Investments

6 Months Ended

Jun. 30, 2011

Equity Investments

Equity Investments

Note 6 – Equity Investments

As of June 30, 2011, we have three investments that we account for using the equity method of accounting: Deepwater Gateway, Independence Hub, and the Clough Helix Joint Venture Pty Ltd. ("Clough Helix JV").  Deepwater Gateway and Independence Hub are included in our Production Facilities segment while the Clough Helix joint venture is a component of our Contracting Services segment.

·Deepwater Gateway, L.L.C.  In June 2002, we, along with Enterprise Products Partners L.P. ("Enterprise"), formed Deepwater Gateway, each with a 50% interest, to design, construct, install, own and operate a tension leg platform production hub primarily for Anadarko Petroleum Corporation's Marco Polo field in the Deepwater Gulf of Mexico. Our investment in Deepwater Gateway totaled $98.3 million and $99.8 million as of June 30, 2011 and December 31, 2010, respectively (including capitalized interest of $1.4 million and $1.5 million at June 30, 2011 and December 31, 2010, respectively).  Distributions from Deepwater Gateway, net to our interest, totaled $1.8 million and $3.6 million for the respective three-month and six-month periods ended June 30, 2011.

·Independence Hub, LLC.  In December 2004, we acquired a 20% interest in Independence Hub, an affiliate of Enterprise.  Independence Hub owns the "Independence Hub" platform located in Mississippi Canyon Block 920 in a water depth of 8,000 feet.  First production through the facility commenced in July 2007.  Our investment in Independence Hub was $81.0 million and $82.4 million as of June 30, 2011 and December 31, 2010, respectively (including capitalized interest of $5.1 million and $5.2 million at June 30, 2011 and December 31, 2010, respectively).  Distributions from Independence Hub, net to our interest, totaled $5.2 million and $9.6 million for the three-month and six-month periods ended June 30, 2011, respectively.

·Clough Helix JV.In February 2010, we announced the formation of the Clough Helix JV with Australian-based engineering and construction company, Clough Projects Australia Pty Ltd ("Clough"), to provide a range of subsea services to offshore operators in the Asia Pacific region. The Clough Helix JV combines our well intervention equipment with Clough's 12-man saturation diving system, which are deployed from the 118 meter long DP2 multiservice vessel, Normand Clough.   In the first quarter of 2011, the Clough Helix JV commenced an approximate six- to nine-month day rate project located offshore China.  Our 50% share of the earnings from the Clough Helix JV totaled $0.7 million and $1.1 million for the three- and six-month periods ended June 30, 2011, respectively as compared to losses of  $4.3 million and $5.7 million in the three- and six-month periods ended June 30, 2010, respectively.   The loss in the 2010 periods primarily represented the mobilization costs of transporting the Normand Clough from the Gulf of Mexico to Singapore and other start up costs.   Our investment in the Clough Helix JV was $9.5 million at June 30, 2011 and $4.9 million at December 31, 2010.

XML



Long-Term Debt

6 Months Ended

Jun. 30, 2011

Long-Term Debt

Long-Term Debt

Note 7 – Long-Term Debt

Scheduled maturities of long-term debt outstanding as of June 30, 2011 were as follows (in thousands):

		Term Loan			Revolving Loans		Senior Unsecured Notes		Convertible Senior Notes (1)			MARAD Debt			Total
Less than one year	$	3,000		$	0	$	0	$	0		$	4,759		$	7,759
One to two years		3,000			0		0		0			4,997			7,997
Two to three years		3,000			0		0		0			5,247			8,247
Three to four years		3,000			0		0		0			5,508			8,508
Four to five years		287,250			0		550,000		0			5,783			843,033
Over five years		0			0		0		300,000			86,222			386,222
Total debt		299,250			0		550,000		300,000			112,516			1,261,766
Current maturities		(3,000	)		0		0		0			(4,759	)		(7,759	)
Long-term debt, less    current maturities	$	296,250		$	0	$	550,000	$	300,000		$	107,757		$	1,254,007
Unamortized debt discount (2)		0			0		0		(14,114	)		0			(14,114	)
Long-term debt	$	296,250		$	0	$	550,000	$	285,886		$	107,757		$	1,239,893

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

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

            At June 30, 2011, unsecured letters of credit issued totaled approximately $48.8 million (see "Credit Agreement" below).  These letters of credit primarily guarantee various contract bidding, contractual performance, including asset retirement obligations, and insurance activities.  The following table details our interest expense and capitalized interest for the three and six month periods ended June 30, 2011 and 2010:

		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2011			2010			2011			2010
		(in thousands)
Interest expense	$	26,029		$	24,597		$	50,796		$	48,946
Interest income		(499	)		(199	)		(975	)		(397	)
Capitalized interest		(252	)		(3,875	)		(307	)		(12,391	)
Interest expense, net	$	25,278		$	20,523		$	49,514		$	36,158

            Included below is a summary of certain components of our indebtedness. For additional information regarding our debt see Note 9 of our 2010 Form 10-K.

Senior Unsecured Notes

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

Credit Agreement

In July 2006, we entered into a credit agreement (the "Credit Agreement") containing both a term loan (the "Term Loan") and a revolving credit facility (the "Revolving Credit Facility"). The $835 million term loan was used to fund the cash portion of the acquisition of Remington Oil and Gas Corporation in July 2006.   The original borrowing capacity under the Revolving Credit Facility was $300 million.  In June 2011, we amended our Credit Agreement as further discussed below.  For additional information regarding the previous terms of our Credit Agreement see Note 9 of our 2010 Form 10-K.

The fourth amendment to our Credit Agreement, among other things:

·increases the Revolving Credit Facility to $600.0 million (capacity was $435 million prior to the closing of the fourth amendment);

·extends the maturity date of the Term Loan from July 1, 2013 to a maturity date that is the earlier of (A) July 1, 2016, or (B), if our currently outstanding Senior Unsecured Notes due in 2016 are not fully re-financed or repaid by July 1, 2015, July 1, 2015;

·provided for the repayment of $109.4 million of the outstanding principal portion of the Term Loan together with accrued interest thereon and related costs;

·extends the maturity date of the Revolving Credit Facility from November 30, 2012 to a maturity date that is the earlier of (A) January 1, 2016, or (B), if our currently outstanding Senior Unsecured Notes due in 2016 are not fully re-financed or repaid by July 1, 2015, July 1, 2015;

·relaxes limitations on our right to dispose of certain Contracting Services assets comprising collateral to the Credit Agreement; 

·increases the amount of restricted payments in the form of stock repurchases or redemptions that we are permitted to repurchase or redeem up to $50 million of our common stock; 

·permits us to repurchase or redeem all or part of our Convertible Senior Notes or Senior Unsecured Notes assuming certain conditions are met pro forma for any such  transaction, including maintaining minimum levels of liquidity (defined as cash on hand and availability under our Revolving Credit Facility) of (A) $400 million with respect to the Convertible Senior Notes, and (B) $500 million with respect to the Senior Unsecured Notes; and 

·increases the maximum amount of all investments permitted in subsidiaries that are neither loan parties nor whose equity interests are pledged from $150 million to $200 million.

With the closing of the fourth amendment, the Term Loan currently bears interest either at the one-, two-, three- or six-month LIBOR or Base Rates at our election plus a margin of between 3.25% and 3.5%  (LIBOR margin) or 2.25% to 2.5% (Base Rate margin) depending on current leverage ratios.  Our average interest rate on the Term Loan for the six-month periods ended June 30, 2011 and 2010 was approximately 3.2% and 2.9%, respectively, including the effects of our interest rate swaps (Note 16). 

The full amount of the Revolving Credit Facility may be used for issuances of letters of credit.  At June 30, 2011, we had no amounts drawn on the Revolving Credit Facility and our availability under the Revolving Credit Facility totaled $551.2 million, net of $48.8 million of letters of credit issued.

With the closing of the fourth amendment, the borrowings outstanding under the Revolving Credit Facility will  bear interest based on one-, two-, three- or six-month LIBOR rates or on Base Rates at our election plus an applicable margin. The LIBOR margin ranges from 2.5% to 3.5% and the Base Rate margin rates from 1.5% to 2.5%, depending on our consolidated leverage ratio. In connection with the closing of the fourth amendment to our Credit Agreement (as noted above), we borrowed $109.4 million under the Revolving Credit Facility and prepaid a portion of the Term Loan.   We subsequently repaid all borrowings under our Revolving Credit Facility with our available cash on hand at June 30, 2011. 

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

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

Convertible Senior Notes

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

The Convertible Senior Notes can be converted prior to the stated maturity (March 2025) under certain triggering events specified in the indenture governing the Convertible Senior Notes.  To the extent we do not have long-term financing secured to cover the conversion, the Convertible Senior Notes would be classified as a current liability in the accompanying condensed consolidated balance sheet.  No conversion triggers were met during either the three or six-month periods ended June 30, 2011 or 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 (see Note 9 of our 2010 Form 10-K).   Effective January 1, 2009 we adopted certain new required accounting standards that required us to discount the principal amount of our Convertible Senior Notes. Following adoption of these accounting standards, the effective interest rate for the Convertible Senior Notes is 6.6%.

Our average share price was below the $32.14 per share conversion price for all the periods presented in this Quarterly Report on Form 10-Q.  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")  pursuant to Title XI of the Merchant Marine Act of 1936, which is administered by the Maritime Administration, was used to finance the construction of the Q4000. The MARAD Debt is payable in equal semi-annual installments beginning in August 2002 and matures in February 2027. 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 February 2027 maturity date. 

Other

                In accordance with our Credit Agreement and our Senior Unsecured Notes, Convertible Senior Notes and MARAD Debt agreements, we are required to comply with certain covenants, including the maintenance of minimum net worth, working capital and debt-to-equity requirements, and restrictions that limit our ability to incur certain types of additional indebtedness.  As of June 30, 2011, we were in compliance with these covenants and restrictions. 

Deferred financing costs of $30.1 million and $25.7 million are included in other assets, net as of June 30, 2011 and December 31, 2010, respectively, and are being amortized over the life of the applicable loan agreements.  We charged to expense $0.8 million of deferred financing costs associated with the repayment of $109.4 million of our Term Loan balance in June 2011 (see "Credit Agreement" above)

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Income Taxes

6 Months Ended

Jun. 30, 2011

Income Taxes

Income Taxes

Note 8 – Income Taxes

             The effective tax rates for the three-month and six-month periods ended June 30, 2011 were 27.7% and 27.2%, respectively.  The effective tax rates for the three-month and six-month periods ended June 30, 2010 reflected benefits of 38.1% and 37.0%, respectively.  The variance primarily reflects the increased benefit derived from the effect of lower tax rates in certain foreign jurisdictions. 

            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.

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Comprehensive Income (Loss)

6 Months Ended

Jun. 30, 2011

Comprehensive Income (Loss)

Comprehensive Income (Loss)

Note 9 – Comprehensive Income (Loss)

            The components of total comprehensive income (loss) for the three and six-month periods ended June 30, 2011 and 2010 were as follows (in thousands):

		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2011			2010			2011		2010
Net income (loss), including noncontrolling interests	$	42,109		$	(85,073	)	$	68,744	$	(102,075	)
Other comprehensive income (loss), net of tax
Foreign currency translation gain (loss)		(1,416	)		(3,106	)		699		(13,808	)
Unrealized gain on hedges, net		20,970			2,063			10,403		16,103
Unrealized loss on investment available for sale		0			(481	)		0		(556	)
Total other comprehensive income (loss)	$	61,663		$	(86,597	)	$	79,846	$	(100,336	)

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

	June 30,			December 31,
	2011			2010
Cumulative foreign currency translation adjustment	$	(21,563	)	$	(22,262	)
Unrealized loss on hedges, net		(6,393	)		(16,796	)
Accumulated other comprehensive loss	$	(27,956	)	$	(39,058	)

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Earnings Per Share

6 Months Ended

Jun. 30, 2011

Earnings Per Share

Earnings Per Share

Note 10 – Earnings Per Share

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

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

		Three Months Ended				Three Months Ended
		June 30, 2011				June 30, 2010
		Income		Shares		Income		Shares
Basic:
Net income (loss) applicable to common shareholders	$	41,313			$	(85,551	)
Less: Undistributed net income allocable to participating securities		(514	)			0
Net income (loss) applicable to common stock	$	40,799		104,673	$	(85,551	)	104,125

		Three Months Ended June 30, 2011			Three Months Ended June 30, 2010
		Income	Shares		Income		Shares
Diluted:
Net  income (loss) per common share – Basic	$	40,799	104,673	$	(85,551	)	104,125
Effect of dilutive securities:
Stock options		0	106		0		0
Undistributed earnings reallocated to participating securities		3	0		0		0
Convertible Senior Notes		0	0		0		0
Convertible preferred stock		10	361		0		0
Net income (loss) per common share – Diluted	$	40,812	105,140	$	(85,551	)	104,125

		Six Months Ended				Six Months Ended
		June 30, 2011				June 30, 2010
		Income		Shares		Income		Shares
Basic:
Net income (loss) applicable to common shareholders	$	67,170			$	(103,442	)
Less: Undistributed net income allocable to participating securities		(850	)			—
Net income (loss) applicable to common stock	$	66,320		104,573	$	(103,442	)	103,610

		Six Months Ended June 30, 2011			Six Months Ended June 30, 2010
		Income	Shares		Income		Shares
Diluted:
Net  income (loss) per common share –  Basic	$	66,320	104,573	$	(103,442	)	103,610
Effect of dilutive securities:
Stock options		0	90		0		0
Undistributed earnings reallocated to participating securities		4	0		0		0
Convertible Senior Notes		0	0		0		0
Convertible preferred stock		20	361		0		0
Net income (loss) per common share –  Diluted	$	66,344	105,024	$	(103,442	)	103,610

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 had an anti-dilutive effect on our EPS calculation, meaning it would have increased 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

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Stock-Based Compensation Plans

6 Months Ended

Jun. 30, 2011

Stock-Based Compensation Plans

Stock-Based Compensation Plans

Note 11 – Stock-Based Compensation Plans

We have two stock-based compensation plans: the 1995 Long-Term Incentive Plan, as amended (the "1995 Incentive Plan") and the 2005 Long-Term Incentive Plan, as amended (the "2005 Incentive Plan").  As of June 30, 2011, there were 967,435 shares available for grant under our 2005 Incentive Plan.

There were no stock option grants in the three- and six-month periods ended June 30, 2011 and 2010. During the six-month period ended June 30, 2011, we made the following restricted share grants to executive officers, selected management employees and non-employee members of the board of directors under the 2005 incentive plan:

Date of Grant	Shares		Market Value Per Share	Vesting Period
January 4, 2011	475,804	$	12.14	20% per year over five years
January 4, 2011	4,427		12.14	100% on January 1, 2013
April 1, 2011	2,907		17.20	100% on January 1, 2013
May 11, 2011	21,608		16.14	20% per year over five years

            Compensation cost is recognized over the applicable vesting periods on a straight-line basis. 

For the three- and six-month periods ended June 30, 2011, $2.0 million and $4.9 million, respectively, was recognized as compensation expense related to restricted shares as compared with $2.1 million and $4.6 million during the three- and six-month periods ended June 30, 2010, 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.  Some of the cash awards are indexed to our Company common stock and the payment amount at each vesting date will fluctuate based on the common stock's performance as a result, the compensation expense associated with those awards is re-measured to fair value each reporting period with corresponding changes being recorded as a charge to earnings as appropriate.   

Total compensation expense under the 2009 LTI plan totaled $1.6 million and $4.6 million for the three- and six-month periods ended June 30, 2011, respectively.  For the three- and six-month periods ended June 30, 2010, total compensation under the 2009 LTI plan totaled $0.9 million and $2.6 million, respectively.  The liability balance under the 2009 LTI Plan was $6.6 million at June 30, 2011 and $7.9 million at December 31, 2010, including $5.7 million at June 30, 2011 and $6.2 million at December 31, 2010 associated with the variable portion of the 2009 LTI plan.

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

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Business Segment Information

6 Months Ended

Jun. 30, 2011

Business Segment Information

Business Segment Information

Note 12 – Business Segment Information

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

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

 

		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2011			2010			2011			2010
		(in thousands)
Revenues —
Contracting Services	$	171,353		$	202,317		$	302,890		$	356,517
Production Facilities		20,545			21,391			36,115			22,711
Oil and Gas		172,458			102,586			341,317			193,301
Intercompany elimination		(26,037	)		(27,032	)		(50,396	)		(71,697	)
Total	$	338,319		$	299,262		$	629,926		$	500,832
Income (loss) from operations —
Contracting Services	$	30,565		$	43,781		$	33,831		$	71,267
Production Facilities (1)		11,920			12,977			17,876			12,940
Oil and Gas		43,064			(154,943	)		96,304			(155,607	)
Corporate (2)		(9,112	)		(12,597	)		(19,553	)		(35,475	)
Intercompany elimination		(19	)		(6,114	)		71			(18,419	)
Total	$	76,418		$	(116,896	)	$	128,529		$	(125,294	)
Equity in earnings of equity investments (Note 6)	$	5,887		$	1,656		$	11,537		$	6,711

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

(2)The six-month period ended June 30, 2010, included $13.8 million of $17.5 million settlement of a third party claim against us in March 2010 (Note 14).

            Intercompany segment revenues during the three- and six-month periods ended June 30, 2011 and 2010 were as follows:

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2011		2010		2011		2010
		(in thousands)
Contracting Services	$	14,295	$	24,426	$	27,164	$	68,167
Production Facilities		11,742		2,606		23,232		3,530
Total	$	26,037	$	27,032	$	50,396	$	71,697

            Intercompany segment gross profit (losses) during the three- and six-month periods ended June 30, 2011 and 2010 were as follows:

		Three Months Ended					Six Months Ended
		June 30,					June 30,
		2011			2010		2011			2010
		(in thousands)
Contracting Services	$	63		$	3,701	$	39		$	15,143
Production Facilities		(44	)		2,413		(110	)		3,293
Total	$	19		$	6,114	$	(71	)	$	18,436

                Our identifiable assets as of June 30, 2011 and December 31, 2010 were as follows:

	June 30, 2011		December 31, 2010
		(in thousands)
Identifiable Assets —
Contracting Services	$	1,869,593	$	1,856,016
Production Facilities		518,220		512,990
Oil and Gas		1,172,824		1,223,014
Total	$	3,560,637	$	3,592,020

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Related Party Transactions

6 Months Ended

Jun. 30, 2011

Related Party Transactions

Related Party Transactions

Note 13 – Related Party Transactions

In April 2000, we acquired a 20% working interest in Gunnison, a deepwater Gulf of Mexico prospect, from a third party.  Financing for the exploratory costs of approximately $20 million was provided by an investment partnership (OKCD Investments, Ltd. or "OKCD"), the investors of which include current and former Helix senior management, in exchange for a revenue interest that is an overriding royalty interest of 25% of Helix's 20% working interest. Production began in December 2003. Our payments to OKCD totaled $2.7 million and $5.1 million for the three-month and six-month periods ended June 30, 2011, respectively, and $3.0 million and $6.1 million in the three-month and six-month periods ended June 30, 2010, respectively.  Our Chief Executive Officer, Owen Kratz, through Class A limited partnership interests in OKCD, personally owns approximately 80.7% of the partnership. In 2000, OKCD also awarded Class B income participations to key Helix employees, who are required to maintain their employment status with Helix in order to retain such income participations. 

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2011

Commitments and Contingencies

Commitments and Contingencies

Note 14 – Commitments and Contingencies

Litigation and Claims

In March 2009, we were notified of a third party's intention to terminate an international construction contract with one of our subsidiaries based on a claimed breach of that contract.  Under the terms of the contract, our potential liability was generally capped for actual damages at approximately 32 million Australian dollars ("AUD").  We asserted a counterclaim that in the aggregate approximated $12 million U.S. dollars.  On March 30, 2010, an out of court settlement of these claims was reached.  In April 2010, pursuant to the terms of the settlement, we paid the third party 15 million AUD to settle all its damage claims against us.   We also agreed not to seek any further payment of our counter claims against them.   In the first quarter of 2010, our results included approximately $17.5 million in expenses associated with this settlement agreement, including $13.8 million for the litigation settlement payment and $3.7 million to write off our remaining trade receivable from the third party.  These amounts were recorded as selling, general and administrative expenses in the accompanying condensed consolidated statements of operations.  

Loss Contract

As discussed in Note 16 of the 2010 Form 10-K, in 2010 our Australian subsidiary contracted for a project to plug, abandon and salvage subsea wells in an oil and gas field located offshore China.  As previously reported as of the year ended December 31, 2010, we had recorded an aggregate pre-tax loss of approximately $30 million related to this project which reflected the difficulty we had in plugging the wells because of certain structural issues, start-up issues with our recently repaired subsea intervention device and significant weather related delays.  In the first quarter of 2011, this project ended and we recorded an additional pre-tax loss of approximately $0.2 million.  Our remaining trade receivable related to this project is $6.7 million.  We believe this amount is collectable, however, if we are unable to collect any of this amount any variance would increase the recorded loss for the project.   

Contingencies and Claims

We were subcontracted to perform development work for a large gas field offshore India.  Work commenced in the fourth quarter of 2007 and we completed our scope of work in the third quarter of 2009.  To date we have collected approximately $303 million related to this project with an amount of trade receivables and claims yet to be collected.  We have requested arbitration in India pursuant to the terms of the subcontract to pursue our claims and the prime contractor has also requested arbitration and has asserted certain counterclaims against us.  If we are not successful in resolving these matters through ongoing discussions with the prime contractor, then arbitration in India remains a potential remedy.  Based on number of factors associated with the ongoing negotiations with the prime contractor, in 2010 we established an allowance against our trade receivable balance that reduces its balance to an amount we believe is ultimately realizable (see Notes 16 and 18 of our 2010 Form 10-K).  However, at the time of this filing no final commercial resolution of this matter has been reached.

We have received value added tax (VAT) assessments from the State of Andhra Pradesh, India (the "State") in the amount of approximately $28 million related to our subsea and diving contract entered into in December 2006 in India for the tax years 2007, 2008, 2009, and  2010. The State claims we owe unpaid taxes related to products consumed by us during the period of the contract.  We are of the opinion that the State has arbitrarily assessed this VAT tax and has no foundation for the assessment, and believe that we have complied with all rules and regulations as it relates to VAT in the State. We also believe that our position is supported by law and intend to vigorously defend our position. However, the ultimate outcome of this assessment and our potential liability from it, if any, cannot be determined at this time. If the current assessment is upheld, it may have a material negative effect on our consolidated results of operations while also impacting our financial position.

We are involved in various legal proceedings, primarily involving claims for personal injury under the General Maritime Laws of the United States and the Jones Act based on alleged negligence. In addition, from time to time we incur other claims, such as contract disputes, in the normal course of business.

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Condensed Consolidated Balance Sheets (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Current assets:
Cash and cash equivalents	$ 414,189	$ 391,085
Accounts receivable - Trade, net of allowance for uncollectible accounts of $4,395 and $4,527, respectively	212,406	177,293
Unbilled revenue	18,325	33,712
Costs in excess of billing	1,978	15,699
Other current assets	110,334	123,065
Total current assets	757,232	740,854
Property and equipment	4,586,583	4,486,077
Less - accumulated depreciation	(2,111,273)	(1,958,997)
Property and equipment, net	2,475,310	2,527,080
Other assets:
Equity investments	188,772	187,031
Goodwill	62,902	62,494
Other assets, net	76,421	74,561
Total assets	3,560,637	3,592,020
Current liabilities:
Accounts payable	148,142	159,381
Accrued liabilities	190,226	198,237
Current maturities of long-term debt	7,759	10,179
Total current liabilities	346,127	367,797
Long-term debt	1,239,893	1,347,753
Deferred income taxes	431,821	413,639
Asset retirement obligations	166,458	170,410
Other long-term liabilities	5,432	5,777
Total liabilities	2,189,731	2,305,376
Convertible preferred stock	1,000	1,000
Commitments and contingencies
Shareholders' equity:
Common stock, no par, 240,000 shares authorized, 105,948 and 105,592 shares issued, respectively	911,393	906,957
Retained earnings	459,875	392,705
Accumulated other comprehensive loss	(27,956)	(39,058)
Total controlling interest shareholders' equity	1,343,312	1,260,604
Noncontrolling interests	26,594	25,040
Total equity	1,369,906	1,285,644
Total liabilities and shareholders' equity	$ 3,560,637	$ 3,592,020

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Fair Value Measurements

6 Months Ended

Jun. 30, 2011

Fair Value Measurements

Fair Value Measurements

Note 15 – Fair Value Measurements

Fair Value Measurements

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

• Level 1.  Observable inputs such as quoted prices in active markets;

• Level 2.  Inputs, other than the quoted prices in active markets, that are observable either directly or indirectly; and

• Level 3.  Unobservable inputs in which there is little or no market data, which require the reporting entity to develop its own assumptions.

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

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

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

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

The following table provides additional information related to assets and liabilities measured at fair value on a recurring basis at June 30, 2011 (in thousands):

		Level 1		Level 2 (1)		Level 3		Total	Valuation Technique
Assets:
Oil and gas swaps and collars	$	0	$	7,531	$	0	$	7,531	(c)
Foreign currency forwards		0		305		0		305	(c)
Liabilities:
Oil and gas swaps and collars		0		16,680		0		16,680	(c)
Fair value of long term debt(2)		1,182,173		122,417		0		1,304,590	(a), (b)
Interest rate swaps		0		1,157		0		1,157	(c)
Total net liability	$	1,182,173	$	132,418	$	0	$	1,314,591

(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)We have elected not to record our debt at fair value in the accompanying condensed consolidated balance sheets. See Note 7 for additional information regarding our long term debt.   The fair value of our long term debt at June 30, 2011 is as follows:

		Fair Value		Carrying Value
Term Loan (matures July 2015)	$	299,998	$	299,250
Revolving Credit Facility (matures July 2015)		0		0
Convertible Senior Notes (matures March 2025)		299,175		300,000	(a)
Senior Unsecured Notes (matures January 2016)		583,000		550,000
MARAD Debt (matures February 2027) (b)		122,417		112,516
Total	$	1,304,590	$	1,261,766

(a)Amount excludes the $14.1 million of unamortized discount recorded on the Convertible Senior Notes at June 30, 2011.

(b) The estimated fair value of all debt, other than MARAD Debt, 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.

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

In the second quarter of 2011, we recorded impairment charge on seven of our oil and gas properties.  These impairment charges reduced these oil and gas properties to their estimated fair value, which, for six of the properties, including our only U.K. oil and gas property, was zero and for the remaining property its  estimated fair value was $2.9 million at June 30, 2011.  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 amounts 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 amounts of the impairment charges were $7.0 million, which reduced these properties to their aggregate fair value of $28.2 million. See Note 4 for additional information regarding our oil and gas property impairment charges.

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Derivative Instruments and Hedging Activities

6 Months Ended

Jun. 30, 2011

Derivative Instruments and Hedging Activities

Derivative Instruments and Hedging Activities

Note 16 – Derivative Instruments and Hedging Activities

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

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

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

Commodity Price Risks

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

As of June 30, 2011, we have the following volumes under derivative contracts related to our oil and gas producing activities totaling approximately 3.5 MMBbl of oil and 9.4 Bcf of natural gas:

Production Period	Instrument Type	Average Monthly Volumes	Weighted Average Price
Crude Oil:			(per barrel)
July 2011 — December 2011	Swap	175.8 MBbl	$82.49
July 2011 — December 2011	Collar	53.3 MBbl	$  95.00 — $124.70
October 2011 — December 2011	Collar	12.5 MBbl	$100.00 — $122.80a
January 2012 — December 2012	Collar	75.0 MBbl	$  96.67 — $118.57
January 2012 — December 2012	Collar	91.7 MBbl	$100.00 — $120.25a
Natural Gas:			(per Mcf)
July 2011 — December 2011	Swap	725.8 Mmcf	$4.97
January 2012 — December 2012	Swap	250.0 Mmcf	$4.77
January 2012 — December 2012	Collar	166.7 Mmcf	$4.75 —  $5.09

a.The prices quoted in the table above are primarily NYMEX Henry Hub for natural gas or NYMEX West Texas Intermediate for crude oil.   As footnoted above these costless collar contracts are priced as Brent crude oil.

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

Variable Interest Rate Risks

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

Foreign Currency Exchange Risks

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

Quantitative Disclosures Related to Derivative Instruments

The following tables present the fair value and balance sheet classification of our derivative instruments as of June 30, 2011 and December 31, 2010.  The fair value amounts below are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements.  

Derivatives designated as hedging instruments are as follows:

	As of June 30, 2011			As of December 31, 2010
	Balance Sheet Location		Fair Value	Balance Sheet Location		Fair Value
	(in thousands)
Asset Derivatives:
Oil contracts	Other current assets	$	3,381	Other current assets	$	0
Natural gas contracts	Other current assets		2,302	Other current assets		5,324
Natural gas contracts	Other assets, net		32	Other assets, net		0
Oil contracts	Other assets, net		1,816	Other assets, net		0
Interest rate swaps	Other assets, net		0	Other assets, net		0
		$	7,531		$	5,324

	As of June 30, 2011			As of December 31, 2010
	Balance Sheet Location		Fair Value	Balance Sheet Location		Fair Value
	(in thousands)
Liability Derivatives:
Oil contracts	Accrued liabilities	$	16,055	Accrued liabilities	$	28,855
Interest rate swaps	Accrued liabilities		1,157	Accrued liabilities		1,751
Oil contracts	Other long-term liabilities		399	Other long-term liabilities		0
Natural gas contracts	Other long-term liabilities		226	Other long-term liabilities		913
Interest rate swaps	Other long-term liabilities		0	Other long-term liabilities		115
		$	17,837		$	31,634

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

	As of June 30, 2011			As of December 31, 2010
	Balance Sheet Location		Fair Value	Balance Sheet Location		Fair Value
	(in thousands)
Asset Derivatives:
Foreign exchange forwards	Other current assets	$	305	Other current assets	$	148
Foreign exchange forwards	Other assets, net		0	Other assets, net		42
		$	305		$	190
Liability Derivatives:
		$	0		$	0

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, 2011 and 2010.

		Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)
		Three Months Ended June 30,					Six Months Ended June 30,
		2011(1)		2010(1)			2011(1)		2010(1)
		(in thousands)
Oil and natural gas commodity contracts	$	20,720	$	2,575		$	9,942	$	17,205
Interest rate swaps		250		(512	)		461		(1,102	)
	$	20,970	$	2,063		$	10,403	$	16,103

(1)      All unrealized gains (losses) related to our derivatives are expected to be reclassified into earnings by no later than December 31, 2012. The last of our interest swaps will mature in January 2012 and we have foreign exchange forwards and oil and natural gas commodity contracts that have maturities through June and December 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,
			2011			2010			2011			2010
Oil and natural gas commodity contracts	Oil and gas revenue	$	(11,860	)	$	9,663		$	(18,185	)	$	10,464
Interest rate swaps	Net interest expense		(591	)		(469	)		(1,071	)		(887	)
		$	(12,451	)	$	9,194		$	(19,256	)	$	9,577

The following table presents the impact of derivative instruments that no longer qualify for hedge accounting or were not designated as hedges on our condensed consolidated income statement for the three and six month periods ended June 30, 2011 and 2010:

	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,
			2011		2010			2011		2010
			(in thousands)
Natural gas contracts	Gain on oil and gas derivative contracts	$	0	$	2,482		$	0	$	2,482
Foreign exchange forwards	Other income (expense)		6		(398	)		614		(3,305	)
		$	6	$	2,084		$	614	$	(823	)

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Condensed Consolidated Guarantor and Non-Guarantor Financial Information

6 Months Ended

Jun. 30, 2011

Condensed Consolidated Guarantor and Non-Guarantor Financial Information

Condensed Consolidated Guarantor and Non-Guarantor Financial Information

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

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

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(in thousands)

(Unaudited)

	As of June 30, 2011
		Helix		Guarantors		Non-Guarantors			Consolidating Entries			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	387,772	$	2,413	$	24,004		$	0		$	414,189
Accounts receivable, net		54,325		106,506		51,575			0			212,406
Unbilled revenue		2,219		0		18,084			0			20,303
Income taxes receivable		63,514		0		13,075			(67,530	)		9,059
Other current assets		47,610		42,191		12,712			(1,238	)		101,275
Total current assets		555,440		151,110		119,450			(68,768	)		757,232
Intercompany		1,294		294,433		(212,007	)		(83,720	)		0
Property and equipment, net		221,300		1,554,186		704,756			(4,932	)		2,475,310
Other assets:
Equity investments in unconsolidated affiliates		0		0		188,772			0			188,772
Equity investments in affiliates		1,947,501		28,432		0			(1,975,933	)		0
Goodwill, net		0		45,107		17,795			0			62,902
Other assets, net		48,499		38,119		19,639			(29,836	)		76,421
Due from subsidiaries/parent		90,965		275,900		0			(366,865	)		0
	$	2,864,999	$	2,387,287	$	838,405		$	(2,530,054	)	$	3,560,637
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	41,121	$	82,403	$	24,618		$	0		$	148,142
Accrued liabilities		58,787		96,184		35,255			0			190,226
Income taxes payable		0		84,684		0			(84,684	)		0
Current maturities of long-term debt		3,000		0		4,759			0			7,759
Total current liabilities		102,908		263,271		64,632			(84,684	)		346,127
Long-term debt		1,132,136		0		107,757			0			1,239,893
Deferred income taxes		213,232		126,992		97,650			(6,053	)		431,821
Asset retirement obligations		0		166,458		0			0			166,458
Other long-term liabilities		1,335		3,480		617			0			5,432
Due to parent		0		0		116,451			(116,451	)		0
Total liabilities		1,449,611		560,201		387,107			(207,188	)		2,189,731
Convertible preferred stock		1,000		0		0			0			1,000
Total equity		1,414,388		1,827,086		451,298			(2,322,866	)		1,369,906
	$	2,864,999	$	2,387,287	$	838,405		$	(2,530,054	)	$	3,560,637

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(in thousands)

	As of December 31, 2010
		Helix		Guarantors		Non-Guarantors			Consolidating Entries			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	376,434	$	3,294	$	11,357		$	0		$	391,085
Accounts receivable, net		61,846		91,659		23,788			0			177,293
Unbilled revenue		11,990		0		37,421			0			49,411
Income taxes receivable		19,334		0		7,195			(20,430	)		6,099
Other current assets		63,306		49,557		12,889			(8,786	)		116,966
Total current assets		532,910		144,510		92,650			(29,216	)		740,854
Intercompany		1,906		263,920		(171,513	)		(94,313	)		0
Property and equipment, net		217,153		1,605,906		709,082			(5,061	)		2,527,080
Other assets:
Equity investments in unconsolidated affiliates		0		0		187,031			0			187,031
Equity investments in affiliates		1,998,289		29,899		0			(2,028,188	)		0
Goodwill, net		0		45,107		17,387			0			62,494
Other assets, net		43,971		38,324		21,900			(29,634	)		74,561
Due from subsidiaries/parent		95,398		105,434		0			(200,832	)		0
	$	2,889,627	$	2,233,100	$	856,537		$	(2,387,244	)	$	3,592,020
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	60,308	$	56,107	$	42,966		$	0		$	159,381
Accrued liabilities		58,074		107,874		32,289			0			198,237
Income taxes payable		0		36,678		0			(36,678	)		0
Current maturities of long-term debt		4,326		0		14,301			(8,448	)		10,179
Total current liabilities		122,708		200,659		89,556			(45,126	)		367,797
Long-term debt		1,237,587		0		110,166			0			1,347,753
Deferred income taxes		185,453		135,101		98,968			(5,883	)		413,639
Asset retirement obligations		0		170,410		0			0			170,410
Other long-term liabilities		1,421		3,691		665			0			5,777
Due to parent		0		0		120,884			(120,884	)		0
Total liabilities		1,547,169		509,861		420,239			(171,893	)		2,305,376
Convertible preferred stock		1,000		0		0			0			1,000
Total equity		1,341,458		1,723,239		436,298			(2,215,351	)		1,285,644
	$	2,889,627	$	2,233,100	$	856,537		$	(2,387,244	)	$	3,592,020

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(in thousands)

(Unaudited)

	Three Months Ended June 30, 2011
		Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated
Net revenues	$	20,545		$	247,855		$	92,926		$	(23,007	)	$	338,319
Cost of sales		15,123			173,897			71,730			(22,629	)		238,121
Gross profit (loss)		5,422			73,958			21,196			(378	)		100,198
Gain on oil & gas derivative contracts		0			0			0			0			0
Gain (loss) on sale or acquisition of assets		(22	)		0			0			0			(22	)
Selling, general and administrative expenses...		(9,574	)		(9,915	)		(4,658	)		389			(23,758	)
Income (loss) from operations		(4,174	)		64,043			16,538			11			76,418
Equity in earnings of investments		58,929			4,194			5,887			(63,123	)		5,887
Net interest expense and other		(18,243	)		(5,890	)		108			0			(24,025	)
Income (loss) before income taxes		36,512			62,347			22,533			(63,112	)		58,280
Provision (benefit) for income taxes		(4,790	)		20,319			637			5			16,171
Net income (loss), including noncontrolling interests		41,302			42,028			21,896			(63,117	)		42,109
Less net income applicable to noncontrolling interests		0			0			0			(786	)		(786	)
Preferred stock dividends		(10	)		0			0			0			(10	)
Net income (loss) applicable to Helix common shareholders	$	41,292		$	42,028		$	21,896		$	(63,903	)	$	41,313

	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		0			2,482			0			0			2,482
Gain (loss) on sale or acquisition of assets		0			0			(14	)		0			(14	)
Selling, general 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		(15,319	)		(5,002	)		(1,878	)		0			(22,199	)
Income (loss) before income taxes		(82,994	)		(137,652	)		23,974			59,233			(137,439	)
Provision (benefit) for income taxes		(1,872	)		(49,351	)		1,221			(2,364	)		(52,366	)
Net income (loss), including noncontrolling interests		(81,122	)		(88,301	)		22,753			61,597			(85,073	)
Less net income applicable to noncontrolling interests		0			0			0			(444	)		(444	)
Preferred stock dividends		(34	)		0			0			0			(34	)
Net income (loss) applicable to Helix common shareholders	$	(81,156	)	$	(88,301	)	$	22,753		$	61,153		$	(85,551	)

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(in thousands)

(Unaudited)

	Six Months Ended June 30, 2011
		Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated
Net revenues	$	36,127		$	489,897		$	150,802		$	(46,900	)	$	629,926
Cost of sales		31,716			339,128			128,008			(46,200	)		452,652
Gross profit (loss)		4,411			150,769			22,794			(700	)		177,274
Gain on oil & gas derivative contracts		0			0			0			0			0
Gain (loss) on sale or acquisition of assets		(6	)		0			0			0			(6	)
Selling, general and administrative expenses...		(20,760	)		(19,951	)		(8,812	)		784			(48,739	)
Income (loss) from operations		(16,355	)		130,818			13,982			84			128,529
Equity in earnings of investments		107,036			(1,468	)		11,537			(105,568	)		11,537
Net interest expense and other		(35,527	)		(10,599	)		525			0			(45,601	)
Income (loss) before income taxes		55,154			118,751			26,044			(105,484	)		94,465
Provision (benefit) for income taxes		(11,963	)		42,060			(4,404	)		28			25,721
Net income (loss), including noncontrolling interests		67,117			76,691			30,448			(105,512	)		68,744
Less net income applicable to noncontrolling interests		0			0			0			(1,554	)		(1,554	)
Preferred stock dividends		(20	)		0			0			0			(20	)
Net income (loss) applicable to Helix common shareholders	$	67,097		$	76,691		$	30,448		$	(107,066	)	$	67,170

	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		0			2,482			0			0			2,482
Gain (loss) on sale or acquisition of assets		0			287			5,946			0			6,233
Selling, general 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		(22,708	)		(12,568	)		(8,143	)		0			(43,419	)
Income (loss) before income taxes		(101,702	)		(125,838	)		16,694			48,844			(162,002	)
Provision (benefit) for income taxes		(6,668	)		(45,136	)		(3,650	)		(4,473	)		(59,927	)
Net income (loss), including noncontrolling interests		(95,034	)		(80,702	)		20,344			53,317			(102,075	)
Less net income applicable to noncontrolling interests		0			0			0			(1,273	)		(1,273	)
Preferred stock dividends		(94	)		0			0			0			(94	)
Net income (loss) applicable to Helix common shareholders	$	(95,128	)	$	(80,702	)	$	20,344		$	52,044		$	(103,442	)

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

	Six Months Ended June 30, 2011
			Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated
Cash flow from operating activities:
Net income (loss), including noncontrolling interests		$	67,117		$	76,691		$	30,448		$	(105,512	)	$	68,744
Adjustments to reconcile net income (loss), including noncontrolling interests to net cash provided by (used in) operating activities:
Equity in earnings of affiliates			(107,036	)		1,468			0			105,568			0
Other adjustments			21,261			180,193			(14,149	)		(5,476	)		181,829
Net cash provided by (used in) operating
activities			(18,658	)		258,352			16,299			(5,420	)		250,573
Cash flows from investing activities:
Capital expenditures			(15,699	)		(76,331	)		(14,092	)		0			(106,122	)
Investments in equity investments			0			0			(2,699	)		0			(2,699	)
Distributions from equity investments, net			0			0			1,593			0			1,593
Proceeds from sale of Cal Dive common stock			3,588			0			0			0			3,588
Decrease (increase) in restricted cash			0			863			0			0			863
Net cash used in investing activities			(12,111	)		(75,468	)		(15,198	)		0			(102,777	)
Cash flows from financing activities:
Repayments of debt			(111,191	)		0			(3,507	)		0			(114,698	)
Deferred financing costs			(9,014	)		0			0			0			(9,014	)
Preferred stock dividends paid			(20	)		0			0			0			(20	)
Repurchase of common stock			(1,012	)		0			0			0			(1,012	)
Excess tax benefit from stock-based  compensation			(1,196	)		0			0			0			(1,196	)
Exercise of stock options, net			1,672			0			0			0			1,672
Intercompany financing			162,868			(183,765	)		15,477			5,420			0
Net cash provided by (used in) financing activities			42,107			(183,765	)		11,970			5,420			(124,268	)
Effect of exchange rate changes on cash and cash equivalents			0			0			(424	)		0			(424	)
Net increase (decrease) in cash and cash equivalents			11,338			(881	)		12,647			0			23,104
Cash and cash equivalents:
Balance, beginning of year			376,434			3,294			11,357			0			391,085
Balance, end of period		$	387,772		$	2,413		$	24,004		$	0		$	414,189

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(in thousands)

	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	)		0			(61,631	)		0
Other adjustments			17,776			243,919			(13,101	)		(10,119	)		238,475
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	)		0			(135,612	)
Investments in equity investments			0			0			(6,307	)		0			(6,307	)
Distributions from equity investments, net			0			0			8,132			0			8,132
Insurance recovery			7,020			9,086			0			0			16,106
Decrease (increase) in restricted cash			0			109			0			0			109
Net cash used in investing activities			(40,943	)		(71,008	)		(5,621	)		0			(117,572	)
Cash flows from financing activities:
Repayments of debt			(2,163	)		0			(3,570	)		0			(5,733	)
Deferred financing costs			(2,792	)		0			0			0			(2,792	)
Preferred stock dividends paid			(94	)		0			0			0			(94	)
Repurchases of common stock			(9,127	)		0			0			0			(9,127	)
Excess tax benefit from stock-based  compensation			(2,163	)		0			0			0			(2,163	)
Exercise of stock options, net			163			0			0			0			163
Intercompany financing			62,654			(86,591	)		5,504			18,433			0
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			0			0			246			0			246
Net increase (decrease) in cash and cash equivalents			(6,987	)		2,513			3,802			0			(672	)
Cash and cash equivalents:
Balance, beginning of year			258,742			2,522			9,409			0			270,673
Balance, end of period		$	251,755		$	5,035		$	13,211		$	0		$	270,001

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Details of Certain Accounts (Tables)

6 Months Ended

Jun. 30, 2011

Details of Certain Accounts

Other Current Assets

		June 30,		December 31,
		2011		2010
		(in thousands)
Other receivables	$	854	$	1,247
Prepaid insurance		12,141		12,375
Other prepaids		12,692		11,623
Spare parts inventory		21,850		25,333
Current deferred tax assets		37,533		49,200
Hedging assets		5,988		5,472
Gas imbalance		5,961		6,001
Income tax receivable		9,059		6,099
Investment held for sale (a)		0		2,835
Other		4,256		2,880
	$	110,334	$	123,065

a.In March 2011, we sold our remaining 500,000 shares of Cal Dive common stock.  These sales transactions resulted in net proceeds of approximately $3.6 million and a pre-tax gain of $0.8 million.   In the fourth quarter of 2010, we recognized a $2.2 million other than temporary loss on our investment in Cal Dive common shares (see Notes 2 and 3 of our 2010 Form 10-K for additional information regarding our former Investment in Cal Dive common stock). 

Other Assets, Net

		June 30,		December 31,
		2011		2010
		(in thousands)
Restricted cash	$	34,476	$	35,339
Deferred drydock expenses, net		7,616		11,086
Deferred financing costs, net		30,127		25,697
Intangible assets with finite lives, net		602		636
Other		3,600		1,803
	$	76,421	$	74,561

Accrued Liabilities

		June 30,		December 31,
		2011		2010
		(in thousands)
Accrued payroll and related benefits	$	33,148	$	38,026
Royalties payable		17,115		15,008
Current asset retirement obligations		64,349		64,526
Unearned revenue		8,504		4,094
Billing in excess of cost		6,346		3,869
Accrued interest		27,347		27,308
Hedge liability		17,212		30,606
Other		16,205		14,800
	$	190,226	$	198,237

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Oil and Gas Properties (Tables)

6 Months Ended

Jun. 30, 2011

Oil and Gas Properties

Components of Exploration Expense

		Three Months Ended					Six Months Ended
		June 30,					June 30,
		2011		2010			2011			2010
Delay rental and geological and geophysical costs...	$	1,299	$	1,182		$	1,654		$	1,528
Impairment of unproved properties (a)		6,640		0			6,640			0
Dry hole expense		0		(10	)		(9	)		(190	)
Total exploration expense	$	7,939	$	1,172		$	8,285		$	1,338

a. Reflects costs associated with a deepwater lease in which the term expired during the second quarter of 2011.

Changes in Asset Retirement Obligations

Asset retirement obligation at December 31, 2010	$	234,936
Liability incurred during the period		672
Liability settled during the period		(25,273	)
Revision in estimated cash flows		12,842
Accretion expense (included in depreciation and amortization)		7,630
Asset retirement obligations at June 30, 2011	$	230,807

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Statement of Cash Flow Information (Tables)

6 Months Ended

Jun. 30, 2011

Statement of Cash Flow Information

Supplemental Cash Flow Information

		Six Months Ended
		June 30,
		2011		2010
Interest paid, net of capitalized interest (1)	$	40,220	$	27,847
Income taxes paid	$	7,236	$	6,642

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Long-Term Debt (Tables)

6 Months Ended

Jun. 30, 2011

Long-Term Debt

Maturities of Long-Term Debt

		Term Loan			Revolving Loans		Senior Unsecured Notes		Convertible Senior Notes (1)			MARAD Debt			Total
Less than one year	$	3,000		$	0	$	0	$	0		$	4,759		$	7,759
One to two years		3,000			0		0		0			4,997			7,997
Two to three years		3,000			0		0		0			5,247			8,247
Three to four years		3,000			0		0		0			5,508			8,508
Four to five years		287,250			0		550,000		0			5,783			843,033
Over five years		0			0		0		300,000			86,222			386,222
Total debt		299,250			0		550,000		300,000			112,516			1,261,766
Current maturities		(3,000	)		0		0		0			(4,759	)		(7,759	)
Long-term debt, less    current maturities	$	296,250		$	0	$	550,000	$	300,000		$	107,757		$	1,254,007
Unamortized debt discount (2)		0			0		0		(14,114	)		0			(14,114	)
Long-term debt	$	296,250		$	0	$	550,000	$	285,886		$	107,757		$	1,239,893

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

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

Interest Expense and Capitalized Interest

		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2011			2010			2011			2010
		(in thousands)
Interest expense	$	26,029		$	24,597		$	50,796		$	48,946
Interest income		(499	)		(199	)		(975	)		(397	)
Capitalized interest		(252	)		(3,875	)		(307	)		(12,391	)
Interest expense, net	$	25,278		$	20,523		$	49,514		$	36,158

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Comprehensive Income (Loss) (Tables)

6 Months Ended

Jun. 30, 2011

Comprehensive Income (Loss)

Components of Total Comprehensive Income (Loss)

		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2011			2010			2011		2010
Net income (loss), including noncontrolling interests	$	42,109		$	(85,073	)	$	68,744	$	(102,075	)
Other comprehensive income (loss), net of tax
Foreign currency translation gain (loss)		(1,416	)		(3,106	)		699		(13,808	)
Unrealized gain on hedges, net		20,970			2,063			10,403		16,103
Unrealized loss on investment available for sale		0			(481	)		0		(556	)
Total other comprehensive income (loss)	$	61,663		$	(86,597	)	$	79,846	$	(100,336	)

Components of Accumulated Other Comprehensive Loss

	June 30,			December 31,
	2011			2010
Cumulative foreign currency translation adjustment	$	(21,563	)	$	(22,262	)
Unrealized loss on hedges, net		(6,393	)		(16,796	)
Accumulated other comprehensive loss	$	(27,956	)	$	(39,058	)

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Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 2011

Earnings Per Share

Computations of Basic and Diluted EPS

		Three Months Ended				Three Months Ended
		June 30, 2011				June 30, 2010
		Income		Shares		Income		Shares
Basic:
Net income (loss) applicable to common shareholders	$	41,313			$	(85,551	)
Less: Undistributed net income allocable to participating securities		(514	)			0
Net income (loss) applicable to common stock	$	40,799		104,673	$	(85,551	)	104,125

		Three Months Ended June 30, 2011			Three Months Ended June 30, 2010
		Income	Shares		Income		Shares
Diluted:
Net  income (loss) per common share – Basic	$	40,799	104,673	$	(85,551	)	104,125
Effect of dilutive securities:
Stock options		0	106		0		0
Undistributed earnings reallocated to participating securities		3	0		0		0
Convertible Senior Notes		0	0		0		0
Convertible preferred stock		10	361		0		0
Net income (loss) per common share – Diluted	$	40,812	105,140	$	(85,551	)	104,125

		Six Months Ended				Six Months Ended
		June 30, 2011				June 30, 2010
		Income		Shares		Income		Shares
Basic:
Net income (loss) applicable to common shareholders	$	67,170			$	(103,442	)
Less: Undistributed net income allocable to participating securities		(850	)			—
Net income (loss) applicable to common stock	$	66,320		104,573	$	(103,442	)	103,610

		Six Months Ended June 30, 2011			Six Months Ended June 30, 2010
		Income	Shares		Income		Shares
Diluted:
Net  income (loss) per common share –  Basic	$	66,320	104,573	$	(103,442	)	103,610
Effect of dilutive securities:
Stock options		0	90		0		0
Undistributed earnings reallocated to participating securities		4	0		0		0
Convertible Senior Notes		0	0		0		0
Convertible preferred stock		20	361		0		0
Net income (loss) per common share –  Diluted	$	66,344	105,024	$	(103,442	)	103,610

Excluded Securities on Diluted Shares Calculation

	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

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Stock-Based Compensation Plans (Tables)

6 Months Ended

Jun. 30, 2011

Stock-Based Compensation Plans

Restricted Shares Granted

Date of Grant	Shares		Market Value Per Share	Vesting Period
January 4, 2011	475,804	$	12.14	20% per year over five years
January 4, 2011	4,427		12.14	100% on January 1, 2013
April 1, 2011	2,907		17.20	100% on January 1, 2013
May 11, 2011	21,608		16.14	20% per year over five years

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Condensed Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Current assets:
Allowance for uncollectible accounts	$ 4,395	$ 4,527
Shareholders' equity:
Common stock, par value
Common stock, shares authorized	240,000	240,000
Common stock, shares issued	105,948	105,592

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Business Segment Information (Tables)

6 Months Ended

Jun. 30, 2011

Business Segment Information

Schedule of Segment Reporting Information by Segment

		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2011			2010			2011			2010
		(in thousands)
Revenues —
Contracting Services	$	171,353		$	202,317		$	302,890		$	356,517
Production Facilities		20,545			21,391			36,115			22,711
Oil and Gas		172,458			102,586			341,317			193,301
Intercompany elimination		(26,037	)		(27,032	)		(50,396	)		(71,697	)
Total	$	338,319		$	299,262		$	629,926		$	500,832
Income (loss) from operations —
Contracting Services	$	30,565		$	43,781		$	33,831		$	71,267
Production Facilities (1)		11,920			12,977			17,876			12,940
Oil and Gas		43,064			(154,943	)		96,304			(155,607	)
Corporate (2)		(9,112	)		(12,597	)		(19,553	)		(35,475	)
Intercompany elimination		(19	)		(6,114	)		71			(18,419	)
Total	$	76,418		$	(116,896	)	$	128,529		$	(125,294	)
Equity in earnings of equity investments (Note 6)	$	5,887		$	1,656		$	11,537		$	6,711

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

(2)The six-month period ended June 30, 2010, included $13.8 million of $17.5 million settlement of a third party claim against us in March 2010 (Note 14).

Summary of Intercompany Segment Revenues

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2011		2010		2011		2010
		(in thousands)
Contracting Services	$	14,295	$	24,426	$	27,164	$	68,167
Production Facilities		11,742		2,606		23,232		3,530
Total	$	26,037	$	27,032	$	50,396	$	71,697

Intercompany Segment Gross Profit (Losses)

		Three Months Ended					Six Months Ended
		June 30,					June 30,
		2011			2010		2011			2010
		(in thousands)
Contracting Services	$	63		$	3,701	$	39		$	15,143
Production Facilities		(44	)		2,413		(110	)		3,293
Total	$	19		$	6,114	$	(71	)	$	18,436

Summary of Identifiable Assets

	June 30, 2011		December 31, 2010
		(in thousands)
Identifiable Assets —
Contracting Services	$	1,869,593	$	1,856,016
Production Facilities		518,220		512,990
Oil and Gas		1,172,824		1,223,014
Total	$	3,560,637	$	3,592,020

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2011

Fair Value Measurements

Assets and Liabilities Measured at Fair Value on a Recurring Basis

		Level 1		Level 2 (1)		Level 3		Total	Valuation Technique
Assets:
Oil and gas swaps and collars	$	0	$	7,531	$	0	$	7,531	(c)
Foreign currency forwards		0		305		0		305	(c)
Liabilities:
Oil and gas swaps and collars		0		16,680		0		16,680	(c)
Fair value of long term debt(2)		1,182,173		122,417		0		1,304,590	(a), (b)
Interest rate swaps		0		1,157		0		1,157	(c)
Total net liability	$	1,182,173	$	132,418	$	0	$	1,314,591

(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)We have elected not to record our debt at fair value in the accompanying condensed consolidated balance sheets. See Note 7 for additional information regarding our long term debt.   The fair value of our long term debt at June 30, 2011 is as follows:

		Fair Value		Carrying Value
Term Loan (matures July 2015)	$	299,998	$	299,250
Revolving Credit Facility (matures July 2015)		0		0
Convertible Senior Notes (matures March 2025)		299,175		300,000	(a)
Senior Unsecured Notes (matures January 2016)		583,000		550,000
MARAD Debt (matures February 2027) (b)		122,417		112,516
Total	$	1,304,590	$	1,261,766

(a)Amount excludes the $14.1 million of unamortized discount recorded on the Convertible Senior Notes at June 30, 2011.

(b)The estimated fair value of all debt, other than MARAD Debt, 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.

Fair Value of Long Term Debt

		Fair Value		Carrying Value
Term Loan (matures July 2015)	$	299,998	$	299,250
Revolving Credit Facility (matures July 2015)		0		0
Convertible Senior Notes (matures March 2025)		299,175		300,000	(a)
Senior Unsecured Notes (matures January 2016)		583,000		550,000
MARAD Debt (matures February 2027) (b)		122,417		112,516
Total	$	1,304,590	$	1,261,766

(a)Amount excludes the $14.1 million of unamortized discount recorded on the Convertible Senior Notes at June 30, 2011.

(b) The estimated fair value of all debt, other than MARAD Debt, 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.

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Derivative Instruments and Hedging Activities (Tables)

6 Months Ended

Jun. 30, 2011

Derivative Instruments and Hedging Activities

Volumes Under Derivative Contracts Related to Oil and Gas Producing Activities

Production Period	Instrument Type	Average Monthly Volumes	Weighted Average Price
Crude Oil:			(per barrel)
July 2011 — December 2011	Swap	175.8 MBbl	$82.49
July 2011 — December 2011	Collar	53.3 MBbl	$  95.00 — $124.70
October 2011 — December 2011	Collar	12.5 MBbl	$100.00 — $122.80a
January 2012 — December 2012	Collar	75.0 MBbl	$  96.67 — $118.57
January 2012 — December 2012	Collar	91.7 MBbl	$100.00 — $120.25a
Natural Gas:			(per Mcf)
July 2011 — December 2011	Swap	725.8 Mmcf	$4.97
January 2012 — December 2012	Swap	250.0 Mmcf	$4.77
January 2012 — December 2012	Collar	166.7 Mmcf	$4.75 —  $5.09

Derivatives Designated as Hedging Instruments

	As of June 30, 2011			As of December 31, 2010
	Balance Sheet Location		Fair Value	Balance Sheet Location		Fair Value
	(in thousands)
Asset Derivatives:
Oil contracts	Other current assets	$	3,381	Other current assets	$	0
Natural gas contracts	Other current assets		2,302	Other current assets		5,324
Natural gas contracts	Other assets, net		32	Other assets, net		0
Oil contracts	Other assets, net		1,816	Other assets, net		0
Interest rate swaps	Other assets, net		0	Other assets, net		0
		$	7,531		$	5,324

	As of June 30, 2011			As of December 31, 2010
	Balance Sheet Location		Fair Value	Balance Sheet Location		Fair Value
	(in thousands)
Liability Derivatives:
Oil contracts	Accrued liabilities	$	16,055	Accrued liabilities	$	28,855
Interest rate swaps	Accrued liabilities		1,157	Accrued liabilities		1,751
Oil contracts	Other long-term liabilities		399	Other long-term liabilities		0
Natural gas contracts	Other long-term liabilities		226	Other long-term liabilities		913
Interest rate swaps	Other long-term liabilities		0	Other long-term liabilities		115
		$	17,837		$	31,634

Derivatives Not Designated as Hedging Instruments

	As of June 30, 2011			As of December 31, 2010
	Balance Sheet Location		Fair Value	Balance Sheet Location		Fair Value
	(in thousands)
Asset Derivatives:
Foreign exchange forwards	Other current assets	$	305	Other current assets	$	148
Foreign exchange forwards	Other assets, net		0	Other assets, net		42
		$	305		$	190
Liability Derivatives:
		$	0		$	0

Impact of Derivative Instruments on Accumulated Comprehensive Income (Loss)

		Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)
		Three Months Ended June 30,					Six Months Ended June 30,
		2011(1)		2010(1)			2011(1)		2010(1)
		(in thousands)
Oil and natural gas commodity contracts	$	20,720	$	2,575		$	9,942	$	17,205
Interest rate swaps		250		(512	)		461		(1,102	)
	$	20,970	$	2,063		$	10,403	$	16,103

(1)      All unrealized gains (losses) related to our derivatives are expected to be reclassified into earnings by no later than December 31, 2012. The last of our interest swaps will mature in January 2012 and we have foreign exchange forwards and oil and natural gas commodity contracts that have maturities through June and December 2012, respectively.

Gain (Loss) Reclassified from Accumulated OCI into Income

	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,
			2011			2010			2011			2010
Oil and natural gas commodity contracts	Oil and gas revenue	$	(11,860	)	$	9,663		$	(18,185	)	$	10,464
Interest rate swaps	Net interest expense		(591	)		(469	)		(1,071	)		(887	)
		$	(12,451	)	$	9,194		$	(19,256	)	$	9,577

Impact of Non Designated Derivative Instruments on Income Statement

	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,
			2011		2010			2011		2010
			(in thousands)
Natural gas contracts	Gain on oil and gas derivative contracts	$	0	$	2,482		$	0	$	2,482
Foreign exchange forwards	Other income (expense)		6		(398	)		614		(3,305	)
		$	6	$	2,084		$	614	$	(823	)

XML



Condensed Consolidated Guarantor and Non-Guarantor Financial Information (Tables)

6 Months Ended

Jun. 30, 2011

Condensed Consolidated Guarantor and Non-Guarantor Financial Information

Schedule of Condensed Consolidating Balance Sheets

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(in thousands)

(Unaudited)

	As of June 30, 2011
		Helix		Guarantors		Non-Guarantors			Consolidating Entries			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	387,772	$	2,413	$	24,004		$	0		$	414,189
Accounts receivable, net		54,325		106,506		51,575			0			212,406
Unbilled revenue		2,219		0		18,084			0			20,303
Income taxes receivable		63,514		0		13,075			(67,530	)		9,059
Other current assets		47,610		42,191		12,712			(1,238	)		101,275
Total current assets		555,440		151,110		119,450			(68,768	)		757,232
Intercompany		1,294		294,433		(212,007	)		(83,720	)		0
Property and equipment, net		221,300		1,554,186		704,756			(4,932	)		2,475,310
Other assets:
Equity investments in unconsolidated affiliates		0		0		188,772			0			188,772
Equity investments in affiliates		1,947,501		28,432		0			(1,975,933	)		0
Goodwill, net		0		45,107		17,795			0			62,902
Other assets, net		48,499		38,119		19,639			(29,836	)		76,421
Due from subsidiaries/parent		90,965		275,900		0			(366,865	)		0
	$	2,864,999	$	2,387,287	$	838,405		$	(2,530,054	)	$	3,560,637
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	41,121	$	82,403	$	24,618		$	0		$	148,142
Accrued liabilities		58,787		96,184		35,255			0			190,226
Income taxes payable		0		84,684		0			(84,684	)		0
Current maturities of long-term debt		3,000		0		4,759			0			7,759
Total current liabilities		102,908		263,271		64,632			(84,684	)		346,127
Long-term debt		1,132,136		0		107,757			0			1,239,893
Deferred income taxes		213,232		126,992		97,650			(6,053	)		431,821
Asset retirement obligations		0		166,458		0			0			166,458
Other long-term liabilities		1,335		3,480		617			0			5,432
Due to parent		0		0		116,451			(116,451	)		0
Total liabilities		1,449,611		560,201		387,107			(207,188	)		2,189,731
Convertible preferred stock		1,000		0		0			0			1,000
Total equity		1,414,388		1,827,086		451,298			(2,322,866	)		1,369,906
	$	2,864,999	$	2,387,287	$	838,405		$	(2,530,054	)	$	3,560,637

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(in thousands)

	As of December 31, 2010
		Helix		Guarantors		Non-Guarantors			Consolidating Entries			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	376,434	$	3,294	$	11,357		$	0		$	391,085
Accounts receivable, net		61,846		91,659		23,788			0			177,293
Unbilled revenue		11,990		0		37,421			0			49,411
Income taxes receivable		19,334		0		7,195			(20,430	)		6,099
Other current assets		63,306		49,557		12,889			(8,786	)		116,966
Total current assets		532,910		144,510		92,650			(29,216	)		740,854
Intercompany		1,906		263,920		(171,513	)		(94,313	)		0
Property and equipment, net		217,153		1,605,906		709,082			(5,061	)		2,527,080
Other assets:
Equity investments in unconsolidated affiliates		0		0		187,031			0			187,031
Equity investments in affiliates		1,998,289		29,899		0			(2,028,188	)		0
Goodwill, net		0		45,107		17,387			0			62,494
Other assets, net		43,971		38,324		21,900			(29,634	)		74,561
Due from subsidiaries/parent		95,398		105,434		0			(200,832	)		0
	$	2,889,627	$	2,233,100	$	856,537		$	(2,387,244	)	$	3,592,020
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	60,308	$	56,107	$	42,966		$	0		$	159,381
Accrued liabilities		58,074		107,874		32,289			0			198,237
Income taxes payable		0		36,678		0			(36,678	)		0
Current maturities of long-term debt		4,326		0		14,301			(8,448	)		10,179
Total current liabilities		122,708		200,659		89,556			(45,126	)		367,797
Long-term debt		1,237,587		0		110,166			0			1,347,753
Deferred income taxes		185,453		135,101		98,968			(5,883	)		413,639
Asset retirement obligations		0		170,410		0			0			170,410
Other long-term liabilities		1,421		3,691		665			0			5,777
Due to parent		0		0		120,884			(120,884	)		0
Total liabilities		1,547,169		509,861		420,239			(171,893	)		2,305,376
Convertible preferred stock		1,000		0		0			0			1,000
Total equity		1,341,458		1,723,239		436,298			(2,215,351	)		1,285,644
	$	2,889,627	$	2,233,100	$	856,537		$	(2,387,244	)	$	3,592,020

Schedule of Condensed Consolidating Statements Of Operations

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(in thousands)

(Unaudited)

	Three Months Ended June 30, 2011
		Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated
Net revenues	$	20,545		$	247,855		$	92,926		$	(23,007	)	$	338,319
Cost of sales		15,123			173,897			71,730			(22,629	)		238,121
Gross profit (loss)		5,422			73,958			21,196			(378	)		100,198
Gain on oil & gas derivative contracts		0			0			0			0			0
Gain (loss) on sale or acquisition of assets		(22	)		0			0			0			(22	)
Selling, general and administrative expenses...		(9,574	)		(9,915	)		(4,658	)		389			(23,758	)
Income (loss) from operations		(4,174	)		64,043			16,538			11			76,418
Equity in earnings of investments		58,929			4,194			5,887			(63,123	)		5,887
Net interest expense and other		(18,243	)		(5,890	)		108			0			(24,025	)
Income (loss) before income taxes		36,512			62,347			22,533			(63,112	)		58,280
Provision (benefit) for income taxes		(4,790	)		20,319			637			5			16,171
Net income (loss), including noncontrolling interests		41,302			42,028			21,896			(63,117	)		42,109
Less net income applicable to noncontrolling interests		0			0			0			(786	)		(786	)
Preferred stock dividends		(10	)		0			0			0			(10	)
Net income (loss) applicable to Helix common shareholders	$	41,292		$	42,028		$	21,896		$	(63,903	)	$	41,313

	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		0			2,482			0			0			2,482
Gain (loss) on sale or acquisition of assets		0			0			(14	)		0			(14	)
Selling, general 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		(15,319	)		(5,002	)		(1,878	)		0			(22,199	)
Income (loss) before income taxes		(82,994	)		(137,652	)		23,974			59,233			(137,439	)
Provision (benefit) for income taxes		(1,872	)		(49,351	)		1,221			(2,364	)		(52,366	)
Net income (loss), including noncontrolling interests		(81,122	)		(88,301	)		22,753			61,597			(85,073	)
Less net income applicable to noncontrolling interests		0			0			0			(444	)		(444	)
Preferred stock dividends		(34	)		0			0			0			(34	)
Net income (loss) applicable to Helix common shareholders	$	(81,156	)	$	(88,301	)	$	22,753		$	61,153		$	(85,551	)

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(in thousands)

(Unaudited)

	Six Months Ended June 30, 2011
		Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated
Net revenues	$	36,127		$	489,897		$	150,802		$	(46,900	)	$	629,926
Cost of sales		31,716			339,128			128,008			(46,200	)		452,652
Gross profit (loss)		4,411			150,769			22,794			(700	)		177,274
Gain on oil & gas derivative contracts		0			0			0			0			0
Gain (loss) on sale or acquisition of assets		(6	)		0			0			0			(6	)
Selling, general and administrative expenses...		(20,760	)		(19,951	)		(8,812	)		784			(48,739	)
Income (loss) from operations		(16,355	)		130,818			13,982			84			128,529
Equity in earnings of investments		107,036			(1,468	)		11,537			(105,568	)		11,537
Net interest expense and other		(35,527	)		(10,599	)		525			0			(45,601	)
Income (loss) before income taxes		55,154			118,751			26,044			(105,484	)		94,465
Provision (benefit) for income taxes		(11,963	)		42,060			(4,404	)		28			25,721
Net income (loss), including noncontrolling interests		67,117			76,691			30,448			(105,512	)		68,744
Less net income applicable to noncontrolling interests		0			0			0			(1,554	)		(1,554	)
Preferred stock dividends		(20	)		0			0			0			(20	)
Net income (loss) applicable to Helix common shareholders	$	67,097		$	76,691		$	30,448		$	(107,066	)	$	67,170

	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		0			2,482			0			0			2,482
Gain (loss) on sale or acquisition of assets		0			287			5,946			0			6,233
Selling, general 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		(22,708	)		(12,568	)		(8,143	)		0			(43,419	)
Income (loss) before income taxes		(101,702	)		(125,838	)		16,694			48,844			(162,002	)
Provision (benefit) for income taxes		(6,668	)		(45,136	)		(3,650	)		(4,473	)		(59,927	)
Net income (loss), including noncontrolling interests		(95,034	)		(80,702	)		20,344			53,317			(102,075	)
Less net income applicable to noncontrolling interests		0			0			0			(1,273	)		(1,273	)
Preferred stock dividends		(94	)		0			0			0			(94	)
Net income (loss) applicable to Helix common shareholders	$	(95,128	)	$	(80,702	)	$	20,344		$	52,044		$	(103,442	)

Schedule of Condensed Consolidating Statements of Cash Flows

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

	Six Months Ended June 30, 2011
			Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated
Cash flow from operating activities:
Net income (loss), including noncontrolling interests		$	67,117		$	76,691		$	30,448		$	(105,512	)	$	68,744
Adjustments to reconcile net income (loss), including noncontrolling interests to net cash provided by (used in) operating activities:
Equity in earnings of affiliates			(107,036	)		1,468			0			105,568			0
Other adjustments			21,261			180,193			(14,149	)		(5,476	)		181,829
Net cash provided by (used in) operating
activities			(18,658	)		258,352			16,299			(5,420	)		250,573
Cash flows from investing activities:
Capital expenditures			(15,699	)		(76,331	)		(14,092	)		0			(106,122	)
Investments in equity investments			0			0			(2,699	)		0			(2,699	)
Distributions from equity investments, net			0			0			1,593			0			1,593
Proceeds from sale of Cal Dive common stock			3,588			0			0			0			3,588
Decrease (increase) in restricted cash			0			863			0			0			863
Net cash used in investing activities			(12,111	)		(75,468	)		(15,198	)		0			(102,777	)
Cash flows from financing activities:
Repayments of debt			(111,191	)		0			(3,507	)		0			(114,698	)
Deferred financing costs			(9,014	)		0			0			0			(9,014	)
Preferred stock dividends paid			(20	)		0			0			0			(20	)
Repurchase of common stock			(1,012	)		0			0			0			(1,012	)
Excess tax benefit from stock-based  compensation			(1,196	)		0			0			0			(1,196	)
Exercise of stock options, net			1,672			0			0			0			1,672
Intercompany financing			162,868			(183,765	)		15,477			5,420			0
Net cash provided by (used in) financing activities			42,107			(183,765	)		11,970			5,420			(124,268	)
Effect of exchange rate changes on cash and cash equivalents			0			0			(424	)		0			(424	)
Net increase (decrease) in cash and cash equivalents			11,338			(881	)		12,647			0			23,104
Cash and cash equivalents:
Balance, beginning of year			376,434			3,294			11,357			0			391,085
Balance, end of period		$	387,772		$	2,413		$	24,004		$	0		$	414,189

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(in thousands)

	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	)		0			(61,631	)		0
Other adjustments			17,776			243,919			(13,101	)		(10,119	)		238,475
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	)		0			(135,612	)
Investments in equity investments			0			0			(6,307	)		0			(6,307	)
Distributions from equity investments, net			0			0			8,132			0			8,132
Insurance recovery			7,020			9,086			0			0			16,106
Decrease (increase) in restricted cash			0			109			0			0			109
Net cash used in investing activities			(40,943	)		(71,008	)		(5,621	)		0			(117,572	)
Cash flows from financing activities:
Repayments of debt			(2,163	)		0			(3,570	)		0			(5,733	)
Deferred financing costs			(2,792	)		0			0			0			(2,792	)
Preferred stock dividends paid			(94	)		0			0			0			(94	)
Repurchases of common stock			(9,127	)		0			0			0			(9,127	)
Excess tax benefit from stock-based  compensation			(2,163	)		0			0			0			(2,163	)
Exercise of stock options, net			163			0			0			0			163
Intercompany financing			62,654			(86,591	)		5,504			18,433			0
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			0			0			246			0			246
Net increase (decrease) in cash and cash equivalents			(6,987	)		2,513			3,802			0			(672	)
Cash and cash equivalents:
Balance, beginning of year			258,742			2,522			9,409			0			270,673
Balance, end of period		$	251,755		$	5,035		$	13,211		$	0		$	270,001

XML



Details of Certain Accounts (Other Current Assets) (Details) (USD $) In Thousands, except Share data	3 Months Ended			6 Months Ended
	Mar. 31, 2011	Dec. 31, 2010		Jun. 30, 2011		Jun. 30, 2010
Details of Certain Accounts
Other receivables		$ 1,247		$ 854
Prepaid insurance		12,375		12,141
Other prepaids		11,623		12,692
Spare parts inventory		25,333		21,850
Current deferred tax assets		49,200		37,533
Hedging assets		5,472		5,988
Gas imbalance		6,001		5,961
Income tax receivable		6,099		9,059
Investment held for sale		2,835	[1]	0	[1]
Other		2,880		4,256
Other current assets		123,065		110,334
Sale of subsidiary/equity method investee shares by parent company	500,000
Proceeds from sale of Cal Dive common stock				3,588		0
Gain on sale of Cal Dive common stock		(2,200)		753		0
Pre-tax gain on sale of Cal Dive common stock	$ 800			$ 753		$ 0

[1] In March 2011, we sold our remaining 500,000 shares of Cal Dive common stock. These sales transactions resulted in net proceeds of approximately $3.6 million and a pre-tax gain of $0.8 million. In the fourth quarter of 2010, we recognized a $2.2 million other than temporary loss on our investment in Cal Dive common shares (see Notes 2 and 3 of our 2010 Form 10-K for additional information regarding our former Investment in Cal Dive common stock).

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Details of Certain Accounts (Other Assets, Net) (Details) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Details of Certain Accounts
Restricted cash	$ 34,476	$ 35,339
Deferred drydock expenses, net	7,616	11,086
Deferred financing costs, net	30,127	25,697
Intangible assets with finite lives, net	602	636
Other	3,600	1,803
Other assets, net	$ 76,421	$ 74,561

XML



Details of Certain Accounts (Accrued Liabilities) (Details) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Details of Certain Accounts
Accrued payroll and related benefits	$ 33,148	$ 38,026
Royalties payable	17,115	15,008
Current asset retirement obligations	64,349	64,526
Unearned revenue	8,504	4,094
Billing in excess of cost	6,346	3,869
Accrued interest	27,347	27,308
Hedge liability	17,212	30,606
Other	16,205	14,800
Accrued liabilities	$ 190,226	$ 198,237

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Oil and Gas Properties (Narrative) (Details) (USD $)	1 Months Ended	3 Months Ended					6 Months Ended		12 Months Ended
	Feb. 28, 2010	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Jun. 30, 2010	Mar. 31, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2007	Dec. 31, 2010
Oil and gas property impairments				$ 22,721,000	$ 159,862,000	$ 7,000,000	$ 22,721,000	$ 170,974,000
Oil and gas properties				6				15
Asset retirement obligation				230,807,000			230,807,000			234,936,000
Capitalized exploration cost				3,600,000			3,600,000
Working interest in oil and gas field									100.00%
Cash acquired from acquisition	10,200,000
Acquired working interest	50.00%
Approximate gain on acquisition	6,000,000
Working interest before acquisition						50.00%
Hurricane-related repair costs					1,600,000		100,000	3,600,000
Insurance reimbursements							4,700,000
General Insurance Expense		2,000,000	8,400,000
Prepaid Insurance				12,141,000			12,141,000			12,375,000
Hurricane Catastrophic Bond [Member]
Prepaid Insurance				10,600,000			10,600,000
Non-Domestic Oil and Gas Property [Member]
Oil and gas property impairments						4,100,000	4,100,000
Asset retirement obligation				12,100,000			12,100,000
Accrued reclamation costs, current				$ 3,700,000			$ 3,700,000

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Oil and Gas Properties (Components of Exploration Expenses) (Details) (USD $) In Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2011		Jun. 30, 2010		Jun. 30, 2011		Jun. 30, 2010
Oil and Gas Properties
Delay rental and geological and geophysical costs	$ 1,299		$ 1,182		$ 1,654		$ 1,528
Impairment of unproved properties	6,640	[1]	0	[1]	6,640	[1]	0	[1]
Dry hole expense	0		(10)		(9)		(190)
Total exploration expense	$ 7,939		$ 1,172		$ 8,285		$ 1,338

[1] Reflects costs associated with a deepwater lease in which the term expired during the second quarter of 2011.

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Condensed Consolidated Statements of Operations (USD $) In Thousands, except Per Share data	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Net revenues:
Contracting services	$ 165,861	$ 196,676	$ 288,609	$ 307,531
Oil and gas	172,458	102,586	341,317	193,301
Total net revenues	338,319	299,262	629,926	500,832
Cost of sales:
Contracting services	116,521	140,126	223,428	226,374
Oil and gas	98,879	94,092	206,503	172,446
Oil and gas property impairments	22,721	159,862	22,721	170,974
Total cost of sales	238,121	394,080	452,652	569,794
Gross profit (loss)	100,198	(94,818)	177,274	(68,962)
Gain on oil and gas derivative contracts	0	2,482	0	2,482
Gain (loss) on sale or acquisition of assets, net	(22)	(14)	(6)	6,233
Selling and administrative expenses	(23,758)	(24,546)	(48,739)	(65,047)
Income (loss) from operations	76,418	(116,896)	128,529	(125,294)
Equity in earnings of investments	5,887	1,656	11,537	6,711
Gain on sale of Cal Dive common stock			753	0
Net interest expense	(25,278)	(20,523)	(49,514)	(36,158)
Other income (expense)	1,253	(1,676)	3,160	(7,261)
Income (loss) before income taxes	58,280	(137,439)	94,465	(162,002)
Provision (benefit) for income taxes	16,171	(52,366)	25,721	(59,927)
Net income (loss), including noncontrolling interests	42,109	(85,073)	68,744	(102,075)
Less net income applicable to noncontrolling interests	(786)	(444)	(1,554)	(1,273)
Net income (loss) applicable to Helix	41,323	(85,517)	67,190	(103,348)
Preferred stock dividends	(10)	(34)	(20)	(94)
Net income (loss) applicable to Helix common shareholders	$ 41,313	$ (85,551)	$ 67,170	$ (103,442)
Earnings (loss) per share of common stock:
Basic	$ 0.39	$ (0.82)	$ 0.63	$ (1.00)
Diluted	$ 0.39	$ (0.82)	$ 0.63	$ (1.00)
Weighted average common shares outstanding:
Basic	104,673	104,125	104,573	103,610
Diluted	105,140	104,125	105,024	103,610

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Oil and Gas Properties (Changes in Asset Retirement Obligations) (Details) (USD $) In Thousands	6 Months Ended
	Jun. 30, 2011
Oil and Gas Properties
Asset retirement obligation at December 31, 2010	$ 234,936
Liability incurred during the period	672
Liability settled during the period	(25,273)
Revision in estimated cash flows	12,842
Accretion expense (included in depreciation and amortization)	7,630
Asset retirement obligations at June 30, 2011	$ 230,807

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Statement of Cash Flow Information (Narrative) (Details) (USD $)	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010
Statement of Cash Flow Information
Restricted Cash and Cash Equivalents, Noncurrent	$ 34,476,000		$ 35,339,000
Accruals for capital expenditures	$ 33,700,000	$ 32,000,000

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Statement of Cash Flow Information (Supplemental Cash Flow Information) (Details) (USD $) In Thousands	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
Statement of Cash Flow Information
Interest paid, net of capitalized interest	$ 40,220	$ 27,847
Income taxes paid	$ 7,236	$ 6,642

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Equity Investments (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010
Equity investments in unconsolidated affiliates	$ 188,772,000		$ 188,772,000		$ 187,031,000
Payments of distributions to affiliates			1,593,000	8,132,000
Equity in earnings of investments	5,887,000	1,656,000	11,537,000	6,711,000
Deepwater Gateway, L.L.C. [Member]
Equity method investment, ownership percentage	50.00%		50.00%
Equity investments in unconsolidated affiliates	98,300,000		98,300,000		99,800,000
Capitalized interest	1,400,000		1,400,000		1,500,000
Payments of distributions to affiliates	1,800,000		3,600,000
Independence Hub, LLC [Member]
Equity method investment, ownership percentage	20.00%		20.00%
Equity investments in unconsolidated affiliates	81,000,000		81,000,000		82,400,000
Capitalized interest	5,100,000		5,100,000		5,200,000
Payments of distributions to affiliates	5,200,000		9,600,000
Clough Helix JV [Member]
Equity method investment, ownership percentage	50.00%		50.00%
Equity investments in unconsolidated affiliates	9,500,000		9,500,000		4,900,000
Equity in earnings of investments	$ 700,000	$ (4,300,000)	$ 1,100,000	$ (5,700,000)

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Long-Term Debt (Narrative) (Details) (USD $)	1 Months Ended	6 Months Ended						6 Months Ended									1 Months Ended		1 Months Ended	6 Months Ended
	Jan. 31, 2010	Jun. 30, 2011	Jun. 30, 2010	May 31, 2011	Mar. 31, 2011	Dec. 31, 2010	Mar. 31, 2010	Jun. 30, 2011 Maximum [Member] Helix Term Loan [Member]	Jun. 30, 2011 Maximum [Member] Helix Revolving Loans [Member]	Jun. 30, 2011 Minimum [Member] Helix Term Loan [Member]	Jun. 30, 2011 Minimum [Member] Helix Revolving Loans [Member]	Jun. 30, 2011 Helix Term Loan [Member]	Jun. 30, 2010 Helix Term Loan [Member]	Jul. 31, 2006 Helix Term Loan [Member]	Jun. 30, 2011 Helix Revolving Loans [Member]	Jul. 31, 2006 Helix Revolving Loans [Member]	Dec. 31, 2007 Senior Unsecured Notes [Member]	Jun. 30, 2011 Senior Unsecured Notes [Member]	Mar. 31, 2005 Convertible Senior Notes [Member]	Jun. 30, 2011 Convertible Senior Notes [Member]		Jun. 30, 2011 MARAD Debt [Member]		Jun. 30, 2011 Letters of Credit [Member]	Jun. 30, 2011 Helix [Member]	Dec. 31, 2010 Helix [Member]
Unsecured letters of credit		$ 48,800,000																						$ 48,800,000
Long-term debt, noncurrent		1,239,893,000				1,347,753,000						296,250,000			0		550,000,000	550,000,000		285,886,000	[1]	107,757,000			1,132,136,000	1,237,587,000
Long-term debt, Carrying Value		1,261,766,000																550,000,000	300,000,000	300,000,000	[2]	112,516,000	[3]
Long Term Debt														835,000,000
Debt instrument interest rate																	9.50%					4.93%
Stated maturity Year																	2016			March 2025		February 2027
Original borrowing capacity		600,000,000		435,000,000												300,000,000
Cash and cash equivalents plus available capacity under revolving credit facility																		500,000,000		400,000,000
Margin range								3.50%	3.50%	3.25%	2.50%
Base rate range								2.50%	2.50%	2.25%	1.50%
Average interest rate												3.20%	2.90%
Revolving credit facility available		551,200,000
Borrowing under revolving credit facility		109,400,000	0
Investments in Subsidiaries Permitted by Credit Agreement, Excluding Loan Party Subsidiaries and Subsidiaries With Pledged Equity Interests		200,000,000		150,000,000
Repurchases and Redemptions Permitted Under Credit Agreement, Common Stock, Value															50,000,000
Interest rate swap	200,000,000	200,000,000
Interest rate swap maximum term in years	two
Debt instrument issued percentage																			100.00%
Effective interest rate																				6.60%
Per share conversion price					$ 32.14		$ 32.14
Convertible senior notes are convertible into shares																				13,303,770
Debt instrument, frequency of periodic payment																						semi-annual
Debt collateral percentage		50.00%
Deferred Finance Costs, Net		30,127,000				25,697,000
Amortization of deferred financing costs		4,777,000	3,768,000									800,000
Repayment of revolving credit facility		$ (109,400,000)	$ 0									$ 109,400,000

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

[2] Amount excludes the $14.1 million of unamortized discount recorded on the Convertible Senior Notes at June 30, 2011.

[3] The estimated fair value of all debt, other than MARAD Debt, 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.

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Long-Term Debt (Maturities of Long-Term Debt) (Details) (USD $) In Thousands	Jun. 30, 2011		Dec. 31, 2010	Jun. 30, 2011 Helix [Member]	Dec. 31, 2010 Helix [Member]	Jun. 30, 2011 Helix Term Loan [Member]		Jun. 30, 2011 Helix Revolving Loans [Member]		Jun. 30, 2011 Senior Unsecured Notes [Member]		Dec. 31, 2007 Senior Unsecured Notes [Member]	Jun. 30, 2011 Convertible Senior Notes [Member]		Jun. 30, 2011 MARAD Debt [Member]
Less than one year	$ 7,759					$ 3,000		$ 0		$ 0			$ 0	[1]	$ 4,759
One to two years	7,997					3,000		0		0			0	[1]	4,997
Two to three years	8,247					3,000		0		0			0	[1]	5,247
Three to four years	8,508					3,000		0		0			0	[1]	5,508
Four to five years	843,033					287,250		0		550,000			0	[1]	5,783
Over five years	386,222					0		0		0			300,000	[1]	86,222
Total debt	1,261,766					299,250		0		550,000			300,000	[1]	112,516
Current maturities	(7,759)		(10,179)	(3,000)	(4,326)	(3,000)		0		0			0	[1]	(4,759)
Long-term debt, less current maturities	1,254,007					296,250		0		550,000			300,000	[1]	107,757
Unamortized debt discount	(14,114)	[2]				0	[2]	0	[2]	0	[2]		(14,114)	[1],[2]	0	[2]
Long-term debt	$ 1,239,893		$ 1,347,753	$ 1,132,136	$ 1,237,587	$ 296,250		$ 0		$ 550,000		$ 550,000	$ 285,886	[1]	$ 107,757

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

[2] The notes will increase to the $300 million face amount through accretion of non-cash interest charges through 2012.

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Long-Term Debt (Interest Expense and Capitalized Interest) (Details) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Long-Term Debt
Interest expense	$ 26,029	$ 24,597	$ 50,796	$ 48,946
Interest income	(499)	(199)	(975)	(397)
Capitalized interest	(252)	(3,875)	(307)	(12,391)
Interest expense, net	$ 25,278	$ 20,523	$ 49,514	$ 36,158

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Income Taxes (Details)	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Income Taxes
Effective tax rate	27.70%	38.10%	27.20%	37.00%

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Comprehensive Income (Loss) (Components of Total Comprehensive Income (Loss)) (Details) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Comprehensive Income (Loss)
Net income (loss), including noncontrolling interests	$ 42,109	$ (85,073)	$ 68,744	$ (102,075)
Foreign currency translation gain (loss)	(1,416)	(3,106)	699	(13,808)
Unrealized gain on hedges, net	20,970	2,063	10,403	16,103
Unrealized loss on investment available for sale	0	(481)	0	(556)
Total other comprehensive income (loss)	$ 61,663	$ (86,597)	$ 79,846	$ (100,336)

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Comprehensive Income (Loss) (Components of Accumulated Other Comprehensive Loss) (Details) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Comprehensive Income (Loss)
Cumulative foreign currency translation adjustment	$ (21,563)	$ (22,262)
Unrealized loss on hedges, net	(6,393)	(16,796)
Accumulated other comprehensive loss	$ (27,956)	$ (39,058)

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Condensed Consolidated Statements of Cash Flows (USD $) In Thousands	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
Cash flows from operating activities:
Net income (loss), including noncontrolling interests	$ 68,744	$ (102,075)
Adjustments to reconcile net income (loss), including noncontrolling interests to net cash provided by operating activities
Depreciation and amortization	167,170	146,268
Asset impairment charge and dry hole expense	29,352	170,784
Amortization of deferred financing costs	4,777	3,768
Stock compensation expense	4,938	4,589
Amortization of debt discount	4,414	4,136
Deferred income taxes	23,864	(54,749)
Excess tax benefit from stock-based compensation	1,196	2,163
Gain on investment in Cal Dive common stock	(753)	0
(Gain) loss on sale or acquisition of assets	6	(6,233)
Unrealized (gain) loss on derivative contracts	(34)	2,813
Changes in operating assets and liabilities:
Accounts receivable, net	(18,207)	(30,591)
Other current assets	12,712	16,477
Income tax payable	(4,154)	(10,811)
Accounts payable and accrued liabilities	(27,070)	28,027
Oil and gas asset retirement costs	(16,073)	(28,727)
Other noncurrent, net	(309)	(9,439)
Net cash provided by operating activities	250,573	136,400
Cash flows from investing activities:
Capital expenditures	(106,122)	(135,612)
Investments in equity investments	(2,699)	(6,307)
Distributions from equity investments, net	1,593	8,132
Proceeds from sale of Cal Dive common stock	3,588	0
Insurance recovery for capital items	0	16,106
Decrease in restricted cash	863	109
Net cash used in investing activities	(102,777)	(117,572)
Cash flows from financing activities:
Borrowing under revolving credit facility	109,400	0
Repayment of revolving credit facility	(109,400)	0
Repayment of Helix Term Loan	(111,191)	(2,163)
Repayment of MARAD borrowings	(2,294)	(2,403)
Loan notes repayment	(1,213)	(1,167)
Deferred financing costs	(9,014)	(2,792)
Preferred stock dividends paid	(20)	(94)
Repurchases of common stock	(1,012)	(9,127)
Excess tax benefit from stock-based compensation	(1,196)	(2,163)
Exercise of stock options, net	1,672	163
Net cash used in financing activities	(124,268)	(19,746)
Effect of exchange rate changes on cash and cash equivalents	(424)	246
Net increase (decrease) in cash and cash equivalents	23,104	(672)
Cash and cash equivalents:
Balance, beginning of year	391,085	270,673
Balance, end of period	$ 414,189	$ 270,001

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Earnings Per Share (Computations of Basic and Diluted EPS) (Details) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Net income (loss) applicable to common shareholders	$ 41,313	$ (85,551)	$ 67,170	$ (103,442)
Less: Undistributed net income allocable to participating securities	(514)	0	(850)
Net Income Loss Available To Common Stockholders Basic Net Of Distributions To Securities	40,799	(85,551)	66,320	(103,442)
Weighted average number of shares outstanding - basic	104,673	104,125	104,573	103,610
Stock options, Income	0	0	0	0
Stock options, Shares	106	0	90	0
Undistributed earnings reallocated to participating securities, value	3	0	4	0
Undistributed earnings reallocated to participating securities, shares	0	0	0	0
Convertible Senior Notes, Value	0	0	0	0
Convertible Senior Notes, Shares	0	0	0	0
Convertible preferred stock	10	0	20	0
Convertible preferred stock, Shares	361	0	361	0
Net income (loss) per common share - Diluted	40,812	(85,551)	66,344	(103,442)
Weighted Average Number of Shares Outstanding, Diluted, Total	105,140	104,125	105,024	103,610
Helix [Member]
Net income (loss) applicable to common shareholders	$ 41,292	$ (81,156)	$ 67,097	$ (95,128)

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Earnings Per Share (Excluded Securities on Diluted Shares Calculation) (Details)	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Diluted	105,140,000	104,125,000	105,024,000	103,610,000
Total		105,414,000		105,379,000
Dilutive securities				0
Stock Options [Member]
Anti-dilutive securities		94,000		80,000
Convertible Preferred Stock [Member]
Anti-dilutive securities		1,195,000		1,689,000

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Stock-Based Compensation Plans (Narrative) (Details) (USD $) In Millions, except Share data	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010
Stock-Based Compensation Plans
Shares available for grant	967,435		967,435
Compensation cost related to restricted shares	$ 2.0	$ 2.1	$ 4.9	$ 4.6
Compensation expense	1.6	0.9	4.6	2.6
Liability long term incentive compensation plan	6.6		6.6		7.9
Liability long term incentive compensation plan variable portion	$ 5.7		$ 5.7		$ 6.2

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Stock-Based Compensation Plans (Restricted Shares Granted) (Details) (USD $)	6 Months Ended
	Jun. 30, 2011
Grant Share Amount A [Member]
Restricted share grants, Date of Grant	January 4, 2011
Restricted share grants, Shares	475,804
Restricted share grants Market Value Per Share	$ 12.14
Restricted share grants vesting percentage	20.00%
Restricted share grants Vesting Period, in years	five
Grant Share Amount B [Member]
Restricted share grants, Date of Grant	January 4, 2011
Restricted share grants, Shares	4,427
Restricted share grants Market Value Per Share	$ 12.14
Restricted share grants vesting percentage	100.00%
Restricted stock, vesting date	January 1, 2013
Grant Share Amount C [Member]
Restricted share grants, Date of Grant	April 1, 2011
Restricted share grants, Shares	2,907
Restricted share grants Market Value Per Share	$ 17.20
Restricted share grants vesting percentage	100.00%
Restricted stock, vesting date	January 1, 2013
Grant Share Amount D [Member]
Restricted share grants, Date of Grant	May 11, 2011
Restricted share grants, Shares	21,608
Restricted share grants Market Value Per Share	$ 16.14
Restricted share grants vesting percentage	20.00%
Restricted share grants Vesting Period, in years	five

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Business Segment Information (Schedule of Segment Reporting Information by Segment) (Details) (USD $)	3 Months Ended					6 Months Ended
	Jun. 30, 2011		Jun. 30, 2010		Mar. 31, 2010	Jun. 30, 2011		Jun. 30, 2010
Revenues	$ 338,319,000		$ 299,262,000			$ 629,926,000		$ 500,832,000
Oil and gas	172,458,000		102,586,000			341,317,000		193,301,000
Income (loss) from operations	76,418,000		(116,896,000)			128,529,000		(125,294,000)
Settlement of a third party claim					13,800,000
Settlement of claims					17,500,000
Contracting Services [Member]
Revenues	171,353,000		202,317,000			302,890,000		356,517,000
Income (loss) from operations	30,565,000		43,781,000			33,831,000		71,267,000
Production Facilities [Member]
Revenues	20,545,000		21,391,000			36,115,000		22,711,000
Income (loss) from operations	11,920,000	[1]	12,977,000	[1]		17,876,000	[1]	12,940,000	[1]
Oil and Gas [Member]
Oil and gas	172,458,000		102,586,000			341,317,000		193,301,000
Income (loss) from operations	43,064,000		(154,943,000)			96,304,000		(155,607,000)
Corporate [Member]
Income (loss) from operations	(9,112,000)	[2]	(12,597,000)	[2]		(19,553,000)	[2]	(35,475,000)	[2]
Intercompany Elimination [Member]
Revenues	(26,037,000)		(27,032,000)			(50,396,000)		(71,697,000)
Income (loss) from operations	$ (19,000)		$ (6,114,000)			$ 71,000		$ (18,419,000)

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

[2] The six-month period ended June 30, 2010, included $13.8 million of $17.5 million settlement of a third party claim against us in March 2010 (Note 14).

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Business Segment Information (Summary of Intercompany Segment Revenues) (Details) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Intercompany segment revenues	$ 26,037	$ 27,032	$ 50,396	$ 71,697
Contracting Services [Member]
Intercompany segment revenues	14,295	24,426	27,164	68,167
Production Facilities [Member]
Intercompany segment revenues	$ 11,742	$ 2,606	$ 23,232	$ 3,530

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Business Segment Information (Intercompany Segment Gross Profit (Losses)) (Details) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Gross profit (loss) with other operating segments of same entity	$ 19	$ 6,114	$ (71)	$ 18,436
Contracting Services [Member]
Gross profit (loss) with other operating segments of same entity	63	3,701	39	15,143
Production Facilities [Member]
Gross profit (loss) with other operating segments of same entity	$ (44)	$ 2,413	$ (110)	$ 3,293

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Business Segment Information (Summary of Identifiable Assets) (Details) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Total assets	$ 3,560,637	$ 3,592,020
Contracting Services [Member]
Total assets	1,869,593	1,856,016
Production Facilities [Member]
Total assets	518,220	512,990
Oil and Gas [Member]
Total assets	$ 1,172,824	$ 1,223,014

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Related Party Transactions (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended	3 Months Ended		6 Months Ended
	Apr. 30, 2000	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Related Party Transactions
Percentage of working interests acquired	20.00%
Financing exploratory costs	$ 20
Royalty interest	25.00%
Related party payments		$ 2.7	$ 3.0	$ 5.1	$ 6.1
Partnership interests				80.70%

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Commitments and Contingencies (Details)	0 Months Ended	1 Months Ended		3 Months Ended			6 Months Ended			3 Months Ended		6 Months Ended			3 Months Ended	12 Months Ended
	Mar. 31, 2009 AUD	Apr. 30, 2010 AUD	Mar. 31, 2009 USD ($)	Jun. 30, 2011 USD ($)	Jun. 30, 2010 USD ($)	Mar. 31, 2010 USD ($)	Jun. 30, 2011 USD ($)	Jun. 30, 2010 USD ($)	Dec. 31, 2010 USD ($)	Jun. 30, 2011 Helix [Member] USD ($)	Jun. 30, 2010 Helix [Member] USD ($)	Jun. 30, 2011 Helix [Member] USD ($)	Jun. 30, 2010 Helix [Member] USD ($)	Dec. 31, 2010 Helix [Member] USD ($)	Mar. 31, 2011 Australian Subsidiary [Member] USD ($)	Dec. 31, 2010 Australian Subsidiary [Member] USD ($)	Jun. 30, 2011 Australian Subsidiary [Member] USD ($)
Approximate actual damages	32,000,000		$ 12,000,000
Damage claims paid		15,000,000
Settlement of claims						17,500,000
Payments for litigation settlements						13,800,000
Remaining trade receivable write off						3,700,000
Approximate pre-tax loss				58,280,000	(137,439,000)		94,465,000	(162,002,000)		36,512,000	(82,994,000)	55,154,000	(101,702,000)		200,000	30,000,000
Accounts receivable, net				212,406,000			212,406,000		177,293,000	54,325,000		54,325,000		61,846,000			6,700,000
Trade receivables collected							303,000,000
Value added tax assessment							$ 28,000,000

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Basis of Presentation

6 Months Ended

Jun. 30, 2011

Basis of Presentation

Basis of Presentation

Note 1 – Basis of Presentation

The accompanying condensed consolidated financial statements include the accounts of Helix Energy Solutions Group, Inc. and its majority-owned subsidiaries (collectively, "Helix" or the "Company"). Unless the context indicates otherwise, the terms "we," "us" and "our" in this report refer collectively to Helix and its majority-owned subsidiaries.   All material intercompany accounts and transactions have been eliminated. These unaudited condensed consolidated financial statements have been prepared pursuant to instructions for the Quarterly Report on Form 10-Q required to be filed with the Securities and Exchange Commission ("SEC"), and do not include all information and footnotes normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles.

            The accompanying condensed consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles and are consistent in all material respects with those applied in our 2010 Annual Report on Form 10-K ("2010 Form 10-K").  The preparation of these financial statements requires us to make estimates and judgments that affect the amounts reported in the financial statements and the related disclosures.  Actual results may differ from our estimates.  Management has reflected all adjustments (which were normal recurring adjustments unless otherwise disclosed herein) that it believes are necessary for a fair presentation of the condensed consolidated balance sheets, results of operations, and cash flows, as applicable. The operating results for the periods ended June 30, 2011 are not necessarily indicative of the results that may be expected for the year ending December 31, 2011. Our balance sheet as of December 31, 2010 included herein has been derived from the audited balance sheet as of December 31, 2010 included in our 2010 Form 10-K. These unaudited condensed consolidated financial statements should be read in conjunction with the annual audited consolidated financial statements and notes thereto included in our 2010 Form 10-K.

            Certain reclassifications were made to previously reported amounts in the condensed consolidated financial statements and notes thereto to make them consistent with the current presentation format, including reclassifying the previously recorded results associated with our discontinued operations.  The discontinued operations results are now reflected as a component of other income (expense) in the accompanying condensed consolidated statement of operations as such amounts are immaterial for all the periods presented in this Quarterly Report on Form 10-Q.  

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Fair Value Measurements (Narrative) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended			6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Mar. 31, 2010	Jun. 30, 2011	Jun. 30, 2010
Oil and gas property impairments	$ 22,721	$ 159,862	$ 7,000	$ 22,721	$ 170,974
Aggregate fair value of properties	2,900	62,500	28,200	2,900	62,500
US Impairments [Member]
Oil and gas property impairments					159,900
UK Impairments [Member]
Oil and gas property impairments			$ 7,000
Natural Gas Properties [Member]
Number of properties impaired			3		15

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Fair Value Measurements (Assets and Liabilities Measured at Fair Value on a Recurring Basis) (Details) (USD $) In Thousands	Jun. 30, 2011		Jun. 30, 2010	Mar. 31, 2010
Assets	$ 2,900		$ 62,500	$ 28,200
Total net liability	1,314,591	[1]
Long-term debt, Fair Value	1,304,590
Long-term debt, Carrying Value	1,261,766
Interest Rate Swap [Member]
Liabilities	1,157	[1]
Interest Rate Swap [Member] | Level 1[Member]
Liabilities	0	[1]
Interest Rate Swap [Member] | Level 2 [Member]
Liabilities	1,157	[1],[2]
Interest Rate Swap [Member] | Level 3 [Member]
Liabilities	0	[1]
Oil and Gas Swaps and Collars [Member]
Assets	7,531	[1]
Liabilities	16,680	[1]
Oil and Gas Swaps and Collars [Member] | Level 1[Member]
Assets	0	[1]
Liabilities	0	[1]
Oil and Gas Swaps and Collars [Member] | Level 2 [Member]
Assets	7,531	[1],[2]
Liabilities	16,680	[1],[2]
Oil and Gas Swaps and Collars [Member] | Level 3 [Member]
Assets	0	[1]
Liabilities	0	[1]
Foreign Currency Forwards [Member]
Assets	305
Foreign Currency Forwards [Member] | Level 1[Member]
Assets	0
Foreign Currency Forwards [Member] | Level 2 [Member]
Assets	305	[2]
Foreign Currency Forwards [Member] | Level 3 [Member]
Assets	0
Fair Value of Long Term Debt [Member]
Liabilities	1,304,590	[3]
Fair Value of Long Term Debt [Member] | Level 1[Member]
Liabilities	1,182,173	[3]
Fair Value of Long Term Debt [Member] | Level 2 [Member]
Liabilities	122,417	[2],[3]
Fair Value of Long Term Debt [Member] | Level 3 [Member]
Liabilities	0	[3]
Level 1[Member]
Total net liability	1,182,173	[1]
Level 2 [Member]
Total net liability	132,418	[1],[2]
Level 3 [Member]
Total net liability	$ 0	[1]

[1] 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).

[2] 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.

[3] We have elected not to record our debt at fair value in the accompanying condensed consolidated balance sheets. See Note 7 for additional information regarding our long term debt. The fair value of our long term debt at June 30, 2011 is as follows:

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Fair Value Measurements (Fair Value of Long Term Debt) (Details) (USD $) In Thousands	6 Months Ended
	Jun. 30, 2011		Mar. 31, 2005
Long-term debt, Fair Value	$ 1,304,590
Long-term debt, Carrying Value	1,261,766
Debt Instrument, Unamortized Discount	14,114	[1]
Revolving Credit Facility [Member]
Long-term debt, Fair Value	0
Long-term debt, Carrying Value	0
Long term debt, Maturity Date	July 2015
Term Loan [Member]
Long-term debt, Fair Value	299,998
Long-term debt, Carrying Value	299,250
Long term debt, Maturity Date	July 2015
Convertible Senior Notes [Member]
Long-term debt, Fair Value	299,175
Long-term debt, Carrying Value	300,000	[2]	300,000
Long term debt, Maturity Date	March 2025
Debt Instrument, Unamortized Discount	14,114	[1],[3]
Senior Unsecured Notes [Member]
Long-term debt, Fair Value	583,000
Long-term debt, Carrying Value	550,000
Long term debt, Maturity Date	January 2016
Debt Instrument, Unamortized Discount	0	[1]
MARAD Debt [Member]
Long-term debt, Fair Value	122,417	[4]
Long-term debt, Carrying Value	112,516	[4]
Long term debt, Maturity Date	February 2027
Debt Instrument, Unamortized Discount	$ 0	[1]

[1] The notes will increase to the $300 million face amount through accretion of non-cash interest charges through 2012.

[2] Amount excludes the $14.1 million of unamortized discount recorded on the Convertible Senior Notes at June 30, 2011.

[3] Beginning in December 2012, the holders may require us to repurchase the notes or we may at our own option elect to repurchase the notes. The notes will mature in March 2025.

[4] The estimated fair value of all debt, other than MARAD Debt, 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.

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Derivative Instruments and Hedging Activities (Narrative) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	6 Months Ended
	Jun. 30, 2011 bbl	Jun. 30, 2011	Jan. 31, 2010
Derivative Instruments and Hedging Activities
Contracts no longer qualified for hedge accounting oil volume	480,000
Total volume of oil units	3,500,000	3,500,000
Total volume of natural gas units	9,400,000,000	9,400,000,000
Term loans payable	$ 200	$ 200	$ 200
Contract maturity period		January 2012

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Derivative Instruments and Hedging Activities (Volumes Under Derivative Contracts Related to Oil and Gas Producing Activities) (Details)	6 Months Ended
	Jun. 30, 2011
Maximum [Member] | Current Remaining Year [Member] | Crude Oil [Member] | Collar [Member]
Weighted Average Price	124.70
Minimum [Member] | Current Remaining Year [Member] | Crude Oil [Member] | Collar [Member]
Weighted Average Price	95.00
Current Remaining Year [Member] | Crude Oil [Member] | Swap [Member]
Average Monthly Volumes	175,800
Weighted Average Price	82.49
Current Remaining Year [Member] | Crude Oil [Member] | Collar [Member]
Average Monthly Volumes	53,300
Current Remaining Year [Member] | Natural Gas [Member] | Swap [Member]
Weighted Average Price	4.97
Current Remaining Year [Member] | Swap [Member]
Average Monthly Volumes	725,800,000
Maximum [Member] | Current Year [Member] | Crude Oil [Member] | Henry Hub [Member] | Collar [Member]
Weighted Average Price	122.80
Minimum [Member] | Current Year [Member] | Crude Oil [Member] | Henry Hub [Member] | Collar [Member]
Weighted Average Price	100.00
Current Year [Member] | Crude Oil [Member] | Collar [Member]
Average Monthly Volumes	12,500
Maximum [Member] | Next Year [Member] | Crude Oil [Member] | Henry Hub [Member] | Collar 2 [Member]
Weighted Average Price	120.25
Maximum [Member] | Next Year [Member] | Crude Oil [Member] | Collar [Member]
Weighted Average Price	118.57
Minimum [Member] | Next Year [Member] | Crude Oil [Member] | Henry Hub [Member] | Collar 2 [Member]
Weighted Average Price	100.00
Minimum [Member] | Next Year [Member] | Crude Oil [Member] | Collar [Member]
Weighted Average Price	96.67
Next Year [Member] | Crude Oil [Member] | Collar [Member]
Average Monthly Volumes	75,000
Next Year [Member] | Crude Oil [Member] | Collar 2 [Member]
Average Monthly Volumes	91,700
Next Year [Member] | Natural Gas [Member] | Swap [Member]
Weighted Average Price	4.77
Next Year [Member] | Swap [Member]
Average Monthly Volumes	250,000,000
Next Year [Member] | Collar [Member]
Average Monthly Volumes	166,700,000
Maximum [Member] | Natural Gas [Member] | Collar [Member]
Weighted Average Price	5.09
Minimum [Member] | Natural Gas [Member] | Collar [Member]
Weighted Average Price	4.75

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Derivative Instruments and Hedging Activities (Derivatives Designated as Hedging Instruments) (Details) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Asset derivatives designated as hedging instruments	$ 7,531	$ 5,324
Liability derivatives designated as hedging instruments	17,837	31,634
Other Current Assets [Member] | Oil Contract [Member]
Asset derivatives designated as hedging instruments	3,381	0
Other Current Assets [Member] | Natural Gas Contracts [Member]
Asset derivatives designated as hedging instruments	2,302	5,324
Other Assets, Net [Member] | Oil Contract [Member]
Asset derivatives designated as hedging instruments	1,816	0
Other Assets, Net [Member] | Natural Gas Contracts [Member]
Asset derivatives designated as hedging instruments	32	0
Other Assets, Net [Member] | Interest Rate Swap [Member]
Asset derivatives designated as hedging instruments	0	0
Other Liabilities [Member] | Oil Contract [Member]
Liability derivatives designated as hedging instruments	399	0
Other Liabilities [Member] | Natural Gas Contracts [Member]
Liability derivatives designated as hedging instruments	226	913
Other Liabilities [Member] | Interest Rate Swap [Member]
Liability derivatives designated as hedging instruments	0	115
Accrued Liabilities [Member] | Oil Contract [Member]
Liability derivatives designated as hedging instruments	16,055	28,855
Accrued Liabilities [Member] | Interest Rate Swap [Member]
Liability derivatives designated as hedging instruments	$ 1,157	$ 1,751

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Derivative Instruments and Hedging Activities (Derivatives Not Designated as Hedging Instruments) (Details) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Asset derivatives not designated as hedging instruments	$ 305	$ 190
Liability derivatives not designated as hedging instruments	0	0
Other Current Assets [Member] | Foreign Exchange Forward [Member]
Asset derivatives not designated as hedging instruments	305	148
Other Assets, Net [Member] | Foreign Exchange Forward [Member]
Asset derivatives not designated as hedging instruments	$ 0	$ 42

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Derivative Instruments and Hedging Activities (Impact of Derivative Instruments on Accumulated Comprehensive Income (Loss)) (Details) (USD $) In Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2011		Jun. 30, 2010		Jun. 30, 2011		Jun. 30, 2010
Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	$ 20,970	[1]	$ 2,063	[1]	$ 10,403	[1]	$ 16,103	[1]
Oil and Natural Gas Commodity Contract [Member]
Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	20,720	[1]	2,575	[1]	9,942	[1]	17,205	[1]
Interest Rate Swap [Member]
Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	$ 250	[1]	$ (512)	[1]	$ 461	[1]	$ (1,102)	[1]

[1] All unrealized gains (losses) related to our derivatives are expected to be reclassified into earnings by no later than December 31, 2012. The last of our interest swaps will mature in January 2012 and we have foreign exchange forwards and oil and natural gas commodity contracts that have maturities through June and December 2012, respectively.

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Derivative Instruments and Hedging Activities (Gain (Loss) Reclassified from Accumulated OCI into Income) (Details) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	$ (12,451)	$ 9,194	$ (19,256)	$ 9,577
Oil and Natural Gas Commodity Contract [Member] | Oil and Gas Revenue [Member]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(11,860)	9,663	(18,185)	10,464
Interest Rate Swap [Member] | Net Interest Expense and Other [Member]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	$ (591)	$ (469)	$ (1,071)	$ (887)

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Derivative Instruments and Hedging Activities (Impact of Non Designated Derivative Instruments on Income Statement) (Details) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Gain (Loss) Recognized in Income on Derivatives	$ 6	$ 2,084	$ 614	$ (823)
Natural Gas Contracts [Member] | Gain On Oil and Gas Derivative Contracts [Member]
Gain (Loss) Recognized in Income on Derivatives	0	2,482	0	2,482
Foreign Exchange Forward [Member] | Other Expense [Member]
Gain (Loss) Recognized in Income on Derivatives	$ 6	$ (398)	$ 614	$ (3,305)

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Company Overview

6 Months Ended

Jun. 30, 2011

Company Overview

Company Overview

Note 2 – Company Overview

We are an international offshore energy company that provides reservoir development solutions and other contracting services to the energy market as well as to our own oil and gas properties. Our Contracting Services segment utilizes our vessels, offshore equipment and methodologies to deliver services that may reduce finding and development costs and encompass the complete lifecycle of an offshore oil and gas field. Our Contracting Services are located primarily in 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 exclusively located in the Gulf of Mexico.

Contracting Services Operations

We seek to provide services and methodologies which we believe are critical to finding and developing offshore reservoirs and maximizing production economics.  Our "life of field" services are segregated into four disciplines: subsea construction, well operations, robotics and production facilities. We have disaggregated our contracting services operations into two reportable segments: Contracting Services and Production Facilities. Our Contracting Services business primarily includes subsea construction, deepwater pipelay, well operations and robotics activities.  Our Production Facilities business includes our investments in Deepwater Gateway, L.L.C. ("Deepwater Gateway") and Independence Hub, LLC ("Independence Hub") as well as our majority ownership of the Helix Producer I ("HP I") vessel.   We have developed a response system that has been referenced as a designated spill response solution in Gulf of Mexico permit applications (see "Events in Gulf of Mexico" below).

Oil and Gas Operations

We began our oil and gas operations to provide a more efficient solution to offshore abandonment, to expand our off-season utilization of our contracting services assets and to achieve incremental returns. We have evolved this business model to include not only mature oil and gas properties but also proved and unproved reserves yet to be developed and explored. This has led to the assembly of services that allows us to create value at key points in the life of a reservoir from exploration through development, life of field management and operating through abandonment.

Events in Gulf of Mexico

In April 2010, an explosion occurred on the Deepwater Horizon drilling rig located on the site of the Macondo well at Mississippi Canyon Block 252.  The resulting events included loss of life, the complete destruction of the drilling rig and an oil spill, the magnitude of which was unprecedented in U.S. territorial waters.  In May 2010, the U.S. Department of Interior ("DOI") announced a total moratorium on new drilling in the Gulf of Mexico.   In October 2010, the DOI lifted the drilling moratorium and instructed the Bureau of Ocean Energy Management, Regulation and Enforcement ("BOEMRE") that it could resume issuing drilling permits conditioned on the requesting company's compliance with all revised drilling, safety and environmental requirements.   No deepwater drilling permits were issued in the period from October 2010 through late February 2011.  In late February 2011, the BOEMRE commenced issuing deepwater permits.    At the time of this filing 24 deepwater permits have been issued, 14 of which were issued referencing the Helix Fast Response System as further discussed below.

We developed the Helix Fast Response System ("HFRS") as a culmination of our experience as a responder in the Macondo oil spill response and containment efforts.  The HFRS centers on two vessels, the HP I and the Q4000, both of which played a key role in the Macondo oil spill response and containment efforts and are presently operating in the Gulf of Mexico.  In 2011, we signed an agreement with Clean Gulf Associates ("CGA"), a non-profit industry group, allowing, in exchange for a retainer fee, the HFRS to be named as a response resource in permit applications to federal and state agencies and making the HFRS available for a two-year term to certain CGA participants who have executed utilization agreements with us. In addition to the agreement with CGA, we currently have signed separate utilization agreements with 24 CGA participant member companies specifying the day rates to be charged should the HFRS solution be deployed in connection with a well control incident.  The retainer fee for the HFRS became effective April 1, 2011 and is a component of our Production Facilities business segment.   A total of 14 permits have been granted to CGA participants for deepwater drilling operations identifying the HFRS to fulfill the BOERME requirement to have a spill response solution included in the submitted permit applications.

New Accounting Pronouncement

In June 2011, the Financial Accounting Standards Board ("FASB") issued an update to existing guidance on the presentation of comprehensive income. This update will require the presentation of the components of net income and other comprehensive income either in a single continuous statement or in two separate but consecutive statements. In addition, companies are also required to present reclassification adjustments for items that are reclassified from other comprehensive income to net income on the face of the financial statements. The update is effective for fiscal years and interim periods beginning after December 15, 2011. We will adopt the new disclosure requirements for comprehensive income beginning January 1, 2012 and are currently evaluating the provisions of this update.

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Condensed Consolidated Guarantor and Non-Guarantor Financial Information (Schedule of Condensed Consolidating Balance Sheets) (Details) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010	Jun. 30, 2010	Dec. 31, 2009
Cash and cash equivalents	$ 414,189	$ 391,085	$ 270,001	$ 270,673
Accounts receivable, net	212,406	177,293
Unbilled revenue	20,303	49,411
Income taxes receivable	9,059	6,099
Other current assets	101,275	116,966
Total current assets	757,232	740,854
Intercompany	0	0
Property and equipment, net	2,475,310	2,527,080
Equity investments in unconsolidated affiliates	188,772	187,031
Equity investments in affiliates	0	0
Goodwill, net	62,902	62,494
Other assets, net	76,421	74,561
Due from subsidiaries/parent	0	0
Total assets	3,560,637	3,592,020
Accounts payable	148,142	159,381
Accrued liabilities	190,226	198,237
Income taxes payable	0	0
Current maturities of long-term debt	7,759	10,179
Total current liabilities	346,127	367,797
Long-term debt, noncurrent	1,239,893	1,347,753
Deferred income taxes	431,821	413,639
Asset retirement obligations	166,458	170,410
Other long-term liabilities	5,432	5,777
Due to parent	0	0
Total liabilities	2,189,731	2,305,376
Convertible preferred stock	1,000	1,000
Total equity	1,369,906	1,285,644
Total liabilities and shareholders' equity	3,560,637	3,592,020
Helix [Member]
Cash and cash equivalents	387,772	376,434	251,755	258,742
Accounts receivable, net	54,325	61,846
Unbilled revenue	2,219	11,990
Income taxes receivable	63,514	19,334
Other current assets	47,610	63,306
Total current assets	555,440	532,910
Intercompany	1,294	1,906
Property and equipment, net	221,300	217,153
Equity investments in unconsolidated affiliates	0	0
Equity investments in affiliates	1,947,501	1,998,289
Goodwill, net	0	0
Other assets, net	48,499	43,971
Due from subsidiaries/parent	90,965	95,398
Total assets	2,864,999	2,889,627
Accounts payable	41,121	60,308
Accrued liabilities	58,787	58,074
Income taxes payable	0	0
Current maturities of long-term debt	3,000	4,326
Total current liabilities	102,908	122,708
Long-term debt, noncurrent	1,132,136	1,237,587
Deferred income taxes	213,232	185,453
Asset retirement obligations	0	0
Other long-term liabilities	1,335	1,421
Due to parent	0	0
Total liabilities	1,449,611	1,547,169
Convertible preferred stock	1,000	1,000
Total equity	1,414,388	1,341,458
Total liabilities and shareholders' equity	2,864,999	2,889,627
Guarantors [Member]
Cash and cash equivalents	2,413	3,294	5,035	2,522
Accounts receivable, net	106,506	91,659
Unbilled revenue	0	0
Income taxes receivable	0	0
Other current assets	42,191	49,557
Total current assets	151,110	144,510
Intercompany	294,433	263,920
Property and equipment, net	1,554,186	1,605,906
Equity investments in unconsolidated affiliates	0	0
Equity investments in affiliates	28,432	29,899
Goodwill, net	45,107	45,107
Other assets, net	38,119	38,324
Due from subsidiaries/parent	275,900	105,434
Total assets	2,387,287	2,233,100
Accounts payable	82,403	56,107
Accrued liabilities	96,184	107,874
Income taxes payable	84,684	36,678
Current maturities of long-term debt	0	0
Total current liabilities	263,271	200,659
Long-term debt, noncurrent	0	0
Deferred income taxes	126,992	135,101
Asset retirement obligations	166,458	170,410
Other long-term liabilities	3,480	3,691
Due to parent	0	0
Total liabilities	560,201	509,861
Convertible preferred stock	0	0
Total equity	1,827,086	1,723,239
Total liabilities and shareholders' equity	2,387,287	2,233,100
Non-Guarantors [Member]
Cash and cash equivalents	24,004	11,357	13,211	9,409
Accounts receivable, net	51,575	23,788
Unbilled revenue	18,084	37,421
Income taxes receivable	13,075	7,195
Other current assets	12,712	12,889
Total current assets	119,450	92,650
Intercompany	(212,007)	(171,513)
Property and equipment, net	704,756	709,082
Equity investments in unconsolidated affiliates	188,772	187,031
Equity investments in affiliates	0	0
Goodwill, net	17,795	17,387
Other assets, net	19,639	21,900
Due from subsidiaries/parent	0	0
Total assets	838,405	856,537
Accounts payable	24,618	42,966
Accrued liabilities	35,255	32,289
Income taxes payable	0	0
Current maturities of long-term debt	4,759	14,301
Total current liabilities	64,632	89,556
Long-term debt, noncurrent	107,757	110,166
Deferred income taxes	97,650	98,968
Asset retirement obligations	0	0
Other long-term liabilities	617	665
Due to parent	116,451	120,884
Total liabilities	387,107	420,239
Convertible preferred stock	0	0
Total equity	451,298	436,298
Total liabilities and shareholders' equity	838,405	856,537
Consolidating Entries [Member]
Cash and cash equivalents	0	0	0	0
Accounts receivable, net	0	0
Unbilled revenue	0	0
Income taxes receivable	(67,530)	(20,430)
Other current assets	(1,238)	(8,786)
Total current assets	(68,768)	(29,216)
Intercompany	(83,720)	(94,313)
Property and equipment, net	(4,932)	(5,061)
Equity investments in unconsolidated affiliates	0	0
Equity investments in affiliates	(1,975,933)	(2,028,188)
Goodwill, net	0	0
Other assets, net	(29,836)	(29,634)
Due from subsidiaries/parent	(366,865)	(200,832)
Total assets	(2,530,054)	(2,387,244)
Accounts payable	0	0
Accrued liabilities	0	0
Income taxes payable	(84,684)	(36,678)
Current maturities of long-term debt	0	(8,448)
Total current liabilities	(84,684)	(45,126)
Long-term debt, noncurrent	0	0
Deferred income taxes	(6,053)	(5,883)
Asset retirement obligations	0	0
Other long-term liabilities	0	0
Due to parent	(116,451)	(120,884)
Total liabilities	(207,188)	(171,893)
Convertible preferred stock	0	0
Total equity	(2,322,866)	(2,215,351)
Total liabilities and shareholders' equity	$ (2,530,054)	$ (2,387,244)

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Condensed Consolidated Guarantor and Non-Guarantor Financial Information (Schedule of Condensed Consolidating Statements of Operations) (Details) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Net revenues	$ 338,319	$ 299,262	$ 629,926	$ 500,832
Cost of sales	238,121	394,080	452,652	569,794
Gross profit (loss)	100,198	(94,818)	177,274	(68,962)
Gain on oil & gas derivative contracts	0	2,482	0	2,482
Gain (loss) on sale or acquisition of assets	(22)	(14)	(6)	6,233
Selling and administrative expenses	(23,758)	(24,546)	(48,739)	(65,047)
Income (loss) from operations	76,418	(116,896)	128,529	(125,294)
Equity in earnings of investments	5,887	1,656	11,537	6,711
Net interest expense and other	(24,025)	(22,199)	(45,601)	(43,419)
Income (loss) before income taxes	58,280	(137,439)	94,465	(162,002)
Provision (benefit) for income taxes	16,171	(52,366)	25,721	(59,927)
Net income (loss), including noncontrolling interests	42,109	(85,073)	68,744	(102,075)
Less net income applicable to noncontrolling interests	(786)	(444)	(1,554)	(1,273)
Preferred stock dividends	(10)	(34)	(20)	(94)
Net income (loss) applicable to Helix common shareholders	41,313	(85,551)	67,170	(103,442)
Helix [Member]
Net revenues	20,545	33,670	36,127	54,692
Cost of sales	15,123	18,158	31,716	31,492
Gross profit (loss)	5,422	15,512	4,411	23,200
Gain on oil & gas derivative contracts	0	0	0	0
Gain (loss) on sale or acquisition of assets	(22)	0	(6)	0
Selling and administrative expenses	(9,574)	(13,583)	(20,760)	(37,458)
Income (loss) from operations	(4,174)	1,929	(16,355)	(14,258)
Equity in earnings of investments	58,929	(69,604)	107,036	(64,736)
Net interest expense and other	(18,243)	(15,319)	(35,527)	(22,708)
Income (loss) before income taxes	36,512	(82,994)	55,154	(101,702)
Provision (benefit) for income taxes	(4,790)	(1,872)	(11,963)	(6,668)
Net income (loss), including noncontrolling interests	41,302	(81,122)	67,117	(95,034)
Less net income applicable to noncontrolling interests	0	0	0	0
Preferred stock dividends	(10)	(34)	(20)	(94)
Net income (loss) applicable to Helix common shareholders	41,292	(81,156)	67,097	(95,128)
Guarantors [Member]
Net revenues	247,855	186,247	489,897	355,970
Cost of sales	173,897	317,157	339,128	457,199
Gross profit (loss)	73,958	(130,910)	150,769	(101,229)
Gain on oil & gas derivative contracts	0	2,482	0	2,482
Gain (loss) on sale or acquisition of assets	0	0	0	287
Selling and administrative expenses	(9,915)	(7,834)	(19,951)	(17,915)
Income (loss) from operations	64,043	(136,262)	130,818	(116,375)
Equity in earnings of investments	4,194	3,612	(1,468)	3,105
Net interest expense and other	(5,890)	(5,002)	(10,599)	(12,568)
Income (loss) before income taxes	62,347	(137,652)	118,751	(125,838)
Provision (benefit) for income taxes	20,319	(49,351)	42,060	(45,136)
Net income (loss), including noncontrolling interests	42,028	(88,301)	76,691	(80,702)
Less net income applicable to noncontrolling interests	0	0	0	0
Preferred stock dividends	0	0	0	0
Net income (loss) applicable to Helix common shareholders	42,028	(88,301)	76,691	(80,702)
Non-Guarantors [Member]
Net revenues	92,926	100,086	150,802	145,058
Cost of sales	71,730	72,345	128,008	122,302
Gross profit (loss)	21,196	27,741	22,794	22,756
Gain on oil & gas derivative contracts	0	0	0	0
Gain (loss) on sale or acquisition of assets	0	(14)	0	5,946
Selling and administrative expenses	(4,658)	(3,531)	(8,812)	(10,576)
Income (loss) from operations	16,538	24,196	13,982	18,126
Equity in earnings of investments	5,887	1,656	11,537	6,711
Net interest expense and other	108	(1,878)	525	(8,143)
Income (loss) before income taxes	22,533	23,974	26,044	16,694
Provision (benefit) for income taxes	637	1,221	(4,404)	(3,650)
Net income (loss), including noncontrolling interests	21,896	22,753	30,448	20,344
Less net income applicable to noncontrolling interests	0	0	0	0
Preferred stock dividends	0	0	0	0
Net income (loss) applicable to Helix common shareholders	21,896	22,753	30,448	20,344
Consolidating Entries [Member]
Net revenues	(23,007)	(20,741)	(46,900)	(54,888)
Cost of sales	(22,629)	(13,580)	(46,200)	(41,199)
Gross profit (loss)	(378)	(7,161)	(700)	(13,689)
Gain on oil & gas derivative contracts	0	0	0	0
Gain (loss) on sale or acquisition of assets	0	0	0	0
Selling and administrative expenses	389	402	784	902
Income (loss) from operations	11	(6,759)	84	(12,787)
Equity in earnings of investments	(63,123)	65,992	(105,568)	61,631
Net interest expense and other	0	0	0	0
Income (loss) before income taxes	(63,112)	59,233	(105,484)	48,844
Provision (benefit) for income taxes	5	(2,364)	28	(4,473)
Net income (loss), including noncontrolling interests	(63,117)	61,597	(105,512)	53,317
Less net income applicable to noncontrolling interests	(786)	(444)	(1,554)	(1,273)
Preferred stock dividends	0	0	0	0
Net income (loss) applicable to Helix common shareholders	$ (63,903)	$ 61,153	$ (107,066)	$ 52,044

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Condensed Consolidated Guarantor and Non-Guarantor Financial Information (Schedule of Condensed Consolidating Statements of Cash Flows) (Details) (USD $) In Thousands	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
Net income (loss), including noncontrolling interests	$ 68,744	$ (102,075)
Equity in earnings of affiliates	0	0
Other adjustments	181,829	238,475
Net cash provided by operating activities	250,573	136,400
Capital expenditures	(106,122)	(135,612)
Investments In Equity Investments	(2,699)	(6,307)
Distributions from equity investments, net	1,593	8,132
Proceeds from sale of Cal Dive common stock	3,588	0
Insurance recovery	0	16,106
Decrease (increase) in restricted cash	863	109
Net cash used in investing activities	(102,777)	(117,572)
Repayments of debt	(114,698)	(5,733)
Deferred financing costs	(9,014)	(2,792)
Preferred stock dividends paid	(20)	(94)
Repurchases of common stock	(1,012)	(9,127)
Excess tax benefit from stock-based compensation	(1,196)	(2,163)
Exercise of stock options, net	1,672	163
Intercompany financing	0	0
Net cash used in financing activities	(124,268)	(19,746)
Effect of exchange rate changes on cash and cash equivalents	(424)	246
Net increase (decrease) in cash and cash equivalents	23,104	(672)
Balance, beginning of year	391,085	270,673
Balance, end of period	414,189	270,001
Helix [Member]
Net income (loss), including noncontrolling interests	67,117	(95,034)
Equity in earnings of affiliates	(107,036)	64,736
Other adjustments	21,261	17,776
Net cash provided by operating activities	(18,658)	(12,522)
Capital expenditures	(15,699)	(47,963)
Investments In Equity Investments	0	0
Distributions from equity investments, net	0	0
Proceeds from sale of Cal Dive common stock	3,588
Insurance recovery		7,020
Decrease (increase) in restricted cash	0	0
Net cash used in investing activities	(12,111)	(40,943)
Repayments of debt	(111,191)	(2,163)
Deferred financing costs	(9,014)	(2,792)
Preferred stock dividends paid	(20)	(94)
Repurchases of common stock	(1,012)	(9,127)
Excess tax benefit from stock-based compensation	(1,196)	(2,163)
Exercise of stock options, net	1,672	163
Intercompany financing	162,868	62,654
Net cash used in financing activities	42,107	46,478
Effect of exchange rate changes on cash and cash equivalents	0	0
Net increase (decrease) in cash and cash equivalents	11,338	(6,987)
Balance, beginning of year	376,434	258,742
Balance, end of period	387,772	251,755
Guarantors [Member]
Net income (loss), including noncontrolling interests	76,691	(80,702)
Equity in earnings of affiliates	1,468	(3,105)
Other adjustments	180,193	243,919
Net cash provided by operating activities	258,352	160,112
Capital expenditures	(76,331)	(80,203)
Investments In Equity Investments	0	0
Distributions from equity investments, net	0	0
Proceeds from sale of Cal Dive common stock	0
Insurance recovery		9,086
Decrease (increase) in restricted cash	863	109
Net cash used in investing activities	(75,468)	(71,008)
Repayments of debt	0	0
Deferred financing costs	0	0
Preferred stock dividends paid	0	0
Repurchases of common stock	0	0
Excess tax benefit from stock-based compensation	0	0
Exercise of stock options, net	0	0
Intercompany financing	(183,765)	(86,591)
Net cash used in financing activities	(183,765)	(86,591)
Effect of exchange rate changes on cash and cash equivalents	0	0
Net increase (decrease) in cash and cash equivalents	(881)	2,513
Balance, beginning of year	3,294	2,522
Balance, end of period	2,413	5,035
Non-Guarantors [Member]
Net income (loss), including noncontrolling interests	30,448	20,344
Equity in earnings of affiliates	0	0
Other adjustments	(14,149)	(13,101)
Net cash provided by operating activities	16,299	7,243
Capital expenditures	(14,092)	(7,446)
Investments In Equity Investments	(2,699)	(6,307)
Distributions from equity investments, net	1,593	8,132
Proceeds from sale of Cal Dive common stock	0
Insurance recovery		0
Decrease (increase) in restricted cash	0	0
Net cash used in investing activities	(15,198)	(5,621)
Repayments of debt	(3,507)	(3,570)
Deferred financing costs	0	0
Preferred stock dividends paid	0	0
Repurchases of common stock	0	0
Excess tax benefit from stock-based compensation	0	0
Exercise of stock options, net	0	0
Intercompany financing	15,477	5,504
Net cash used in financing activities	11,970	1,934
Effect of exchange rate changes on cash and cash equivalents	(424)	246
Net increase (decrease) in cash and cash equivalents	12,647	3,802
Balance, beginning of year	11,357	9,409
Balance, end of period	24,004	13,211
Consolidating Entries [Member]
Net income (loss), including noncontrolling interests	(105,512)	53,317
Equity in earnings of affiliates	105,568	(61,631)
Other adjustments	(5,476)	(10,119)
Net cash provided by operating activities	(5,420)	(18,433)
Capital expenditures	0	0
Investments In Equity Investments	0	0
Distributions from equity investments, net	0	0
Proceeds from sale of Cal Dive common stock	0
Insurance recovery		0
Decrease (increase) in restricted cash	0	0
Net cash used in investing activities	0	0
Repayments of debt	0	0
Deferred financing costs	0	0
Preferred stock dividends paid	0	0
Repurchases of common stock	0	0
Excess tax benefit from stock-based compensation	0	0
Exercise of stock options, net	0	0
Intercompany financing	5,420	18,433
Net cash used in financing activities	5,420	18,433
Effect of exchange rate changes on cash and cash equivalents	0	0
Net increase (decrease) in cash and cash equivalents	0	0
Balance, beginning of year	0	0
Balance, end of period	$ 0	$ 0

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Details of Certain Accounts

6 Months Ended

Jun. 30, 2011

Details of Certain Accounts

Details of Certain Accounts

Note 3 – Details of Certain Accounts

            Other current assets consisted of the following as of June 30, 2011 and December 31, 2010:

		June 30,		December 31,
		2011		2010
		(in thousands)
Other receivables	$	854	$	1,247
Prepaid insurance		12,141		12,375
Other prepaids		12,692		11,623
Spare parts inventory		21,850		25,333
Current deferred tax assets		37,533		49,200
Hedging assets		5,988		5,472
Gas imbalance		5,961		6,001
Income tax receivable		9,059		6,099
Investment held for sale (a)		0		2,835
Other		4,256		2,880
	$	110,334	$	123,065

a.In March 2011, we sold our remaining 500,000 shares of Cal Dive common stock.  These sales transactions resulted in net proceeds of approximately $3.6 million and a pre-tax gain of $0.8 million.   In the fourth quarter of 2010, we recognized a $2.2 million other than temporary loss on our investment in Cal Dive common shares (see Notes 2 and 3 of our 2010 Form 10-K for additional information regarding our former Investment in Cal Dive common stock). 

            Other assets, net, consisted of the following as of June 30, 2011 and December 31, 2010:

		June 30,		December 31,
		2011		2010
		(in thousands)
Restricted cash	$	34,476	$	35,339
Deferred drydock expenses, net		7,616		11,086
Deferred financing costs, net		30,127		25,697
Intangible assets with finite lives, net		602		636
Other		3,600		1,803
	$	76,421	$	74,561

            Accrued liabilities consisted of the following as of June 30, 2011 and December 31, 2010:

		June 30,		December 31,
		2011		2010
		(in thousands)
Accrued payroll and related benefits	$	33,148	$	38,026
Royalties payable		17,115		15,008
Current asset retirement obligations		64,349		64,526
Unearned revenue		8,504		4,094
Billing in excess of cost		6,346		3,869
Accrued interest		27,347		27,308
Hedge liability		17,212		30,606
Other		16,205		14,800
	$	190,226	$	198,237

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Oil and Gas Properties

6 Months Ended

Jun. 30, 2011

Oil and Gas Properties

Oil and Gas Properties

Note 4 – Oil and Gas Properties

We follow the successful efforts method of accounting for our interests in oil and gas properties. Under the successful efforts method, the costs of drilling and equipping 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.

Impairments

During the three-month period ended June 30, 2011, we recorded impairment charges totaling $22.7 million, including $4.1 million for  our only non-domestic oil and gas property (see "United Kingdom Property" below), and for  six of our Gulf of Mexico oil and gas properties.   These impairment charges primarily reflect a premature end of these fields' production life either through actual depletion or as a result of capital allocation decisions affecting our third party operated fields.  We did not have any impairment of our oil and gas properties in the first quarter of 2011. 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 U.K oil and gas property.  

Exploration and Other

           As of June 30, 2011, we capitalized approximately $3.6 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, 2011 and 2010 (in thousands):

		Three Months Ended					Six Months Ended
		June 30,					June 30,
		2011		2010			2011			2010
Delay rental and geological and geophysical costs...	$	1,299	$	1,182		$	1,654		$	1,528
Impairment of unproved properties (a)		6,640		0			6,640			0
Dry hole expense		0		(10	)		(9	)		(190	)
Total exploration expense	$	7,939	$	1,172		$	8,285		$	1,338

a. Reflects costs associated with a deepwater lease in which the term expired during the second quarter of 2011.

United Kingdom Property

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

Also in connection with this acquisition, we reassessed the fair value associated with our original 50% interest in the field. Based on these evaluations, we concluded that the Camelot field was impaired based on the unlikely probability of our expending the additional capital necessary to further develop the field.  As a result, we recorded a $4.1 million impairment charge to fully impair the property in the first quarter of 2010.  We are currently abandoning the field in accordance with applicable United Kingdom regulations. In connection with these activities, during the second quarter of 2011 we revised our estimated future field abandonment costs for the field, which resulted in our recording an incremental $4.1 million impairment charge to increase our asset retirement obligation to $12.1 million at June 30, 2011. We have incurred approximately $3.7 million of costs related to our reclamation activities at the Camelot field through June 30, 2011.    

Asset retirement obligations

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

Asset retirement obligation at December 31, 2010	$	234,936
Liability incurred during the period		672
Liability settled during the period		(25,273	)
Revision in estimated cash flows		12,842
Accretion expense (included in depreciation and amortization)		7,630
Asset retirement obligations at June 30, 2011	$	230,807

Insurance

In September 2008, we sustained damage to certain of our oil and gas production facilities from Hurricanes Gustav and Ike.  We carried comprehensive insurance on all of our operated and non-operated producing and non-producing properties.  We record our hurricane-related costs as incurred. Insurance reimbursements are recorded when the realization of the claim for recovery of a loss is deemed probable.  We incurred $0.1 million of hurricane-related costs in the first half of 2011, which were totally offset by $4.7 million of insurance reimbursements.  Our hurricane-related costs, net of reimbursements totaled $1.6 million and $3.6 million for the three-month and six-month periods ended June 30, 2010.  Expense related to our hurricane catastrophic bond windstorm coverage was immaterial for all periods presented in this Quarterly Report on Form 10-Q.  On June 30, 2011, we renewed our hurricane catastrophic bond for the period July 1, 2011 to June 30, 2012 and made a payment of $10.6 million.   We will charge approximately $8.4 million of this payment to insurance expense in the third quarter of 2011 and $2.0 million in the fourth quarter of 2011 based upon the bond's contractual intrinsic value at the end of each of those quarterly periods.