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 March 31, 2012
	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 April 20, 2012, 105,641,054 shares of common stock were outstanding.

TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION	PAGE
Item 1.	Financial Statements:
	Condensed Consolidated Balance Sheets –   March 31, 2012 (Unaudited) and December 31, 2011	3
	Condensed Consolidated Statements of Operations and Comprehensive Income (Unaudited) –   Three months ended March 31, 2012 and 2011	4
	Condensed Consolidated Statements of Cash Flows (Unaudited) –   Three months ended March 31, 2012 and 2011	5
	Notes to Condensed Consolidated Financial Statements (Unaudited)	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	41
Item 4.	Controls and Procedures	41
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	42
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	42
Item 6.	Exhibits	42
	Signatures	43
	Index to Exhibits	44

2

PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements.

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

 (in thousands)

	March 31,		December 31,
	2012		2011
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	620,449	$	546,465
Accounts receivable-
Trade, net of allowance for uncollectible accounts of $4,067		237,417		238,781
Unbilled revenue		15,458		24,338
Costs in excess of billing		9,118		13,037
Other current assets		109,669		121,621
Total current assets		992,111		944,242
Property and equipment		4,403,092		4,391,064
Less - accumulated depreciation		(2,041,405)		(2,059,737)
Property and equipment, net		2,361,687		2,331,327
Other assets:
Equity investments		173,440		175,656
Goodwill		62,667		62,215
Other assets, net		75,038		68,907
Total assets	$	3,664,943	$	3,582,347
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	145,631	$	147,043
Accrued liabilities		196,814		239,963
Income tax payable		24,977		1,293
Current maturities of long-term debt		12,997		7,877
Total current liabilities		380,419		396,176
Long-term debt		1,167,486		1,147,444
Deferred income taxes		423,098		417,610
Asset retirement obligations		146,696		161,208
Other long-term liabilities		16,516		9,368
Total liabilities		2,134,215		2,131,806
Convertible preferred stock		1,000		1,000
Commitments and contingencies
Shareholders' equity:
Common stock, no par, 240,000 shares authorized, 105,636 and 105,530 shares issued, respectively		932,097		908,776
Retained Earnings		588,371		522,644
Accumulated other comprehensive loss		(19,667)		(10,017)
Total controlling interest shareholders' equity		1,500,801		1,421,403
Noncontrolling interest		28,927		28,138
Total equity		1,529,728		1,449,541
Total liabilities and shareholders' equity	$	3,664,943	$	3,582,347

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 OPERATIONS AND

COMPREHENSIVE INCOME

(UNAUDITED)

 (in thousands, except per share amounts)

	Three Months Ended
	March 31,
	2012			2011
Net revenues:
Contracting services	$	229,842		$	122,748
Oil and gas		178,085			168,859
Total net revenues		407,927			291,607
Cost of sales:
Contracting services		156,968			106,907
Oil and gas		89,249			107,624
Total cost of sales		246,217			214,531
Gross profit		161,710			77,076
Gain (loss) on sale of assets, net		(1,478	)		16
Loss on oil and gas derivative commodity contracts		(2,339	)		-
Selling, general and administrative expenses		(25,696	)		(24,981	)
Income from operations		132,197			52,111
Equity in earnings of investments		407			5,650
Net interest expense		(21,760	)		(24,236	)
Loss on early extinguishment of long term debt		(17,127	)		-
Other income (expense), net		86			2,660
Income before income taxes		93,803			36,185
Provision for income taxes		27,277			9,550
Net income, including noncontrolling interests		66,526			26,635
Less net income applicable to noncontrolling interests		(789	)		(768	)
Net income applicable to Helix		65,737			25,867
Preferred stock dividends		(10	)		(10	)
Net income applicable to Helix common shareholders	$	65,727		$	25,857
Earnings per share of common stock:
Basic	$	0.62		$	0.24
Diluted	$	0.62		$	0.24
Weighted average common shares outstanding:
Basic		104,530			104,471
Diluted		104,989			104,903
Comprehensive income (Note 9)	$	56,876		$	18,183

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

4

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

 (in thousands)

	Three Months Ended
	March 31,
	2012			2011
Cash flows from operating activities:
Net income, including noncontrolling interests	$	66,526		$	26,635
Adjustments to reconcile net income, including noncontrolling interests  to net cash provided by operating activities
Depreciation and amortization		72,492			92,143
Asset impairment charge and dry hole expense		143			-
Amortization of deferred financing costs		2,355			1,981
Stock compensation expense		1,838			2,953
Amortization of debt discount		1,611			2,207
Deferred income taxes		(2,673	)		9,329
Excess tax benefit from stock-based compensation		340			969
Gain on investment in Cal Dive common stock		-			(753	)
(Gain) loss on sale of assets, net		1,478			(16	)
Loss on early extinguishment of debt		17,127			-
Unrealized loss (gain) and ineffectiveness on derivative contracts, net		2,453			(318	)
Changes in operating assets and liabilities:
Accounts receivable, net		11,526			(381	)
Other current assets		15,360			18,869
Income tax payable		23,233			(2,338	)
Accounts payable and accrued liabilities		(59,079	)		(58,747	)
Oil and gas asset retirement costs		(18,357	)		(8,160	)
Other noncurrent, net		(2,568	)		692
Net cash provided by operating activities		133,805			85,065
Cash flows from investing activities:
Capital expenditures		(101,744	)		(34,488	)
Distributions from equity investments, net		5,943			480
Proceeds from sale of Cal Dive common stock		-			3,588
Decrease in restricted cash		922			613
Net cash used in investing activities		(94,879	)		(29,807	)
Cash flows from financing activities:
Early extinguishment of Senior Unsecured Notes		(209,500	)		-
Borrowings under revolving credit facility		100,000			-
Issuance of Convertible Senior Notes due 2032		200,000			-
Repurchase of Convertible Senior Notes due 2025		(143,945	)		-
Proceeds from Term Loan A		100,000			-
Repayment of Term Loan		(750	)		(1,082	)
Repayment of MARAD borrowings		(2,409	)		(2,294	)
Deferred financing costs		(6,337	)		-
Repurchases of common stock		(991	)		(927	)
Excess tax benefit from stock-based compensation		(340	)		(969	)
Exercise of stock options, net and other		381			(70	)
Net cash provided by (used in) financing activities		36,109			(5,342	)
Effect of exchange rate changes on cash and cash equivalents		(1,051	)		(470	)
Net increase in cash and cash equivalents		73,984			49,446
Cash and cash equivalents:
Balance, beginning of year		546,465			391,085
Balance, end of period	$	620,449		$	440,531

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

5

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 – Basis of Presentation and Recent Accounting Standards

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 2011 Annual Report on Form 10-K (“2011 Form 10-K”).  The preparation of these financial statements requires us to make estimates and judgments that affect the amounts reported in the financial statements and the related disclosures.  Actual results may differ from our estimates.  Management has reflected all adjustments (which were normal recurring adjustments unless otherwise disclosed herein) that it believes are necessary for a fair presentation of the condensed consolidated balance sheets, results of operations, and cash flows, as applicable. The operating results for the three-month period ended March 31, 2012 are not necessarily indicative of the results that may be expected for the year ending December 31, 2012. Our balance sheet as of December 31, 2011 included herein has been derived from the audited balance sheet as of December 31, 2011 included in our 2011 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 2011 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.

In June 2011, the Financial Accounting Standards Board (“FASB”) issued amendments to disclosure requirements for presentation of comprehensive income. This guidance, effective retrospectively for the interim and annual periods beginning on or after December 15, 2011, requires presentation of total comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements.  In December 2011, the FASB issued an amendment that deferred the presentation of reclassification adjustments for each component of accumulated other comprehensive income in both net income and other comprehensive income on the face of the financial statements.  The implementation of the amended accounting guidance did not have a material impact on our consolidated financial position or results of operations.

Note 2 – Company Overview

We are an international offshore energy company that provides 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 proprietary technologies to deliver services that may reduce finding and development costs and cover 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 prospect generation, exploration, development and production activities. Our oil and gas operations are located in the Gulf of Mexico.

6

Contracting Services Operations

We seek to provide services and methodologies which we believe are critical to developing offshore reservoirs and maximizing production economics.  Our “life of field” services are segregated into four disciplines: well operations, robotics, subsea construction 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 well operations, robotics and subsea construction activities.  Our Production Facilities business includes our equity 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.  It also includes the Helix Fast Response System (“HFRS”), which includes our Q4000 and HP I vessels.  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 be deployed in connection with a well control incident.  The retainer fee for the HFRS became effective April 1, 2011.

Oil and Gas Operations

We began our oil and gas operations to achieve incremental returns, to expand our off-season utilization of our contracting services assets, and to provide a more efficient solution to offshore abandonment. We have evolved this business model to include not only mature oil and gas properties but also unproved and proved reserves yet to be explored and developed. This has led to the assembly of services that allows us to create value throughout the complete cycle of a reservoir, including exploration through development and managing and operating a field’s production up to and through the field’s eventual abandonment.

Note 3 – Details of Certain Accounts

Other current assets consisted of the following as of March 31, 2012 and December 31, 2011:

	March 31,		December 31,
	2012		2011
	(in thousands)
Other receivables	$	4,771	$	5,096
Prepaid insurance		6,637		12,701
Other prepaids		10,200		13,271
Spare parts inventory		16,614		18,066
Current deferred tax assets		44,442		41,449
Hedging assets		17,785		21,579
Gas and oil imbalance		4,175		5,134
Other		5,045		4,325
Total other current assets	$	109,669	$	121,621

Other assets, net, consisted of the following as of March 31, 2012 and December 31, 2011:

	March 31,		December 31,
	2012		2011
	(in thousands)
Restricted cash	$	32,819	$	33,741
Deferred drydock expenses, net		9,445		5,381
Deferred financing costs, net		28,081		26,483
Intangible assets with finite lives, net		520		531
Other		4,173		2,771
Total other assets, net	$	75,038	$	68,907

7

Accrued liabilities consisted of the following as of March 31, 2012 and December 31, 2011:

	March 31,		December 31,
	2012		2011
	(in thousands)
Accrued payroll and related benefits	$	37,489	$	49,599
Royalties payable		16,011		19,391
Current asset retirement obligations		82,339		93,183
Unearned revenue		7,724		7,654
Billing in excess of cost		8,361		28,839
Accrued interest		9,619		24,028
Hedging liability		15,167		1,247
Gas and oil imbalance		3,601		4,177
Other		16,503		11,845
Total accrued liabilities	$	196,814	$	239,963

Note 4 – Oil and Gas Properties

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

Exploration and Other

As of March 31, 2012, we capitalized approximately $7.8 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-month periods ended March 31, 2012 and 2011:

		Three Months Ended
		March 31,
		2012			2011
		(in thousands)
Delay rental and geological and geophysical costs	$	611		$	355
Impairment of unproved properties		144			–
Dry hole expense		(1	)		(9	)
Total exploration expense	$	754		$	346

Impairments

No proved property impairments were recorded in the first quarter of 2012 or 2011.

Asset retirement obligations

The following table describes the changes in our asset retirement obligations (both long term and current) since December 31, 2011 (in thousands):

Asset retirement obligations at December 31, 2011	$	254,391
Liability incurred during the period		115
Liability settled during the period		(34,665	)
Other revisions in estimated cash flows		5,755
Accretion expense (included in depreciation and amortization)		3,439
Asset retirement obligations at March 31, 2012	$	229,035

8

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 $32.8 million at March 31, 2012 and $33.7 million at December 31, 2011,all of which consisted of funds required to be escrowed to cover the future asset retirement obligations associated with our South Marsh Island Block 130 field.  We have fully satisfied the escrow requirements under the escrow agreement and may use the restricted cash for the future asset retirement costs of the field.  These amounts are reflected in other assets, net in the accompanying condensed consolidated balance sheets.

The following table provides supplemental cash flow information for the three-month periods ended March 31, 2012 and 2011 (in thousands):

		Three Months Ended
		March 31,
		2012		2011
Interest paid, net of capitalized interest(1)	$	32,554	$	32,093
Income taxes paid	$	6,725	$	3,785

Non-cash investing activities for the three-month periods ended March 31, 2012 and 2011 included $21.0 million and $36.0 million, respectively, of accruals for capital expenditures.  The accruals have been reflected in the accompanying condensed consolidated balance sheets as an increase in property and equipment and accounts payable.

Note 6 – Equity Investments

As of March 31, 2012, we had two investments that we account for using the equity method of accounting: Deepwater Gateway and Independence Hub, both of which are included in our Production Facilities 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 $95.1 million and $96.0 million as of March 31, 2012 and December 31, 2011, respectively (including capitalized interest of $1.4 million at March 31, 2012 and December 31, 2011).  Our net distributions from Deepwater Gateway totaled $2.2 million in the first quarter of 2012.

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 $78.3 million and $79.7 million as of March 31, 2012 and December 31, 2011, respectively (including capitalized interest of $4.8 million and $4.9 million at March 31, 2012 and December 31, 2011, respectively).  Our net distributions from Independence Hub totaled $4.2 million in the first quarter of 2012.

As disclosed in our 2011 Form 10-K, we invested in an Australian joint venture that engages in well intervention operations in the Southeast Asia region.   At December 31, 2011, we fully impaired our investment in that joint venture (Note 7 of 2011 Form 10-K).   In the first quarter of 2012, we recorded additional losses totaling $3.8 million related to our continued participation in this joint venture, including a $3.0 million negotiated exit fee from the joint venture.  In April 2012, we paid this exit fee and we are no longer a participant in this Australian joint venture.

9

Note 7 – Long-Term Debt

Scheduled maturities of long-term debt outstanding as of March 31, 2012 were as follows (in thousands):

		Term Loan (1)			Revolving Credit Facility		Senior Unsecured Notes		2025   Notes (2)			MARAD Debt			2032  Notes (3)			Total
Less than one year	$	8,000		$	─	$	─	$	─		$	4,997		$	─		$	12,997
One to two years		8,000			─		─		─			5,247			─			13,247
Two to three years		8,000			─		─		─			5,508			─			13,508
Three to four years		355,000			100,000		274,960		─			5,783			─			735,743
Four to five years		─			─		─		─			6,072			─			6,072
Over five years		─			─		─		157,830			80,149			200,000			437,979
Total debt		379,000			100,000		274,960		157,830			107,756			200,000			1,219,546
Current maturities		(8,000	)		─		─		─			(4,997	)		─			(12,997	)
Long-term debt, less    current maturities	$	371,000		$	100,000	$	274,960	$	157,830		$	102,759		$	200,000		$	1,206,549
Unamortized debt discount (4)		─			─		─		(3,688	)		─			(35,375	)		(39,063	)
Long-term debt	$	371,000		$	100,000	$	274,960	$	154,142		$	102,759		$	164,625		$	1,167,486

(1)   Amounts reflect both our Term Loan and new Term Loan A.

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

(3)   Beginning in March 2018, the holders of these Convertible Senior Notes may require us to repurchase these notes or we may at our election elect to repurchase the notes. These notes will mature in March 2032.

(4)   The notes will increase to their principal amount through accretion of non-cash interest charges through December 2012 for the Convertible Senior Notes due 2025 and March 2018 for the Convertible Senior Notes due 2032.

At March 31, 2012, unsecured letters of credit issued totaled approximately $46.2 million (see “Credit Agreement” below).  These letters of credit primarily guarantee asset retirement obligations as well as various contract bidding, contractual performance, insurance activities and shipyard commitments.  The following table details our interest expense and capitalized interest for the three-month periods ended March 31, 2012 and 2011:

		Three Months Ended
		March 31,
		2012			2011
		(in thousands)
Interest expense	$	22,809		$	24,767
Interest income		(570	)		(476	)
Capitalized interest		(479	)		(55	)
Interest expense, net	$	21,760		$	24,236

Included below is a summary of certain components of our indebtedness. For additional information regarding our debt see Note 9 of our 2011 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.    At December 31, 2011, we had $475.0 million of Senior Unsecured Notes outstanding.   Prior to stated maturity, after January 15, 2012, we may redeem all or a portion of the Senior Unsecured Notes, on not less than 30 days’ nor more than 60 days’ prior notice at the redemption prices (expressed as percentages of the principal amount) set forth below, plus accrued and unpaid interest, in any, thereon to the applicable redemption date.

10

Year	Redemption Price
2012	104.750%
2013	102.375%
2014 and thereafter	100.000%

In March 2012, we purchased a portion of these Senior Unsecured Notes that resulted in an early extinguishment of $200.0 million of our balance outstanding. In these transactions we paid an aggregate amount of $213.5 million, including $200.0 million in principal,  $9.5 million in premium for the repurchased Senior Unsecured Notes and $4.0 million of accrued interest.  We also recorded a $2.0 million charge to accelerate a pro rata portion of the deferred financing costs associated with the original issuance of the Senior Unsecured Notes.  The loss on the early extinguishment of these related Senior Unsecured Notes totaled $11.5 million and is reflected as a component of “Loss on early extinguishment of long term debt” in the accompanying condensed consolidated statements of operations and comprehensive income.

Credit Agreement

In July 2006, we entered into a credit agreement (the “Credit Agreement”) under which we borrowed $835 million in a term loan (the “Term Loan”) and were able to borrow up to $300 million (the “Revolving Loans”) under a revolving credit facility (the “Revolving Credit Facility”). The Credit Agreement has been amended six times, most recently in March 2012 , to address certain issues with regard to covenants, maturity and the borrowing limits under the Term Loans and Revolving Credit Facility.  For additional information regarding the current terms of our credit facility see Note 9 of our 2011 Form 10-K.

On February 21, 2012, we entered into an amendment to our Credit Agreement.   Under the terms of the amendment the participating lenders agree to loan us $100.0 million pursuant to a new term loan (“Term Loan A”).  The terms of the new Term Loan A are the same as those governing the Revolving Credit Facility, with the Term Loan A requiring a $5 million annual payment of its principal balance. The Term Loan A was funded in late March 2012 and we used the borrowings under Term Loan A to repurchase a portion of our Senior Unsecured Notes. 

The Term Loan currently bears interest either at the one-, two-, three- or six-month LIBOR at our election plus an applicable margin of between 2.25% and 3.5% depending on our consolidated leverage ratio.  Our average interest rate on the Term Loan for the three-month periods ended March 31, 2012 and 2011 was approximately 4.0% and 3.0%, respectively, including the effects of our interest rate swaps (Note 16).  Our Term Loan is currently scheduled to mature on July 1, 2015 but could be extended to July 1, 2016 if our Senior Unsecured Notes are fully repaid or refinanced by July 1, 2015.

As amended, our Revolving Credit Facility provides for $600 million in borrowing capacity. The full amount of the Revolving Credit Facility may be used for issuances of letters of credit.  In late March 2012, we borrowed $100.0 million under our Revolving Credit Facility to repurchase a portion of our Senior Unsecured Notes.  Accordingly, at March 31, 2012, we had $100.0 million drawn on the Revolving Credit Facility and our availability under the Revolving Credit Facility totaled $453.8 million, net of $46.2 million of letters of credit issued.  There were no borrowings outstanding at December 31, 2011.

The Revolving Loans bear interest based on one-, two-, three- or six-month LIBOR rates or on Base Rates, at our election, plus an applicable margin. The margin ranges from 1.5% to 3.5%, depending on our consolidated leverage ratio. The average interest rate under the Revolving Credit Facility totaled 3.0% for the period in which we had borrowings outstanding during the three-month period ended March 31, 2012.

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, which extended to January 2012.  In August 2011, we entered into additional two-year

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interest rate swap contracts to assist in stabilizing cash flows related to our interest payments from January 2012 through January 2014 (Note 16).

Convertible Senior Notes

In March 2005, we issued $300 million of our 3.25% Convertible Senior Notes at 100% of the principal amount to certain qualified institutional buyers (the “2025 Notes”).  The 2025 Notes are convertible into cash and, if applicable, shares of our common stock based on the specified conversion rate, subject to adjustment.

The 2025 Notes can be converted prior to the stated maturity (March 2025) under certain triggering events specified in the indenture governing the 2025 Notes.  No conversion triggers were met during the three-month period ended March 31, 2012. The first dates for early redemption of the 2025 Notes are in December 2012, with the holders of the 2025 Notes being able to put them to us on December 15, 2012 and our being able to call the 2025 Notes at any time after December 20, 2012 (see Note 9 of our 2011 Form 10-K).   To the extent we do not have long-term financing secured to cover such conversion and/or redemption, the 2025 Notes would be classified as a current liability in the accompanying consolidated balance sheet.  As the holders have the option to require us to redeem the 2025 Notes on December 15, 2012, we assessed whether or not this indebtedness was required to be classified as a current liability at March 31, 2012 and concluded that it still qualified as a long term debt because  a) we possess enough borrowing capacity under our Revolving Credit Facility (see “Credit Agreement” above) to settle the notes in full and b) it is our intent to utilize our Revolving Credit Facility borrowings or other alternative financing proceeds to settle our 2025 Notes, if and when the holders exercise their redemption option.

The remaining balance of our 2025 Notes was $157.8 million at March 31, 2012.   In association with the issuance of additional Convertible Senior Notes (see “2032 Notes” below), we repurchased $142.2 million in aggregate principal of our 2025 Notes.  In these repurchase transactions we paid an aggregate amount of $145.1 million, representing principal plus $1.8 million of premium and $1.1 million of accrued interest on these repurchased 2025 Notes.  The loss on the early extinguishment of these related 2025 Notes totaled $5.6 million and is reflected as a component of “Loss on early extinguishment of long term debt” in the accompanying condensed consolidated statements of operations and comprehensive income.  The loss on early extinguishment includes the acceleration of $3.5 million of related unamortized discounts associated with the 2025 Notes, the $1.8 million premium paid in connection with the repurchase of a portion of the 2025 Notes and a $0.3 million charge to accelerate a pro rata portion of the deferred financing costs associated with the original issuance of these 2025 Notes.

The effective interest rate for the 2025 Notes is 6.6% after considering the effect of the accretion of the related debt discount that represented the equity component of the Convertible Notes at their inception.

Our average share price for the both the first quarter of 2012 and 2011 was below the $32.14 per share conversion price.  As a result of our share price being lower than the $32.14 per share conversion price for these periods, there are no shares included in our diluted earnings per share calculation associated with the assumed conversion of our 2025 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.

2032 Notes

In March 2012, we completed the public offering and sale of $200.0 million in aggregate principal amount of 3.25% Convertible Senior Notes due 2032 (the “2032 Notes”).  The net proceeds from the issuance of the 2032 Notes were $195.0 million, after deducting the underwriter’s discounts and commissions and estimated offering expenses.  We used the net proceeds to repurchase and retire $142.2 million of aggregate principal amount of our 2025 Notes (see above), in separate, privately negotiated transactions, and intend to use the remaining net proceeds for other general corporate purposes, including the repayment of other indebtedness.

The registered 2032 Notes bear interest at a rate of 3.25% per annum, payable semi-annually in arrears on March 15 and September 15 of each year, beginning on September 15, 2012.  The 2032 Notes will mature on March 15, 2032, unless earlier converted, redeemed or repurchased by us.  The 2032 Notes are convertible in certain circumstances and during certain periods at an initial conversion rate of 39.9752

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shares of common stock per $1,000 principal amount of the 2032 Notes (which represents an initial conversion price of approximately $25.02 per share of common stock), subject to adjustment in certain circumstances as set forth in the indenture governing the 2032 Notes.  The initial conversion price represents a conversion premium of 35.0% over the closing price of our common stock on March 6, 2012 of $18.53 per share.

Prior to March 20, 2018, the 2032 Notes will not be redeemable.  On or after March 20, 2018, we may, at our option, redeem some or all of the 2032 Notes in cash, at any time, upon at least 30 days’ notice at a price equal to 100% of the principal amount of the 2032 Notes to be redeemed plus accrued and unpaid interest (including contingent interest, if any) up to but excluding the redemption date.  Holders may require us to purchase in cash some or all of their 2032 Notes at a repurchase price equal to 100% of the principal amount of the 2032 Notes, plus accrued and unpaid interest (including contingent interest, if any) up to but excluding the applicable repurchase date, on March 15, 2018, March 15, 2022 and March 15, 2027, or, subject to specified exceptions, at any time prior to the 2032 Notes’ maturity following a fundamental change.

In connection with the issuance of our 2032 Notes, we recorded a discount of $35.4 million as required under existing accounting requirements.  To arrive at this discount amount, we estimated the fair value of the liability component of the 2032 Notes as of the date of their issuance (March 12, 2012) using an income approach.  To determine this estimated fair value, we used borrowing rates of similar market transactions involving comparable liabilities at the time of issuance and an expected life of 6.0 years.  In selecting the expected life, we selected the earliest date that the holder could require us to repurchase all or a portion of the 2032 Notes (March 15, 2018).  The effective interest rate for the 2032 Notes is 6.9% after considering the effect of the accretion of the related debt discount that represented the equity component of the 2032 Notes at their inception.

MARAD Debt

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

Other

In accordance with our Credit Agreement, Senior Unsecured Notes, 2025 Notes, 2032 Notes and MARAD Debt agreements, we are required to comply with certain covenants, including the maintenance of minimum net worth, working capital and debt-to-equity requirements, and restrictions that limit our ability to incur certain types of additional indebtedness.  As of March 31, 2012, we were in compliance with these covenants and restrictions.

Deferred financing costs of $28.1 million and $26.5 million are included in other assets, net as of March 31, 2012 and December 31, 2011, respectively, and are being amortized over the life of the respective financing agreements.

Note 8 – Income Taxes

     The effective tax rate for the three-month period ended March 31, 2012 was 29.1% as compared to 26.4% for the three-month period ended March 31, 2011. The variance is primarily attributable to increased profitability in certain foreign jurisdictions with higher income tax rates.

     We believe our recorded assets and liabilities are reasonable; however, tax laws and regulations are subject to interpretation and tax litigation is inherently uncertain, and therefore our assessments can involve a series of complex judgments about future events and rely heavily on estimates and assumptions.

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Note 9 – Comprehensive Income and Accumulated Other Comprehensive Loss

The components of total comprehensive income for the three-month periods ended March 31, 2012 and 2011 were as follows (in thousands):

		Three Months Ended
		March 31,
		2012			2011
Net income, including noncontrolling interests	$	66,526		$	26,635
Other accumulated comprehensive income, net of tax
Foreign currency translation gain		4,152			2,115
Unrealized loss on hedges, net		(13,802	)		(10,567	)
Total  comprehensive income	$	56,876		$	18,183

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

	March 31,			December 31,
	2012			2011
Cumulative foreign currency translation adjustment	$	(18,806	)	$	(22,958	)
Unrealized gain (loss) on hedges, net		(861	)		12,941
Accumulated other comprehensive loss	$	(19,667	)	$	(10,017	)

Note 10 – Earnings Per Share

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

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

		Three Months Ended				Three Months Ended
		March 31, 2012				March 31, 2011
		Income		Shares		Income		Shares
Basic:
Net income applicable to common shareholders	$	65,727			$	25,857
Less: Undistributed net income allocable to participating securities		(677	)			(338	)
Net income applicable to common shareholders	$	65,050		104,530	$	25,519		104,471

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		Three Months Ended March 31, 2012			Three Months Ended March 31, 2011
		Income	Shares		Income	Shares
Diluted:
Net  income per common share - Basic	$	65,050	104,530	$	25,519	104,471
Effect of dilutive securities:
Stock options		─	98		─	71
Undistributed earnings reallocated to participating securities		3	─		1	─
2025 Notes and 2032 Notes		─	─		─	─
Convertible preferred stock		10	361		10	361
Net income per common share - Diluted	$	65,063	104,989	$	25,530	104,903

There were no diluted shares associated with our 2025 Convertible Senior Notes as the conversion price of $32.14 (and conversion trigger of $38.57 per share) was not met in either of the three-month periods ended March 31, 2012 and 2011.    Also, no diluted shares were included for our 2032 Notes for the three-month period ended March 31, 2012 as the conversion price of $25.02 (and conversion trigger of $32.53 per share) was not met and we have the right to settle any such future conversions in cash at our sole discretion.

Note 11 – Stock-Based Compensation Plans

We have two stock-based compensation plans: the 1995 Long-Term Incentive Plan, as amended (the “1995 Incentive Plan”) and the 2005 Long-Term Incentive Plan, as amended (the “2005 Incentive Plan”).  As of March 31, 2012, there were 401,642 shares available for grant under our 2005 Incentive Plan. There were no stock option grants in the three-month periods ended March 31, 2012 and 2011.During the three-month period ended March 31, 2012, the following grants of share-based awards (restricted shares, restricted stock units and performance share units) were made 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 3, 2012	537,973	$	15.80	33% per year over three years
January 3, 2012	1,958		15.80	100% on January 1, 2014

Compensation cost is recognized over the respective vesting periods on a straight-line basis.  For the three-month period ended March 31, 2012, $1.8 million was recognized as compensation expense related to shared based awards as compared with $3.0 million during the three-month period ended March 31, 2011.

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 (the vesting period is five years for awards granted before January 1, 2012 and three years thereafter).  However, some of the cash awards are indexed to our Company common stock and the payment amount at each vesting date will fluctuate based on the common stock’s performance. This share-based component is considered a liability plan and as such is re-measured to fair value each reporting period with corresponding changes being recorded as a charge to earnings as appropriate.

The total awards made under the 2009 LTI Plan totaled $4.2 million in 2012 and $5.2 million in 2011.   Total compensation expense under the 2009 LTI plan totaled $2.4 million and $3.0 million for the three-month periods ended March 31, 2012 and 2011, respectively.   The liability balance under the 2009 LTI Plan was $6.9 million at March 31, 2012 and $9.9 million at December 31, 2011, including $6.5 million at March 31, 2012 and $8.5 million at December 31, 2011 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 2011 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 consist of the following: Contracting Services, Production Facilities and Oil and Gas. Contracting Services operations include well operations, robotics and subsea construction.  The Production Facilities segment includes our consolidated investment in the HP I and Kommandor LLC as well as our equity investments in Deepwater Gateway and Independence Hub that are accounted for under the equity method of accounting.

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

		Three Months Ended
		March 31,
		2012			2011
		(in thousands)
Revenues ─
Contracting Services	$	244,544		$	131,537
Production Facilities		20,022			15,570
Oil and Gas		178,085			168,859
Intercompany elimination		(34,724	)		(24,359	)
Total	$	407,927		$	291,607

Income (loss) from operations ─
Contracting Services	$	59,124		$	3,266
Production Facilities		10,049			5,956
Oil and Gas		76,942			53,240
Corporate		(10,898	)		(10,441	)
Intercompany elimination		(3,020	)		90
Total	$	132,197		$	52,111
Equity in earnings of equity investments	$	407		$	5,650

	March 31, 2012		December 31, 2011
		(in thousands)
Identifiable Assets ─
Contracting Services	$	2,128,639	$	2,006,065
Production Facilities		534,155		534,776
Oil and Gas		1,002,149		1,041,506
Total	$	3,664,943	$	3,582,347

Intercompany segment revenues during the three-month periods ended March 31, 2012 and 2011 were as follows:

		Three Months Ended
		March 31,
		2012		2011
		(in thousands)
Contracting Services	$	23,201	$	12,869
Production Facilities		11,523		11,490
Total	$	34,724	$	24,359

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 Intercompany segment profits during the three-month periods ended March 31, 2012 and 2011 were as follows:

		Three Months Ended
		March 31,
		2012			2011
		(in thousands)
Contracting Services	$	3,064		$	(24	)
Production Facilities		(44	)		(66	)
Total	$	3,020		$	(90	)

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 $1.7 million and $2.3 million for the three-month periods ended March 31, 2012 and 2011, respectively.  Our Chief Executive Officer, Owen Kratz, through Class A limited partnership interests in OKCD, personally owns approximately 81% 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

Commitments

In March 2012, we executed a shipyard contract for the construction of a newbuild semisubmersible well intervention vessel.  This $385.5 million shipyard contract represents the majority of the expected costs associated with this new semisubmersible well intervention vessel.   We made the first scheduled payment under the contract in the amount of $57.8 million on March 12, 2012.  Under terms of this contract, payments will be made in fixed amounts on contractually scheduled dates.

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 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 a 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 2011 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 for the tax years 2007, 2008, 2009 and  2010 related to a subsea construction and diving contract we entered into in December 2006 in India.  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 relate 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.

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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

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 for which there is little or no market data, which require the reporting entity to develop its own assumptions.

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

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

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

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

The following table provides additional information related to assets and liabilities measured at fair value on a recurring basis at March 31, 2012 (in thousands):

	Level 1		Level 2 (1)		Level 3		Total		Valuation Technique
Assets:
Natural gas contracts	$	–	$	20,239	$	–	$	20,239	(c)
Interest rate swaps		–		83		–		83	(c)
Foreign currency forwards		–		110		–		110	(c)
Liabilities:
Oil contracts		–		23,647		–		23,647	(c)
Fair value of long term debt(2)		1,143,077		119,609		–		1,262,686	(a), (b)
Interest rate swaps		–		338		–		338	(c)
Foreign currency forwards		–		13		–		13	(c)
Total net liability	$	1,143,077	$	123,175	$	–	$	1,266,252

(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 could be positive or negative.

(2)   See Note 7 for additional information regarding our long term debt.   The fair value of our long term debt at March 31, 2012 is as follows:

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	Fair Value		Carrying Value
Term Loans (mature July 2015)	$	380,395	$	379,000
Revolving Credit Facility (matures July 2015)		100,000		100,000
2025 Notes (mature March 2025)		160,099		157,830	(a)
2032 Notes (mature March 2032)		212,500		200,000	(b)
Senior Unsecured Notes (mature January 2016)		290,083		274,960
MARAD Debt (matures February 2027) (c)		119,609		107,756
Total	$	1,262,686	$	1,219,546

(a)   Amount excludes the related unamortized debt discount of $3.7 million.

(b)   Amount excludes the related unamortized debt discount of $35.4 million.

(c)   The estimated fair value of all debt, other than the 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 marketplace with similar terms.   The fair value of the MARAD Debt was estimated using Level 2 fair value inputs using the market approach.

Note 16 – Derivative Instruments and Hedging Activities

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

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

For additional information regarding our accounting for derivatives see Notes 2 and 20 of our 2011 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 2012 and 2013.  All of our current commodity derivative contracts qualify for hedge accounting.

As of March 31, 2012, we had the following volumes under derivative contracts related to our oil and gas producing activities, totaling approximately 2.9 million barrels of oil and 14.4 Bcf of natural gas:

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Production Period	Instrument Type	Average Monthly Volumes	Weighted Average Price a
Crude Oil:			(per barrel)
April 2012 — December 2012	Collar	75.0 MBbl	$  96.67 — $118.57b
April 2012 — December 2012	Collar	118.6 MBbl	$  99.52 — $118.06
April 2012 — December 2012	Swap	11.4 MBbl	$103.20
January 2013 — December 2013	Swap	41.7 MBbl	$99.15
January 2013 — December 2013	Collar	50.0 MBbl	$  95.83 — $105.50
Natural Gas:			(per Mcf)
April 2012 — December 2012	Swap	771.1 Mmcf	$4.32
April 2012 — December 2012	Collar	162.2 Mmcf	$4.75 —  $5.09
January 2013 — December 2013	Swap	500.0 Mmcf	$4.09

a.   The prices quoted in the table above are NYMEX Henry Hub for natural gas.  Most of our current contracts are indexed to the Brent crude oil price.

b.   This contract is priced using NYMEX West Texas Intermediate for crude oil.

In April 2012, we entered into costless collar financial derivative contracts associated with a total of 1.0 MMBbls of our anticipated crude oil production in 2013, with a floor price of $100.00 per barrel and a ceiling price of $122.06 per barrel as indexed to Brent crude oil prices.

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

Variable Interest Rate Risks

As some of our long-term debt has variable interest rates and is subject to market influences, 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).  The last of these monthly contracts matured in January 2012.  In August 2011, we entered into additional interest rate swap contracts to fix the interest rate on $200 million of our Term Loan debt.   These monthly contracts began in January 2012 and extend through January 2014.  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.  The amount of ineffectiveness associated with our interest swap contracts was immaterial for all periods presented in this Quarterly Report on Form 10-Q.

Foreign Currency Exchange Risks

Because we operate in various regions in the world, we conduct a portion of our business in currencies other than the U.S. dollar.  We entered into various foreign currency forwards to stabilize expected cash outflows relating to certain vessel charters denominated in British pounds.  We did not designate any of our existing foreign exchange contracts as hedge contracts at their inception. The last of our existing monthly foreign currency swap contracts will settle in June 2012.

Quantitative Disclosures Related to Derivative Instruments

The following tables present the fair value and balance sheet classification of our derivative instruments as of March 31, 2012 and December 31, 2011.

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Derivatives designated as hedging instruments are as follows:

	As of March 31, 2012			As of December 31, 2011
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Asset Derivatives:
Natural gas contracts	Other current assets	$	16,744	Other current assets	$	12,957
Oil contracts	Other current assets		931	Other current assets		8,567
Natural gas contracts	Other assets		2,564	Other assets		857
Interest rate swaps	Other assets		83	Other assets		327
		$	20,322		$	22,708

	As of March 31, 2012			As of December 31, 2011
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Liability Derivatives:
Oil contracts	Accrued liabilities	$	14,816	Accrued liabilities	$	886
Interest rate swaps	Accrued liabilities		338	Accrued liabilities		202
Oil contracts	Other long-term liabilities		8,831	Other long-term liabilities		1,711
		$	23,985		$	2,799

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

	As of March 31, 2012			As of December 31, 2011
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Asset Derivatives:
Foreign exchange forwards	Other current assets	$	110	Other current assets	$	55
		$	110		$	55

	As of March 31, 2012			As of December 31, 2011
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Liability Derivatives:
Foreign exchange forwards	Accrued liabilities		13	Accrued liabilities		159
		$	13		$	159

The following tables present the impact that derivative instruments designated as cash flow hedges had on our accumulated comprehensive income (loss) and our consolidated condensed statements of operations and comprehensive income for the three-month periods ended March 31, 2012 and 2011.  The ineffectiveness related to some of our crude oil contracts totaled $2.3 million for the three-month period ended March 31, 2012 and is reflected as a separate line item titled “Loss on oil and gas derivative commodity contracts” in the accompanying condensed consolidated statements of operations and comprehensive income.  Ineffectiveness associated with our interest swaps was immaterial for all periods presented in this report.  All unrealized gains (losses) related to our derivative contracts are expected to be reclassified to earnings by no later than December 31, 2013.   The last of our interest rate swaps will be settled in January 2014.  At March 31, 2012, most of our remaining unrealized gains (losses) related to our derivative contracts are expected to be reclassified into earnings in 2012, including $2.8 million for our oil and natural gas contracts and $(0.2) million related to our interest swap contracts.

21

		Gain (Loss) Recognized in Accumulated OCI on Derivatives
		2012			2011
		(in thousands)
Oil and natural gas commodity contracts	$	(13,555	)	$	(10,778	)
Interest rate swaps		(247	)		211
	$	(13,802	)	$	(10,567	)

	Location of Gain (Loss) Reclassified from Accumulated OCI into Income		Gain (Loss) Recognized from Accumulated OCI into Income
			2012			2011
			(in thousands)
Oil and natural gas commodity contracts	Oil and gas revenue	$	109		$	(6,325	)
Interest rate swaps	Net interest expense		(193	)		(480	)
		$	(84	)	$	(6,805	)

The following tables present the impact that derivative instruments not designated as hedges had on our condensed consolidated statement of operations for the three months ended March 31, 2012 and 2011:

	Location of Gain (Loss) Recognized in Income on Derivatives		Gain (Loss) Recognized in Income on Derivatives
			2012		2011
			(in thousands)
Foreign exchange forwards	Other expense		233		608
		$	233	$	608

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.

22

 HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(in thousands)

(Unaudited)

	As of March 31, 2012
		Helix			Guarantors		Non-Guarantors			Consolidating Entries			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	566,287		$	2,498	$	51,664		$	—		$	620,449
Accounts receivable, net		50,886			118,038		68,493			—			237,417
Unbilled revenue		5,777			228		18,571			—			24,576
Income taxes receivable		86,005			—		1,586			(87,591	)		—
Other current assets		54,484			45,654		9,864			(333	)		109,669
Total current assets		763,439			166,418		150,178			(87,924	)		992,111
Intercompany		(157,195	)		340,018		(107,547	)		(75,276	)		—
Property and equipment, net		227,620			1,456,602		682,200			(4,735	)		2,361,687
Other assets:
Equity investments in unconsolidated affiliates		—			—		173,440			—			173,440
Equity investments		2,019,076			39,864		—			(2,058,940	)		—
Goodwill		—			45,107		17,560			—			62,667
Other assets, net		54,828			36,566		21,475			(37,831	)		75,038
Due from subsidiaries/parent		56,189			509,701		—			(565,890	)		—
	$	2,963,957		$	2,594,276	$	937,306		$	(2,830,596	)	$	3,664,943
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	42,316		$	67,950	$	35,365		$	—		$	145,631
Accrued liabilities		68,627			107,284		20,903			—			196,814
Income taxes payable		—			128,808		—			(103,831	)		24,977
Current maturities of long-term debt		8,000			—		4,997			—			12,997
Total current liabilities		118,943			304,042		61,265			(103,831	)		380,419
Long-term debt		1,064,726			—		102,760			—			1,167,486
Deferred income taxes		234,567			90,526		103,861			(5,856	)		423,098
Asset retirement obligations		—			146,696		—			—			146,696
Other long-term liabilities		4,163			11,803		550			—			16,516
Due to parent		—			—		89,821			(89,821	)		—
Total liabilities		1,422,399			553,067		358,257			(199,508	)		2,134,215
Convertible preferred stock		1,000			—		—			—			1,000
Total equity		1,540,558			2,041,209		579,049			(2,631,088	)		1,529,728
	$	2,963,957		$	2,594,276	$	937,306		$	(2,830,596	)	$	3,664,943

23

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(in thousands)

	As of December 31, 2011
		Helix			Guarantors		Non-Guarantors			Consolidating Entries			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	495,484		$	2,434	$	48,547		$	—		$	546,465
Accounts receivable, net		79,290			117,767		41,724			—			238,781
Unbilled revenue		10,530			155		26,690			—			37,375
Income taxes receivable		80,388			—		—			(80,388	)		—
Other current assets		68,627			48,661		10,159			(5,826	)		121,621
Total current assets		734,319			169,017		127,120			(86,214	)		944,242
Intercompany		(147,187	)		315,821		(102,826	)		(65,808	)		—
Property and equipment, net		230,946			1,422,326		682,899			(4,844	)		2,331,327
Other assets:
Equity investments in unconsolidated affiliates		—			—		175,656			—			175,656
Equity investments in affiliates		1,952,392			37,239		—			(1,989,631	)		—
Goodwill, net		—			45,107		17,108			—			62,215
Other assets, net		53,425			36,453		16,809			(37,780	)		68,907
Due from subsidiaries/parent		64,655			430,496		—			(495,151	)		—
	$	2,888,550		$	2,456,459	$	916,766		$	(2,679,428	)	$	3,582,347
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	39,280		$	82,750	$	25,013		$	—		$	147,043
Accrued liabilities		115,921			97,692		26,350			—			239,963
Income taxes payable		—			97,692		217			(96,616	)		1,293
Current maturities of long-term debt		3,000			—		10,377			(5,500	)		7,877
Total current liabilities		158,201			278,134		61,957			(102,116	)		396,176
Long-term debt		1,042,155			—		105,289			—			1,147,444
Deferred income taxes		231,255			88,625		103,552			(5,822	)		417,610
Decommissioning liabilities		—			161,208		—			—			161,208
Other long-term liabilities		4,150			4,647		571			—			9,368
Due to parent		—			—		98,285			(98,285	)		—
Total liabilities		1,435,761			532,614		369,654			(206,223	)		2,131,806
Convertible preferred stock		1,000			—		—			—			1,000
Total equity		1,451,789			1,923,845		547,112			(2,473,205	)		1,449,541
	$	2,888,550		$	2,456,459	$	916,766		$	(2,679,428	)	$	3,582,347

24

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(in thousands)

(Unaudited)

	Three Months Ended March 31, 2012
	Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated
Net revenues	$	20,022		$	285,688		$	125,900		$	(23,683	)	$	407,927
Cost of sales		16,621			164,593			88,445			(23,442	)		246,217
Gross profit		3,401			121,095			37,455			(241	)		161,710
Gain on sale or acquisition of assets		—			(1,478	)		—			—			(1,478	)
Loss on oil and gas derivative contract		—			(2,339	)		—			—			(2,339	)
Selling, general and administrative expenses		(11,272	)		(9,877	)		(4,834	)		287			(25,696	)
Income (loss) from operations		(7,871	)		107,401			32,621			46			132,197
Equity in earnings of investments		93,250