SEC Filing | Helix Energy Solutions Group, Inc.

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form10q.htm

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, 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

[ √ ]

[ ]

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

[ √ ]

[ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer“ and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer [√ ]	Accelerated filer [ ]	Non-accelerated filer [ ]	Smaller reporting company [ ]
		(Do not check if a smaller reporting company)

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

Yes

[ ]

[ √ ]

As of July 20, 2012, 105,231,593 shares of common stock were outstanding.

TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION	PAGE
Item 1.	Financial Statements:
	Condensed Consolidated Balance Sheets – June 30, 2012 (Unaudited) and December 31, 2011	3
	Condensed Consolidated Statements of Operations and Comprehensive Income (Unaudited) – Three months ended June 30, 2012 and 2011	4
	Condensed Consolidated Statements of Operations and Comprehensive Income (Unaudited) – Six months ended June 30, 2012 and 2011	5
	Condensed Consolidated Statements of Cash Flows (Unaudited) – Six months ended June 30, 2012 and 2011	6
	Notes to Condensed Consolidated Financial Statements (Unaudited)	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	51
Item 4.	Controls and Procedures	52
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	53
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	53
Item 5.	Other Information	53
Item 6.	Exhibits	53
	Signatures	54
	Index to Exhibits	55

Table of Contents

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,
	2012		2011
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	649,503	$	546,465
Accounts receivable:
Trade, net of allowance for uncollectible accounts of $4,067		187,904		238,781
Unbilled revenue		30,053		24,338
Costs in excess of billing		21,492		13,037
Other current assets		117,979		121,621
Total current assets		1,006,931		944,242
Property and equipment		4,366,783		4,391,064
Less accumulated depreciation		(2,007,490)		(2,059,737)
Property and equipment, net		2,359,293		2,331,327
Other assets:
Equity investments		173,543		175,656
Goodwill		62,252		62,215
Other assets, net		86,786		68,907
Total assets	$	3,688,805	$	3,582,347

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	156,738	$	147,043
Accrued liabilities		177,225		239,963
Income tax payable		3,065		1,293
Current maturities of long-term debt		12,997		7,877
Total current liabilities		350,025		396,176
Long-term debt		1,167,908		1,147,444
Deferred tax liabilities		445,817		417,610
Asset retirement obligations		135,235		161,208
Other long-term liabilities		8,832		9,368
Total liabilities		2,107,817		2,131,806

Convertible preferred stock		1,000		1,000
Commitments and contingencies
Shareholders' equity:
Common stock, no par, 240,000 shares authorized, 105,631 and 105,530 shares issued, respectively		927,085		908,776
Retained Earnings		633,012		522,644
Accumulated other comprehensive loss		(9,825)		(10,017)
Total controlling interest shareholders' equity		1,550,272		1,421,403
Noncontrolling interest		29,716		28,138
Total equity		1,579,988		1,449,541
Total liabilities and shareholders' equity	$	3,688,805	$	3,582,347

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

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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
	June 30,
	2012			2011

Net revenues:
Contracting services	$	197,461		$	165,861
Oil and gas		149,933			172,458
Total net revenues		347,394			338,319

Cost of sales:
Contracting services		147,156			116,521
Contracting services impairments		14,590			—
Oil and gas		92,423			110,027
Oil and gas property impairments		—			11,573
Total cost of sales		254,169			238,121

Gross profit		93,225			100,198

Loss on sale of assets, net		(236	)		(22	)
Ineffectiveness on oil and gas commodity derivative contracts		10,069			—
Selling and administrative expenses		(24,571	)		(23,758	)
Income from operations		78,487			76,418
Equity in earnings of investments		5,748			5,887
Net interest expense		(18,627	)		(25,278	)
Other income (expense), net		(1,692	)		1,253
Income before income taxes		63,916			58,280
Provision for income taxes		18,476			16,171
Net income, including noncontrolling interests		45,440			42,109
Less net income applicable to noncontrolling interests		(789	)		(786	)
Net income applicable to Helix		44,651			41,323
Preferred stock dividends		(10	)		(10	)
Net income applicable to Helix common shareholders	$	44,641		$	41,313


Earnings per share of common stock:
Basic	$	0.42		$	0.39
Diluted	$	0.42		$	0.39

Weighted average common shares outstanding:
Basic		104,563			104,673
Diluted		105,042			105,140

Total comprehensive income applicable to Helix common shareholders (Note 9)	$	54,483		$	60,867

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

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(UNAUDITED)

(in thousands, except per share amounts)

	Six Months Ended
	June 30,
	2012			2011

Net revenues:
Contracting services	$	427,303		$	288,609
Oil and gas		328,018			341,317
Total net revenues		755,321			629,926

Cost of sales:
Contracting services		304,124			223,428
Contracting services impairments		14,590			—
Oil and gas		181,672			217,651
Oil and gas property impairments		—			11,573
Total cost of sales		500,386			452,652

Gross profit		254,935			177,274

Loss on sale of assets, net		(1,714	)		(6	)
Ineffectiveness on oil and gas commodity derivative contracts		7,730			—
Selling and administrative expenses		(50,267	)		(48,739	)
Income from operations		210,684			128,529
Equity in earnings of investments		6,155			11,537
Net interest expense		(40,387	)		(49,514	)
Loss on early extinguishment of long-term debt		(17,127	)		—
Other income (expense), net		(1,606	)		3,913
Income before income taxes		157,719			94,465
Provision for income taxes		45,753			25,721
Net income, including noncontrolling interests		111,966			68,744
Less net income applicable to noncontrolling interests		(1,578	)		(1,554	)
Net income applicable to Helix		110,388			67,190
Preferred stock dividends		(20	)		(20	)
Net income applicable to Helix common shareholders	$	110,368		$	67,170


Earnings per share of common stock:
Basic	$	1.05		$	0.63
Diluted	$	1.04		$	0.63

Weighted average common shares outstanding:
Basic		104,547			104,573
Diluted		105,012			105,024

Total comprehensive income applicable to Helix common shareholders (Note 9)	$	110,560		$	78,272

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

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(in thousands)

	Six Months Ended
	June 30,
	2012			2011
Cash flows from operating activities:
Net income, including noncontrolling interests	$	111,966		$	68,744
Adjustments to reconcile net income, including noncontrolling interests to net cash provided by operating activities:
Depreciation and amortization		134,960			167,170
Asset impairment charge and dry hole expense		14,679			18,204
Amortization of deferred financing costs		3,292			4,777
Stock-based compensation expense		3,658			4,938
Amortization of debt discount		4,776			4,414
Deferred income taxes		21,624			23,864
Excess tax benefit from stock-based compensation		657			1,196
Gain on investment in Cal Dive common stock		—			(753	)
Loss on sale of assets, net		1,714			6
Loss on early extinguishment of debt		17,127			—
Unrealized gain and ineffectiveness on derivative contracts, net		(7,581	)		(34	)
Changes in operating assets and liabilities:
Accounts receivable, net		46,611			(18,207	)
Other current assets		(5,854	)		12,712
Income tax payable		1,083			(4,154	)
Accounts payable and accrued liabilities		(61,372	)		(27,070	)
Oil and gas asset retirement costs		(54,976	)		(16,073	)
Other noncurrent, net		(11,344	)		10,839
Net cash provided by operating activities		221,020			250,573

Cash flows from investing activities:
Capital expenditures		(150,107	)		(106,122	)
Distributions (investments) from equity investments, net		2,045			(1,106	)
Proceeds from sale of Cal Dive common stock		—			3,588
Decrease in restricted cash		2,660			863
Net cash used in investing activities		(145,402	)		(102,777	)

Cash flows from financing activities:
Extinguishment of Senior Unsecured Notes		(209,500	)		—
Borrowings under revolving credit facility		100,000			109,400
Repayment of revolving credit facility		—			(109,400	)
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		(2,750	)		(111,191	)
Repayment of MARAD borrowings		(2,409	)		(2,294	)
Deferred financing costs		(6,485	)		(9,014	)
Repurchases of common stock		(7,510	)		(1,012	)
Excess tax benefit from stock-based compensation		(657	)		(1,196	)
Exercise of stock options, net and other		372			439
Net cash provided by (used in) financing activities		27,116			(124,268	)

Effect of exchange rate changes on cash and cash equivalents		304			(424	)
Net increase in cash and cash equivalents		103,038			23,104
Cash and cash equivalents:
Balance, beginning of year		546,465			391,085
Balance, end of period	$	649,503		$	414,189

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

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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, statements of operations and comprehensive income, and cash flows, as applicable. The operating results for the three- and six-month periods ended June 30, 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 specialty services to the offshore energy industry, with a focus on our growing well intervention and robotics businesses. We also own an oil and gas business that is a prospect generation, exploration, development and production company. We utilize cash flow generated from our oil and gas production to support expansion of our well intervention and robotics businesses. Our Contracting Services are located primarily in the Gulf of Mexico, North Sea, Asia Pacific, and West Africa regions. Our oil and gas operations are located in the Gulf of Mexico.

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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 includes the 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 access to 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.

Note 3 – Details of Certain Accounts

Other current assets consisted of the following as of June 30, 2012 and December 31, 2011:

	June 30,		December 31,
	2012		2011
	(in thousands)

Other receivables	$	2,120	$	5,096
Prepaid insurance		11,247		12,701
Other prepaids		15,937		13,271
Spare parts inventory		15,697		18,066
Current deferred tax assets		36,504		41,449
Hedging assets		25,696		21,579
Gas and oil imbalance		4,367		5,134
Other		6,411		4,325
Total other current assets	$	117,979	$	121,621

Other assets, net, consisted of the following as of June 30, 2012 and December 31, 2011:

	June 30,			December 31,
	2012			2011
	(in thousands)

Restricted cash	$	31,081		$	33,741
Deferred dry dock expenses, net		20,341	(1)		5,381
Deferred financing costs, net		26,528			26,483
Intangible assets with finite lives, net		483			531
Other		8,353			2,771
Total other assets, net	$	86,786		$	68,907

(1)	The increase subsequent to December 31, 2011 primarily reflects the costs associated with the completed regulatory dry docks for the Q4000 and Seawell in the first half of 2012.

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Accrued liabilities consisted of the following as of June 30, 2012 and December 31, 2011:

	June 30,		December 31,
	2012		2011
	(in thousands)

Accrued payroll and related benefits	$	44,642	$	49,599
Royalties payable		11,943		19,391
Current asset retirement obligations		69,630		93,183
Unearned revenue		7,649		7,654
Billing in excess of cost		2,994		28,839
Accrued interest		17,509		24,028
Hedging liability		5,685		1,247
Gas and oil imbalance		3,609		4,177
Other		13,564		11,845
Total accrued liabilities	$	177,225	$	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 June 30, 2012, we capitalized approximately $32.8 million of costs associated with ongoing exploration and/or appraisal activities, including $26.9 million associated with our Danny II exploratory well at Garden Banks Block 506 (see below). 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, 2012 and 2011:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2012			2011		2012			2011

Delay rental and geological and geophysical costs	$	1,146		$	1,299	$	1,757		$	1,654
Impairment of unproved properties (1)		—			6,640		144			6,640
Dry hole expense		(54	)		—		(55	)		(9	)
Total exploration expense	$	1,092		$	7,939	$	1,846		$	8,285

(1)	The amount recorded in the second quarter of 2011 reflects costs associated with a deepwater lease in which the term expired.

Danny II

We hold a 50% interest in the Danny II prospect at Garden Banks Block 506. The Danny II exploration well was drilled to a total depth of approximately 14,750 feet, in water depths of approximately 2,800 feet. Based on preliminary data, the well has encountered hydrocarbon pay and is expected to be predominately an oil producer. The well is currently being completed and is expected to be developed via a subsea tie back system to our 70% owned and operated East Cameron Block 381 platform.

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Impairments

We did not record any oil and gas property impairments during the three-month period ended June 30, 2012. We recorded impairment charges totaling $11.6 million associated with five of our Gulf of Mexico oil and gas properties during the three-month period ended June 30, 2011. There were no proved property impairments in the first quarter of 2012 or 2011.

Asset retirement obligations

The following table describes the changes in our asset retirement obligations (both current and long-term) 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		(80,166	)
Other revisions in estimated cash flows (1)		23,671
Accretion expense (included in depreciation and amortization)		6,854
Asset retirement obligations at June 30, 2012	$	204,865

(1)

The increased amount of these liabilities includes revisions to both non-producing and producing oil and gas properties. Increases to liabilities associated with non-producing properties include a corresponding cost of sales expense charge within our consolidated condensed statements of operations and comprehensive income while changes in estimates for producing properties are recorded as an increase to the related oil and gas properties property and equipment carrying costs included within our consolidated condensed balance sheet.

In the second quarter of 2012, we recorded an expense charge of $6.9 million related to our only non-domestic oil and gas property, which is located in the North Sea. The charge reflects the increase in our estimated costs to complete our abandonment activities at this non-producing field. These activities are ongoing and are scheduled to be completed in the third quarter of 2012. In the second quarter of 2011, we recorded $11.1 million of expense charges to increase our asset retirement obligations related to five non-producing fields, including $4.1 million related to our oil and gas property located in the North Sea.

Insurance

On June 30, 2012, we obtained a hurricane catastrophic bond for the period from July 1, 2012 to June 30, 2013 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 2012 and $2.0 million in the fourth quarter of 2012 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 $31.1 million at June 30, 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 future asset retirement costs of the field. 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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The following table provides supplemental cash flow information for the six-month periods ended June 30, 2012 and 2011 (in thousands):

		Six Months Ended
		June 30,
		2012		2011

Interest paid, net of capitalized interest	$	39,259	$	40,220
Income taxes paid	$	23,054	$	7,236

Non-cash investing activities for the six-month periods ended June 30, 2012 and 2011 included $37.8 million and $33.7 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 June 30, 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 $95.0 million and $96.0 million as of June 30, 2012 and December 31, 2011, respectively (including capitalized interest of $1.4 million at June 30, 2012 and December 31, 2011). Our net distributions from Deepwater Gateway totaled $1.3 million and $3.4 million for the three- and six-month periods ended June 30, 2012, respectively.

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 $78.5 million and $79.7 million as of June 30, 2012 and December 31, 2011, respectively (including capitalized interest of $4.7 million and $4.9 million at June 30, 2012 and December 31, 2011, respectively). Our net distributions from Independence Hub totaled $0.6 million and $4.8 million in the three- and six-month periods ended June 30, 2012, respectively.

As disclosed in our 2011 Form 10-K, we invested in an Australian joint venture that engaged 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 the joint venture, including a $3.0 million negotiated exit fee. In April 2012, we paid this fee and exited the joint venture. In connection with our exit, we were entitled to 50% of certain of the net assets on hand at the time of our departure. We received approximately $3.7 million of proceeds for our pro rata portion of certain of the joint venture’s net assets, which was recorded as income in “Equity in earnings of investments” during the second quarter of 2012. We are no longer a participant in this Australian joint venture.

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Note 7 – Long-Term Debt

Scheduled maturities of long-term debt outstanding as of June 30, 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		353,000			100,000		274,960		—			5,783			—			733,743
Four to five years		—			—		—		—			6,072			—			6,072
Over five years		—			—		—		157,830			80,150			200,000			437,980
Total debt		377,000			100,000		274,960		157,830			107,757			200,000			1,217,547
Current maturities		(8,000	)		—		—		—			(4,997	)		—			(12,997	)
Long-term debt, less current maturities	$	369,000		$	100,000	$	274,960	$	157,830		$	102,760		$	200,000		$	1,204,550
Unamortized debt discount (4)		—			—		—		(2,482	)		—			(34,160	)		(36,642	)
Long-term debt	$	369,000		$	100,000	$	274,960	$	155,348		$	102,760		$	165,840		$	1,167,908

(1)	Amounts reflect both our Term Loan and 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 own option 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.

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 no less than 30 days’ and no 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.


	Year		Redemption Price

	2012		104.750%
	2013		102.375%
	2014 and thereafter		100.000%

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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, a $9.5 million 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 February 2012, to address certain issues with regard to covenants, maturity and the borrowing limits under the Term Loans and the 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 an additional term loan (the “Term Loan A”). The terms of 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 the Term Loan A to repurchase a portion of our Senior Unsecured Notes.

The Term Loan currently bears interest at the one-, two-, three- or six-month LIBOR or on Base Rates at our current election plus an applicable margin between 2.25% and 3.5% depending on our consolidated leverage ratio. Our average interest rate on the Term Loan for the six-month periods ended June 30, 2012 and 2011 was approximately 3.8% and 3.2%, 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 June 30, 2012, we had $100.0 million drawn on the Revolving Credit Facility and our availability under the Revolving Credit Facility totaled $453.7 million, net of $46.3 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 current 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 six-month period ended June 30, 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 interest rate swap contracts to assist in stabilizing cash flows related to our interest payments from January 2012 through January 2014 (Note 16).

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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 six-month periods ended June 30, 2012 and 2011. 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 June 30, 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 the remaining balance of our 2025 Notes, if and when the holders exercise their redemption option.

The remaining balance of our 2025 Notes was $157.8 million at June 30, 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 was below the $32.14 per share conversion price for all of the periods presented in this Quarterly Report on Form 10-Q. As a result, 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 upon 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 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

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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 June 30, 2012, we were in compliance with these covenants and restrictions.

Deferred financing costs of $26.5 million and $26.5 million are included in other assets, net as of June 30, 2012 and December 31, 2011, respectively, and are being amortized over the life of the respective financing agreements.

At June 30, 2012, our unsecured letters of credit totaled approximately $46.3 million (see “Credit Agreement” above). 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- and six-month periods ended June 30, 2012 and 2011:

		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2012			2011			2012			2011
		(in thousands)

Interest expense	$	19,947		$	26,029		$	42,756		$	50,796
Interest income		(322	)		(499	)		(892	)		(975	)
Capitalized interest		(998	)		(252	)		(1,477	)		(307	)
Interest expense, net	$	18,627		$	25,278		$	40,387		$	49,514

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Note 8 – Income Taxes

The effective tax rates for the three- and six-month periods ended June 30, 2012 were 28.9% and 29.0%, respectively. The effective tax rates for the three- and six-month periods ended June 30, 2011 were 27.7% and 27.2%, respectively. 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.

Note 9 – Comprehensive Income and Accumulated Other Comprehensive Loss

The components of total comprehensive income for the three- and six-month periods ended June 30, 2012 and 2011 were as follows (in thousands):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011

Net income, including noncontrolling interests	$	45,440		$	42,109		$	111,966		$	68,744
Other comprehensive income, net of tax
Foreign currency translation gain (loss)		(2,838	)		(1,416	)		1,314			699
Unrealized gain (loss) on hedges, net		12,680			20,970			(1,122	)		10,403
Other comprehensive income		9,842			19,554			192			11,102
Total comprehensive income		55,282			61,663			112,158			79,846
Less comprehensive income applicable to noncontrolling interests		(789	)		(786	)		(1,578	)		(1,554	)
Total comprehensive income applicable to Helix		54,493			60,877			110,580			78,292
Preferred stock dividends		(10	)		(10	)		(20	)		(20	)
Total comprehensive income applicable to Helix common shareholders	$	54,483		$	60,867		$	110,560		$	78,272

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

	June 30,			December 31,
	2012			2011

Cumulative foreign currency translation adjustment	$	(21,644	)	$	(22,958	)
Unrealized gain on hedges, net		11,819			12,941
Accumulated other comprehensive loss	$	(9,825	)	$	(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.

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The presentation of basic EPS amounts on the face of the accompanying condensed consolidated statements of operations and comprehensive income is computed by dividing the net income applicable to Helix 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 and comprehensive income are as follows (in thousands):

	Three Months Ended				Three Months Ended
	June 30, 2012				June 30, 2011
	Income			Shares	Income			Shares
Basic:
Net income applicable to Helix common shareholders	$	44,641			$	41,313
Less: Undistributed net income allocable to participating securities		(449	)			(514	)
Net income applicable to Helix common shareholders	$	44,192		104,563	$	40,799		104,673

	Three Months Ended				Three Months Ended
	June 30, 2012				June 30, 2011
	Income		Shares		Income		Shares
Diluted:
Net income per common share - Basic	$	44,192		104,563	$	40,799		104,673
Effect of dilutive securities:
Stock options	—			118	—			106
Undistributed earnings reallocated to participating securities		2	—			3	—
2025 Notes and 2032 Notes	—		—		—		—
Convertible preferred stock		10		361		10		361
Net income per common share - Diluted	$	44,204		105,042	$	40,812		105,140

	Six Months Ended				Six Months Ended
	June 30, 2012				June 30, 2011
	Income			Shares	Income			Shares
Basic:
Net income applicable to Helix common shareholders	$	110,368			$	67,170
Less: Undistributed net income allocable to participating securities		(1,111	)			(850	)
Net income applicable to Helix common shareholders	$	109,257		104,547	$	66,320		104,573

	Six Months Ended				Six Months Ended
	June 30, 2012				June 30, 2011
	Income		Shares		Income		Shares
Diluted:
Net income per common share - Basic	$	109,257		104,547	$	66,320		104,573
Effect of dilutive securities:
Stock options	—			104	—			90
Undistributed earnings reallocated to participating securities		5	—			4	—
2025 Notes and 2032 Notes	—		—		—		—
Convertible preferred stock		20		361		20		361
Net income per common share - Diluted	$	109,282		105,012	$	66,344		105,024

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- or six-month periods ended June 30, 2012 and 2011. Also, no diluted shares were included for our 2032 Notes for the three- or six-month periods ended June 30, 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.

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Note 11 – Employee Benefit 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”). At the Annual Meeting of Shareholders on May 9, 2012, the shareholders approved an amendment and restatement to the 2005 Incentive Plan to: (i) authorize 4.3 million additional shares for issuance pursuant to our equity incentive compensation strategy, (ii) authorize incentive stock options, stock appreciation rights, cash awards and performance awards to be made pursuant to the amended and restated 2005 Incentive Plan, and (iii) include performance criteria for awards that may be made contingent upon the achievement of one or more performance measures, as well as limits on individual awards, in accordance with the requirements for performance-based compensation under Section 162(m) of the Internal Revenue Code. As of June 30, 2012, there were 6.7 million shares available for issuance under the amended and restated 2005 Incentive Plan, which includes a maximum of 2.0 million shares that may be granted as incentive stock options. There were no stock option grants in the three- and six-month periods ended June 30, 2012 and 2011. During the six-month period ended June 30, 2012, the following grants of share-based awards (restricted shares, restricted stock units and performance share units (“PSUs") were made to executive officers, selected management employees and non-employee members of the board of directors under the amended and restated 2005 incentive plan:

Date of Grant	Shares		Grant Date Fair Value Per Share		Vesting Period

January 3, 2012		272,153	$	15.80	33% per year over three years
January 3, 2012 (1)		132,910		23.68	100% on January 1, 2015
January 3, 2012		1,958		15.80	100% on January 1, 2014
April 1, 2012		1,879		17.80	100% on January 1, 2014

(1)

Reflects the grant of PSUs to certain of our executive officers. The estimated fair value of the PSUs on grant date was determined using a Monte Carlo simulation model. The PSUs provide for an award based on the performance of our common stock over a three-year period with the maximum award being 200% of the original awarded PSUs and the minimum amount being zero. The vested PSUs will be settled in an equivalent number of shares of our common stock unless the Compensation Committee of our Board of Directors elects to pay in cash. See Note 12 of 2011 Form 10-K.

Compensation cost is recognized over the respective vesting periods on a straight-line basis. For the three- and six-month periods ended June 30, 2012, $1.8 million and $3.7 million, respectively, were recognized as compensation expense related to share-based awards as compared with $2.0 million and $4.9 million during the three- and six-month periods ended June 30, 2011.

Long-Term Incentive Compensation Plan

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 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 deemed 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 $1.2 million and $3.6 million for the three- and six-month periods ended June 30, 2012, respectively. For the three- and six-month periods ended June 30, 2011, total compensation under the 2009 LTI Plan totaled $1.6 million and $4.6 million, respectively. The liability balance under the 2009 LTI Plan was $8.0 million at June 30, 2012 and $9.9 million at December 31, 2011, including $7.3 million at June 30, 2012 and $8.5 million at December 31, 2011 associated with the variable portion of the 2009 LTI plan.

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Employee Stock Purchase Plan

At the May 2012 Annual Meeting of Shareholders, the shareholders approved the Helix Energy Solutions Group, Inc. Employee Stock Purchase Plan (the “ESPP”). The ESPP has 1.5 million shares authorized for issuance. Eligible employees who participate in the ESPP may purchase shares of our common stock through payroll deductions on an after tax basis over a four-month period beginning on January 1, May 1, and September 1 of each year during the term of the ESPP. The first of such purchase periods begins on September 1, 2012. The purchase price for the stock will be 85% of the lesser of (1) its fair market value on the first trading day of the purchase period or (2) its fair market value on the last trading day of the purchase period. A participant may elect to make contributions each pay period in an amount not less than 1% of his or her compensation, subject to an annual limitation equal to 10% of his or her compensation or such other amount established by the Compensation Committee of our Board of Directors (which administers the ESPP). No participant, however, may purchase more than 10,000 shares of our common stock during any purchase period nor may a participant purchase shares during a calendar year in excess of the “maximum share limitation.” The maximum share limitation is the number of shares of our common stock derived by dividing $25,000 by the fair market value (equal to the closing price per share of our common stock on the New York Stock Exchange on the applicable date) of the common stock determined as of the first trading day of the purchase period.

For more information regarding our employee benefit plans, including our stock-based compensation plans and our 2009 LTI Plan, see Note 12 of our 2011 Form 10-K.

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. All material intercompany transactions between the segments have been eliminated.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
	(in thousands)
Revenues –
Contracting Services	$	209,557		$	171,353		$	454,101		$	302,890
Production Facilities		19,963			20,545			39,985			36,115
Oil and Gas		149,933			172,458			328,018			341,317
Intercompany elimination		(32,059	)		(26,037	)		(66,783	)		(50,396	)
Total	$	347,394		$	338,319		$	755,321		$	629,926

Income (loss) from operations –
Contracting Services	$	19,223		$	30,565		$	78,347		$	33,831
Production Facilities		9,882			11,920			19,931			17,876
Oil and Gas		60,442			43,064			137,384			96,304
Corporate		(11,158	)		(9,112	)		(22,056	)		(19,553	)
Intercompany elimination		98			(19	)		(2,922	)		71
Total	$	78,487		$	76,418		$	210,684		$	128,529

Equity in earnings of equity investments	$	5,748		$	5,887		$	6,155		$	11,537

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Intercompany segment revenues during the three- and six-month periods ended June 30, 2012 and 2011 were as follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2012		2011		2012		2011
	(in thousands)

Contracting Services		20,538		14,295		43,739		27,164
Production Facilities		11,521		11,742		23,044		23,232
Total	$	32,059	$	26,037	$	66,783	$	50,396

Intercompany segment profits (losses) during the three- and six-month periods ended June 30, 2012 and 2011 were as follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
	(in thousands)

Contracting Services		(55	)		63			3,009			39
Production Facilities		(43	)		(44	)		(87	)		(110	)
Total	$	(98	)	$	19		$	2,922		$	(71	)

Segment assets are comprised of all assets attributable to the reportable segment. The following table reflects total assets by reportable segment as of June 30, 2012 and December 31, 2011:

	June 30,		December 31,
	2012		2011
	(in thousands)

Contracting Services	$	2,176,796	$	2,006,065
Production Facilities		534,714		534,776
Oil and Gas		977,295		1,041,506
Total	$	3,688,805	$	3,582,347

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”), 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 $2.2 million and $3.9 million for the three- and six-month periods ended June 30, 2012, respectively, and $2.7 million and $5.1 million for the three- and six-month periods ended June 30, 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.

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Note 14 – Commitments and Contingencies and Other Matters

Commitments

Expansion of Well Intervention Fleet

In March 2012, we executed a shipyard contract for the construction of a newbuild semisubmersible well intervention vessel. This $386.5 million shipyard contract represents the majority of the expected costs associated with the construction of 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, the payments will be made in fixed amounts on contractually scheduled dates. The next $58.0 million payment is scheduled to be made in December 2012.

On July 23, 2012, we entered into a definitive agreement to acquire the Discoverer 534 drillship from a subsidiary of Transocean Ltd. for $85 million. The transaction is expected to close in August 2012. We will then convert the drillship into a well intervention vessel in Singapore.

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 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 related 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.

Contracting Services Impairment

As our subsea construction vessel, the Intrepid, did not have work for the immediately foreseeable future, we deferred the vessel’s scheduled regulatory dry dock and are currently preparing the vessel to be placed in cold-stack mode for at least the remainder of 2012. In consideration of these developments, we concluded the vessel was impaired and we recorded a $14.6 million charge to reduce the carrying cost of the Intrepid to its estimated fair value at June 30, 2012.

Litigation

On May 12, 2012, a shareholder derivative lawsuit styled Mark Lucas v. Owen Kratz, et al. was filed in the 270th Judicial District in the District Court of Harris County, Texas. In the suit, the plaintiff makes claims against our Board of Directors, certain of our former directors, certain of our current and former executive officers and the independent compensation consultant to the Compensation Committee of our board of directors, for breaches of the fiduciary duties of candor, good faith and loyalty, unjust enrichment and aiding and abetting the alleged breaches of fiduciary duty relating to the long-term equity awards granted in 2010 to certain of our executive officers. This case is essentially a “copycat” complaint asserting similar causes of action arising out of the same facts as set forth in the federal action, City of Sterling Heights Police & Fire Retirement System v. Owen Kratz, et al., a description of which is included in our 2011 Form

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10-K. We have filed a motion to stay, motion to dismiss, special exceptions, plea to the jurisdiction and an original answer asserting that: (i) the suit should be stayed in favor of a first-filed federal derivative case; (ii) the plaintiff has not pled specific facts showing wrongful refusal of demand; (iii) the plaintiff has not demonstrated he continually owned shares during the complained of action; and (iv) the plaintiff has not stated a claim. The plaintiff is generally demanding disgorgement of the excessive compensation, restraint on the disposition/exercise of the alleged improperly awarded equity, implementation of additional internal controls, and attorney’s fees and costs of litigation.

On June 20, 2012, we were named as a defendant in a claim filed in the Western District of Virginia by an individual, Charles Adams, who claims that he invented the capping stack used to plug the BP Gulf of Mexico Macondo well. Mr. Adams alleges that we obtained some drawings and other intellectual property from an engineer named Richard Haun and/or Mr. Haun’s company, Equipment Design & Manufacturing Group, LLC, d/b/a ED&M Deepwater Engineering (collectively “ED&M”, and also a named defendant), and that we and ED&M then engaged Cameron International Corporation (which is also a named defendant) to manufacture the capping stack and realize the Plaintiff’s invention. Mr. Adams seeks at least $150 million in compensatory damages, treble damages under a Virginia statute, punitive damages, attorney’s fees and costs, as well as temporary and permanent injunctions against the defendants in relation to his claimed intellectual property. We believe that we were mistakenly named in this lawsuit because, among other things, we did not invent, manufacture or provide the capping stack that was used to plug the Macondo well, and although we did have a working relationship with ED&M, that work had nothing to do with the Macondo (or any other) capping stack. In the event it is not dismissed from this lawsuit, we intend to defend this matter vigorously. We do not expect that this matter will have a material adverse effect on our business or financial position, results of operations or cash flows.

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).

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The following table provides additional information related to assets and liabilities measured at fair value on a recurring basis at June 30, 2012 (in thousands):

	Level 1		Level 2 (1)		Level 3		Total		Valuation Technique
Assets:
Natural gas contracts	$	—	$	10,902	$	—	$	10,902	(c)
Oil contracts		—		21,770		—		21,770	(c)

Liabilities:
Oil contracts		—		6,383		—		6,383	(c)
Fair value of long term debt (2)		1,133,037		123,382		—		1,256,419	(a), (b)
Interest rate swaps		—		376		—		376	(c)
Foreign currency forwards		—		44		—		44	(c)
Total net liability	$	1,133,037	$	97,513	$	—	$	1,230,550

(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 June 30, 2012 is as follows:

	Fair Value		Carrying Value

Term Loans (mature July 2015)	$	376,630	$	377,000
Revolving Credit Facility (matures July 2015)		100,000		100,000
2025 Notes (mature March 2025)		158,824		157,830	(a)
2032 Notes (mature March 2032)		207,500		200,000	(b)
Senior Unsecured Notes (mature January 2016)		290,083		274,960
MARAD Debt (matures February 2027) (c)		123,382		107,757
Total	$	1,256,419	$	1,217,547

a.	Amount excludes the related unamortized debt discount of $2.5 million.

b.	Amount excludes the related unamortized debt discount of $34.2 million.

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 rates 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

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(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 June 30, 2012, we had the following volumes under derivative contracts related to our oil and gas producing activities totaling approximately 4.3 million barrels of oil and 11.6 Bcf of natural gas:

Production Period	Instrument Type	Average Monthly Volumes	Weighted Average Price (1)
Crude Oil:			(per barrel)
July 2012 — December 2012	Collar	75.0 MBbl	$ 96.67 — $118.57 (2)
July 2012 — December 2012	Collar	99.1 MBbl	$ 99.67 — $118.42
July 2012 — December 2012	Swap	96.6 MBbl	$92.52
January 2013 — December 2013	Swap	88.9 MBbl	$95.28
January 2013 — December 2013	Collar	133.3 MBbl	$ 98.44 — $115.85

Natural Gas:			(per Mcf)
July 2012 — December 2012	Swap	777.5 Mmcf	$4.29
July 2012 — December 2012	Collar	156.7 Mmcf	$4.75 — $5.09
January 2013 — December 2013	Swap	500.0 Mmcf	$4.09

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

(2)	This contract is priced using NYMEX West Texas Intermediate for crude oil.

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 November 2012.

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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, 2012 and December 31, 2011.

Derivatives designated as hedging instruments are as follows (in thousands):

	As of June 30, 2012			As of December 31, 2011
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Asset Derivatives:
Natural gas contracts	Other current assets	$	9,663	Other current assets	$	12,957
Oil contracts	Other current assets		16,033	Other current assets		8,567
Oil contracts	Other assets		5,737	Other assets		—
Natural gas contracts	Other assets		1,239	Other assets		857
Interest rate swaps	Other assets		—	Other assets		327
		$	32,672		$	22,708

	As of June 30, 2012			As of December 31, 2011
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Liability Derivatives:
Oil contracts	Accrued liabilities	$	5,324	Accrued liabilities	$	886
Interest rate swaps	Accrued liabilities		317	Accrued liabilities		202
Oil contracts	Other long-term liabilities		1,059	Other long-term liabilities		1,711
Interest rate swaps	Other long-term liabilities		59	Other long-term liabilities		—
		$	6,759		$	2,799

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

	As of June 30, 2012			As of December 31, 2011
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Asset Derivatives:
Foreign exchange forwards	Other current assets	$	—	Other current assets	$	55
		$	—		$	55

	As of June 30, 2012			As of December 31, 2011
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Liability Derivatives:
Foreign exchange forwards	Accrued liabilities	$	44	Accrued liabilities	$	159
		$	44		$	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- and six-month periods ended June 30, 2012 and 2011. The hedge ineffectiveness related to some of our crude oil contracts totaled $10.1 million and $7.7 million for the three- and six-month periods ended June 30, 2012. The amount of any ineffectiveness associated with our oil contracts was immaterial for the three- and six-month periods ended June 30, 2011. These amounts are reflected as a separate line item titled “Ineffectiveness on oil and gas commodity derivative contracts” in the accompanying condensed consolidated statements of operations and comprehensive income. Ineffectiveness associated with our interest rate swaps was immaterial for all periods presented. At June 30, 2012, most of our remaining unrealized gains (losses) related to our derivative contracts are expected to be reclassified into earnings within the next 12 months, including $9.1 million for our oil and natural gas contracts and $(0.2) million related to our interest swap contracts. 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.

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		Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)
		Three Months Ended June 30,					Six Months Ended June 30,
		2012			2011		2012			2011
		(in thousands)

Oil and natural gas commodity contracts	$	12,759		$	20,720	$	(796	)	$	9,942
Interest rate swaps		(79	)		250		(326	)		461
	$	12,680		$	20,970	$	(1,122	)	$	10,403


				Gain (Loss) Reclassified from Accumulated OCI
				into Income
	Location of Gain (Loss)			(Effective Portion)
	Reclassified from			Three Months Ended						Six Months Ended
	Accumulated OCI into Income			June 30,						June 30,
	(Effective Portion)			2012			2011			2012			2011
			(in thousands)

Oil and natural gas commodity contracts	Oil and gas revenue	$		8,023		$	(11,860	)	$	8,132		$	(18,185	)
Interest rate swaps	Net interest expense			(120	)		(591	)		(313	)		(1,071	)
		$		7,903		$	(12,451	)