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Accounts receivable - Trade, net of allowance for uncollectible accounts of $5,152 and $4,000, respectively

$ 437,100

$ 546,463

$ 391,084

152,233

147,899

Costs in excess of billing

26,992

24,338

6,848

13,037

96,934

93,584

84,000

118,921

804,107

944,242

Less accumulated depreciation

2,051,796

1,815,012

(565,921)

(355,343)

1,485,875

1,459,669

1,452,842

Other assets:

Equity investments

167,599

175,656

Goodwill

62,935

62,215

62,494

^[1]

49,837

35,166

816,227

905,399

3,386,580

3,582,347

3,592,020

Current liabilities:

92,398

73,919

161,514

146,112

1,293

16,607

7,877

182,527

166,975

453,046

396,176

1,002,621

1,147,444

Other non-current liabilities

359,237

417,610

5,025

9,368

147,237

161,208

1,967,166

2,131,806

Commitments and contingencies

1,000

Shareholders' equity:

Common stock, no par, 240,000 shares authorized, 105,763 and 105,530 shares issued, respectively

932,742

908,776

Retained earnings

476,310

522,644

Accumulated other comprehensive loss

(15,667)

(10,017)

Total controlling interest shareholders' equity

1,393,385

1,421,403

Noncontrolling interests

26,029

28,138

1,419,414

1,449,541

$ 1,285,644

$ 1,427,462

$ 3,386,580

$ 3,582,347

[1]	In 2010, we fully impaired $16.7 million of goodwill associated with our Australian well intervention subsidiary (“WOSEA”) (see below).

Consolidated Balance Sheets - USD ($)
$ in Thousands

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Current assets:

Accounts receivable - Trade, net of allowance for uncollectible accounts of $5,152 and $4,000, respectively

$ 437,100

$ 546,463

$ 391,084

152,233

147,899

Costs in excess of billing

26,992

24,338

6,848

13,037

96,934

93,584

84,000

118,921

804,107

944,242

Less accumulated depreciation

2,051,796

1,815,012

(565,921)

(355,343)

1,485,875

1,459,669

1,452,842

Other assets:

Equity investments

167,599

175,656

Goodwill

62,935

62,215

62,494

^[1]

49,837

35,166

816,227

905,399

3,386,580

3,582,347

3,592,020

Current liabilities:

92,398

73,919

161,514

146,112

1,293

16,607

7,877

182,527

166,975

453,046

396,176

1,002,621

1,147,444

Other non-current liabilities

359,237

417,610

5,025

9,368

147,237

161,208

1,967,166

2,131,806

Commitments and contingencies

1,000

Shareholders' equity:

Common stock, no par, 240,000 shares authorized, 105,763 and 105,530 shares issued, respectively

932,742

908,776

Retained earnings

476,310

522,644

Accumulated other comprehensive loss

(15,667)

(10,017)

Total controlling interest shareholders' equity

1,393,385

1,421,403

Noncontrolling interests

26,029

28,138

1,419,414

1,449,541

$ 1,285,644

$ 1,427,462

Significant Accounting Policies

$ 3,386,580

$ 3,582,347

[1]	In 2010, we fully impaired $16.7 million of goodwill associated with our Australian well intervention subsidiary (“WOSEA”) (see below).

Consolidated Balance Sheets (Parenthetical) - USD ($) shares in Thousands, $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Current assets:
Allowance for uncollectible accounts	$ 5,152	$ 4,000
Shareholders' equity:
Common stock, par value
Common stock, shares authorized	240,000	240,000
Common stock, shares issued	105,763	105,530

Consolidated Statements Of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Net revenues:
Net revenues	$ 846,109	$ 702,000	$ 774,469
Cost of sales:
Cost of sales	619,059	545,753	605,575
Impairments	177,135	6,564	4,077
Total cost of sales	796,194	552,317	609,652
Gross profit	49,915	149,683	164,817
Goodwill impairment			(16,743)
Non-hedge loss on commodity derivative contracts	(10,507)
Gain (loss) on sale of assets, net	(13,476)	(6)	9,118
Selling, general and administrative expenses	(94,415)	(86,637)	(106,113)
Income (loss) from operations	(68,483)	63,040	51,079
Equity in earnings of investments	8,434	22,215	19,469
Other than temporary loss on equity investments		(10,563)	(2,240)
Net interest expense	(48,160)	(70,181)	(65,589)
Loss on early extinguishment of long term debt	(17,127)	(2,354)
Other expense, net	(625)	(1,107)	(1,049)
Income (loss) before income taxes	(125,961)	1,050	1,670
Income tax provision (benefit)	(59,158)	(36,806)	19,166
Income (loss) from continuing operations	(66,803)	37,856	(17,496)
Income (loss) from discontinued operations, net of tax	23,684	95,221	(106,657)
Net income (loss), including noncontrolling interests	(43,119)	133,077	(124,153)
Less net income applicable to noncontrolling interests	(3,178)	(3,098)	(2,835)
Net income (loss) applicable to Helix	(46,297)	129,979	(126,988)
Preferred stock dividends	(37)	(40)	(114)
Net income (loss) applicable to Helix common shareholders	$ (46,334)	$ 129,939	$ (127,102)
Basic earnings (loss) per share of common stock:
Continuing operations	$ (0.67)	$ 0.33	$ (0.19)
Discontinued operations	0.23	0.90	(1.03)
Net income (loss) per common share	(0.44)	1.23	(1.22)
Diluted earnings (loss) per share of common stock:
Continuing operations	(0.67)	0.33	(0.19)
Discontinued operations	0.23	0.90	(1.03)
Net income (loss) per common share	$ (0.44)	$ 1.23	$ (1.22)
Weighted average common shares outstanding:
Basic	104,449	104,528	103,857
Diluted	104,449	104,953	103,857

Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Consolidated Statements of Comprehensive Income [Abstract]
Net income (loss), including noncontrolling interests	$ (43,119)	$ 133,077	$ (124,153)
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Foreign currency translation gain	8,368	(1,118)	(11,108)
Income taxes on foreign currency translation gain	(1,077)	116	1,103
Foreign currency translation gain, net of tax	7,291	(1,002)	(10,005)
Unrealized gain (loss) on hedges arising during the period	(33,078)	69,889	(35,571)
Reclassification adjustments for (gain) loss included in net income	2,661	(23,669)	23,726
Reclassification adjustments for (gain) loss from derivatives de-designated as cash flow hedges included in net income	10,507
Income taxes on unrealized gain (loss) on hedges	6,969	(16,177)	4,146
Unrealized gain (loss) on hedges, net	(12,941)	30,043	(7,699)
Unrealized gain on investment held for sale			1,220
Income taxes on unrealized gain on investment held for sale			(333)
Unrealized gain on investment held for sale, net of tax			887
Other comprehensive income (loss), net of taxes	(5,650)	29,041	(16,817)
Comprehensive income (loss)	(48,769)	162,118	(140,970)
Less comprehensive income applicable to noncontrolling interests	(3,178)	(3,098)	(2,835)
Comprehensive income (loss) applicable to Helix	(51,947)	159,020	(143,805)
Preferred stock dividends	(37)	(40)	(114)
Comprehensive income (loss) applicable to Helix common shareholders	$ (51,984)	$ 158,980	$ (143,919)

Consolidated Statements Of Shareholders' Equity - USD ($) shares in Thousands, $ in Thousands	Common Stock [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Parent [Member]	Noncontrolling Interest [Member]	Total
Balance at Dec. 31, 2009	$ 907,691	$ 519,807	$ (22,241)	$ 1,405,257	$ 22,205	$ 1,427,462
Common Stock, Shares, Outstanding, Beginning Balance at Dec. 31, 2009	104,281
Net income (loss), including noncontrolling interests		(126,988)		(126,988)	2,835	(124,153)
Foreign currency translation adjustments			(10,005)	(10,005)		(10,005)
Unrealized gain (loss) on hedges, net			(7,699)	(7,699)		(7,699)
Unrealized loss on investment available for sale			887	887		887
Convertible preferred stock dividends		(114)		(114)		(114)
Convertible preferred stock conversion, value (Note 10)	$ 5,000			5,000		5,000
Convertible preferred stock conversion, shares	1,807
Stock compensation expense	$ 9,217			9,217		9,217
Stock repurchase, value	$ (11,680)			(11,680)		(11,680)
Stock repurchase, shares	(1,016)
Activity in company stock plans, net and other, value	$ 674			674		674
Activity in company stock plans, net and other, shares	520
Excess tax from stock-based compensation	$ (3,945)			(3,945)		(3,945)
Balance at Dec. 31, 2010	$ 906,957	392,705	(39,058)	1,260,604	25,040	1,285,644
Common Stock, Shares, Outstanding, Ending Balance at Dec. 31, 2010	105,592
Net income (loss), including noncontrolling interests		129,979		129,979	3,098	133,077
Foreign currency translation adjustments			(1,002)	(1,002)		(1,002)
Unrealized gain (loss) on hedges, net			30,043	30,043		30,043
Convertible preferred stock dividends		(40)		(40)		(40)
Stock compensation expense	$ 8,418			8,418		8,418
Stock repurchase, value	$ (6,502)			(6,502)		(6,502)
Stock repurchase, shares	(497)
Activity in company stock plans, net and other, value	$ 916			916		916
Activity in company stock plans, net and other, shares	435
Excess tax from stock-based compensation	$ (1,013)			(1,013)		(1,013)
Balance at Dec. 31, 2011	$ 908,776	522,644	(10,017)	1,421,403	28,138	1,449,541
Common Stock, Shares, Outstanding, Ending Balance at Dec. 31, 2011	105,530
Net income (loss), including noncontrolling interests		(46,297)		(46,297)	3,178	(43,119)
Foreign currency translation adjustments			7,291	7,291		7,291
Unrealized gain (loss) on hedges, net			(12,941)	(12,941)		(12,941)
Dividend payment					(5,287)	(5,287)
Equity component of debt discount on Convertible Senior Note due 2032	$ 22,419			22,419		22,419
Convertible preferred stock dividends		(37)		(37)		(37)
Convertible preferred stock conversion, value (Note 10)	$ 1,000			1,000		1,000
Convertible preferred stock conversion, shares	362
Stock compensation expense	$ 7,361			7,361		7,361
Stock repurchase, value	$ (6,415)			(6,415)		(6,415)
Stock repurchase, shares	(405)
Activity in company stock plans, net and other, value	$ 787			787		787
Activity in company stock plans, net and other, shares	276
Excess tax from stock-based compensation	$ (1,186)			(1,186)		(1,186)
Balance at Dec. 31, 2012	$ 932,742	$ 476,310	$ (15,667)	$ 1,393,385	$ 26,029	$ 1,419,414
Common Stock, Shares, Outstanding, Ending Balance at Dec. 31, 2012	105,763

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Cash flows from operating activities:
Net income, including noncontrolling interests	$ (43,119)	$ 133,077	$ (124,153)
Adjustments to reconcile net income (loss), including noncontrolling interests to net cash provided by operating activities
Income (loss) from discontinued operations, net of tax	(23,684)	(95,221)	106,657
Depreciation and amortization	97,201	91,188	81,878
Asset impairment charge and dry hole expense	177,135	6,564	4,077
Goodwill impairment			16,743
Amortization of deferred financing costs	9,086	8,910	7,703
Stock-based compensation expense	7,627	6,973	7,475
Amortization of debt discount	9,729	8,973	8,409
Deferred income taxes	(69,584)	(4,188)	(46,836)
Excess tax from stock-based compensation	1,186	1,013	3,945
Gain on investment in Cal Dive common stock		(753)
Loss on sale of assets, net	13,476	6	(9,118)
Loss on early extinguishment of debt	17,127	2,354
Other than temporary loss on equity investments		10,563	2,240
Unrealized gain and ineffectiveness on derivative contracts, net	(250)	382	1,568
Changes in operating assets and liabilities:
Accounts receivable, net	(3,652)	(30,491)	(29,727)
Other current assets	(10,434)	18,783	(2,088)
Income tax payable	16,812	(6,472)	(214)
Accounts payable and accrued liabilities	73,448	23,191	47,992
Oil and gas asset retirement costs	(37,970)	(4,907)
Other noncurrent, net	(24,442)	(231)	(5,607)
Net cash provided by operating activities	176,068	182,658	71,372
Net cash provided by discontinued operations	276,430	384,498	260,082
Net cash provided by (used in) operating activities	452,498	567,156	331,454
Cash flows from investing activities:
Capital expenditures	(323,039)	(100,154)	(122,218)
Distributions from equity investments, net	7,797	1,266	2,286
Proceeds from sale of assets	19,530		6,042
Proceeds from insurance reimbursement			7,020
Proceeds from sale of Cal Dive common stock		3,588
Net cash used in investing activities	(295,712)	(95,300)	(106,870)
Net cash used in discontinued operations	(120,057)	(87,017)	(74,686)
Net cash used in investing activities	(415,769)	(182,317)	(181,556)
Cash flows from financing activities:
Early extinguishment of Senior Unsecured Notes	(209,500)	(77,394)
Borrowing 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	(298,288)
Proceeds from Term Loan A	100,000
Repayment of Term Loan	(12,569)	(130,691)	(4,326)
Repayment of MARAD borrowings	(4,877)	(4,645)	(4,424)
Deferred financing costs	(7,580)	(9,311)	(2,947)
Distributions to noncontrolling interest	(5,287)
Repurchases of common stock	(7,197)	(7,604)	(11,680)
Excess tax benefit from stock-based compensation	(1,186)	(1,013)	(3,945)
Exercise of stock options, net and other	1,252	763	(1,957)
Net cash provided by (used in) financing activities	(145,232)	(229,895)	(29,279)
Effect of exchange rate changes on cash and cash equivalents	(860)	436	(207)
Net increase (decrease) in cash and cash equivalents	(109,363)	155,380	120,412
Cash and cash equivalents:
Balance, beginning of year	546,465	391,085	270,673
Balance, end of year	437,102	546,465	391,085
Less cash from discontinued operations, end of year	(2)	(2)	(1)
Cash from continuing operations, end of year	$ 437,100	$ 546,463	$ 391,084

Organization	12 Months Ended
Organization	Dec. 31, 2012
Organization [Abstract]
Organization	Note 1 — Organization Effective March 6, 2006, we changed our name from Cal Dive International, Inc. to Helix Energy Solutions Group, Inc. (“Helix” or the “Company”). Unless the context indicates otherwise, the terms “we,” “us” and “our” in this Annual Report refer collectively to Helix and its subsidiaries. Until June 2009, Cal Dive International, Inc. (collectively with its subsidiaries referred to as “Cal Dive” or “CDI”) was a majority-owned subsidiary of Helix. We sold substantially all of our remaining ownership interests in Cal Dive during 2009 (Note 2). 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 operations. Our contracting services operations are located primarily in the Gulf of Mexico, North Sea, Asia Pacific, and West Africa regions. In February 2013, we sold Energy Resource Technology GOM, Inc. (“ERT”), a former wholly-owned U.S. subsidiary that conducted our oil and gas operations in the Gulf of Mexico. Our former Oil and Gas segment was involved in prospect generation, exploration, development and production activities in the Gulf of Mexico. Contracting Services Operations We seek to provide services and methodologies that we believe are critical to developing offshore reservoirs and maximizing production economics. Our “life of field” services are segregated into four disciplines: well intervention, 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 segment includes well intervention, robotics and subsea construction operations (see Note 2 for disclosures regarding the planned dispositions of our subsea construction vessels and related assets). Our Production Facilities business includes our majority ownership of the Helix Producer I (“HP I”) vessel as well as our equity investments in Deepwater Gateway, L.L.C. (“Deepwater Gateway”) and Independence Hub, LLC (“Independence Hub”) (Note 5). 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 to certain CGA participants who have executed utilization agreements with us. In addition to the agreement with CGA, we currently have separate utilization agreements with 24 CGA participant member companies. These agreements specify the day rates to be charged should the HFRS be deployed in connection with a well control incident. Recently, this group of operators formed HWCG LLC to perform the same functions as CGA with respect to the HFRS. The retainer fee for the HFRS became effective April 1, 2011. We anticipate that a new contract covering the HFRS will be signed in the first quarter of 2013 to provide for a four-year term commencing April 1, 2013. Discontinued Operations In December 2012, we announced a definitive agreement for the sale of ERT. On February 6, 2013, we sold ERT for $620 million plus contingent consideration in the form of overriding royalty interests in the Wang well and certain other future exploration prospects. As a result, we have presented the assets and liabilities included in the sale of ERT and the historical operating results of our former Oil and Gas segment as discontinued operations in the accompanying consolidated financial statements. See Note 3 for additional information regarding our discontinued oil and gas operations.

Summary Of Significant Accounting Policies

12 Months Ended

Dec. 31, 2012

Accounting Policies [Abstract]

Note 2 — Summary of Significant Accounting Policies

Principles of Consolidation

Our consolidated financial statements include the accounts of majority-owned subsidiaries. The equity method is used to account for investments in affiliates in which we do not have majority ownership, but have the ability to exert significant influence. We account for our Deepwater Gateway, Independence Hub and former Australian joint venture investments under the equity method of accounting. Noncontrolling interests represent the minority shareholders’ proportionate share of the equity in Kommandor LLC. All material intercompany accounts and transactions have been eliminated. Certain reclassifications were made to previously-reported amounts in the consolidated financial statements and notes thereto to make them consistent with the current presentation format. The most significant of these reclassifications are associated with our discontinued oil and gas operations. As noted in Note 1, ERT qualified as discontinued operations in December 2012 following the announcement of a definitive agreement for the sale of ERT. Accordingly, all operations and financial positions related to ERT have been presented as discontinued operations even if they did not qualify as a discontinued operation in that period.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash and Cash Equivalents

Cash and cash equivalents are highly liquid financial instruments with original maturities of three months or less. They are carried at cost plus accrued interest, which approximates fair value.

Statement of Cash Flow Information

The following table provides supplemental cash flow information for the periods stated (in thousands):


		Year Ended December 31,
		2012		2011		2010

Interest paid, net of interest capitalized	$	68,735	$	81,000	$	68,534
Income taxes paid	$	43,111	$	11,216	$	10,071

Total non-cash investing activities for the years ended December 31, 2012, 2011 and 2010 included $51.1 million, $26.1 million and $21.9 million, respectively, of accruals for property and equipment capital expenditures.

Accounts Receivable and Allowance for Uncollectible Accounts

Accounts receivable are stated at the historical carrying amount net of write-offs and allowance for uncollectible accounts. The amount of our net accounts receivable approximates fair value. We establish an allowance for uncollectible accounts receivable based on historical experience and any specific customer collection issues that we have identified. Uncollectible accounts receivable are written off when a settlement is reached for an amount that is less than the outstanding historical balance or when we have determined that the balance will not be collected (Note 15).

Property and Equipment

Overview. Property and equipment is recorded at cost. Property and equipment is depreciated on a straight line basis over the estimated useful life of each respective asset. The following is a summary of the gross components of property and equipment (dollars in thousands):


	Estimated Useful Life		2012		2011

ROVs/Vessels	10 to 30 years	$	1,822,642	$	1,616,772
Machinery, equipment, buildings and leasehold improvements	5 to 30 years		229,154		198,240
Total property and equipment		$	2,051,796	$	1,815,012

The cost of repairs and maintenance is charged to expense as incurred, while the cost of improvements is capitalized. The repair and maintenance expenses totaled $38.7 million, $32.3 million and $29.3 million for the years ended December 31, 2012, 2011 and 2010, respectively. Included in machinery, equipment, buildings and leasehold improvements were $18.5 million and $18.1 million of capitalized software costs at December 31, 2012 and 2011, respectively. The total amount charged to expense related to the amortization of these software costs was $2.6 million during each of the years ended December 31, 2012, 2011 and 2010.

Assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value and reported as an impairment charge in the periods in which the determination of the impairment is made. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. Our marine vessels are assessed on a vessel by vessel basis, while our ROVs are grouped and assessed by asset class. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or based on a multiple of operating cash flows validated with historical market transactions of similar assets where possible. The expected future cash flows used for impairment reviews and related fair value calculations are based on judgmental assessments, operating costs, project margins and capital project decisions, considering all available information at the date of review. If an impairment has occurred, we recognize a loss for the difference between the carrying amount and the fair value of the asset.

In 2012, we decided to cease our well intervention operations in Australia. We recorded a $4.6 million impairment charge to reduce our well intervention assets in Australia to their fair value of $5.0 million. In 2011, in association with the reorganization of our Australian well intervention operations, we conducted an impairment assessment of its subsea well intervention equipment, which resulted in a $6.6 million charge to reduce the carrying value of such well intervention equipment to its then estimated fair value. In 2012, as a result of diminished work opportunities for the Intrepid, we placed the vessel in cold-stack mode and later sold the vessel for $14.5 million in cash, which resulted in asset impairment and related loss on disposal charges totaling $28.1 million for the Intrepid. Also in 2012, we entered into an agreement to sell our two remaining pipelay vessels, the Express and the Caesar, and other related pipelay equipment for a total sales price of $238.3 million, of which we have received a $50 million deposit that is only refundable in very limited circumstances. The sales of these vessels are scheduled to close and fund in two stages in 2013 following the completion of each vessel’s existing backlog of work. In connection with the announcement of the sale of our remaining pipelay vessels and related equipment, we recorded an impairment charge of $157.8 million to reduce the carrying cost of the Caesar and other related pipelay equipment to their respective fair values as determined by the definitive sales agreement. We did not record impairments related to our vessels during 2011 and 2010. See Note 3 for disclosure related to the impairment charges associated with certain of our former oil and gas properties.

Assets are classified as held for sale when we have a formalized plan for disposal and those assets meet the held for sale criteria. Assets classified as held for sale are included in other current assets. There were no assets meeting the requirements to be classified as assets held for sale at December 31, 2012 other than assets associated with our discontinued oil and gas operations (Note 3). We had no assets classified as assets held for sale at December 31, 2011.

Interest from external borrowings is capitalized on major projects until the assets are ready for their intended use. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful life of the asset in the same manner as the underlying asset. The total of our interest expense capitalized during each of the three years ended December 31, 2012, 2011 and 2010 was $4.9 million, $1.3 million and $12.5 million, respectively.

Equity Investments

We periodically review our equity investments in Deepwater Gateway and Independence Hub for impairment. Under the equity method of accounting, an impairment loss would be recorded whenever the fair value of an equity investment is determined to be below its carrying amount and the reduction is considered to be other than temporary. In judging “other than temporary,” we would consider the length of time and extent to which the fair value of the investment has been less than the carrying amount of the equity investment, the near-term and long-term operating and financial prospects of the equity company and our longer-term intent of retaining the investment in the entity. We previously invested in an Australian joint venture that engaged in well intervention operations in the Southeast Asia region. We fully impaired our investment in that joint venture and recorded a $10.6 million other than temporary impairment charge in 2011. We exited this Australian joint venture in 2012. See Note 5 for discussion of other than temporary loss amounts recorded in both 2011 and 2010.

Goodwill and Other Intangible Assets

We are required to perform an annual impairment analysis of goodwill. We elected November 1 to be our annual impairment assessment date for goodwill. However, we could be required to evaluate the recoverability of goodwill prior to the annual assessment date if we experience disruption to the business, unexpected significant declines in operating results, divestiture of a significant component of the business, emergence of unanticipated competition, loss of key personnel or a sustained decline in market capitalization. Our goodwill impairment test involves a comparison of the fair value with our carrying amount. The fair value is determined using discounted cash flows and other market-related valuation models. At the time of our annual assessment of goodwill on November 1, 2012 we had two reporting units with goodwill and our impairment analysis.

Goodwill impairment is determined using a two-step process. The first step is to identify if a potential impairment exists by comparing the fair value of the reporting unit with its carrying amount, including goodwill. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered to have a potential impairment and the second step of the impairment test is not necessary. However, if the carrying amount of a reporting unit exceeds its fair value, the second step is performed to determine if goodwill is impaired and to measure the amount of impairment loss to recognize, if any.

The second step compares the implied fair value of goodwill with the carrying amount of goodwill. If the implied fair value of goodwill exceeds the carrying amount, then goodwill is not considered impaired. However, if the carrying amount of goodwill exceeds the implied fair value, an impairment loss is recognized in an amount equal to that excess. The implied fair value of goodwill is determined in the same manner as the amount of goodwill recognized in a business combination (i.e., the fair value of the reporting unit is allocated to all the assets and liabilities, including any unrecognized intangible assets, as if the reporting unit were acquired in a business combination).

We use both the income approach and market approach to estimate the fair value of our reporting units under the first step of our goodwill impairment assessment. Under the income approach, a discounted cash flow analysis is performed requiring us to make various judgmental assumptions about future revenue, operating margins, growth rates and discount rates. These judgmental assumptions are based on our budgets, long-term business plans, economic projections, anticipated future cash flows and market place data. Under the market approach, the fair value of each reporting unit is calculated by applying an average peer total invested capital EBITDA (defined as earnings before interest, income taxes and depreciation and amortization) multiple to the upcoming fiscal year’s forecasted EBITDA for each reporting unit. Judgment is required when selecting peer companies that operate in the same or similar lines of business and are potentially subject to the same economic risks.

In 2011, the Financial Accounting Standards Board (“FASB”) issued an update to simplify goodwill impairment testing by giving an entity the option to first assess certain qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount including goodwill. If an entity determines it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then performing the currently prescribed two-step impairment test is unnecessary. The Company early adopted this standard for its annual goodwill impairment tests in 2011.

All of our remaining goodwill at December 31, 2012 ($62.9 million) was associated with our Contracting Services segment. The reporting units that support the remaining goodwill amounts are strong operationally, and absent any significant downturn in their areas of service, should be able to support their goodwill amounts for the foreseeable future. Based on the current and historical evidence supporting these reporting units’ carrying value being sufficient to maintain their recorded goodwill amounts, we concluded, as allowed under applicable accounting guidance, to forego the quantitative step one impairment analysis. We will continue to monitor the current and future operations of these two reporting units to determine whether or not the quantitative assessment is once again necessary. We will conduct the quantitative test at least every three years with the last such test occurring on November 1, 2010.

The changes in the carrying amount of goodwill are as follows (in thousands):


Balance at December 31, 2010 ⁽¹⁾	$	62,494
Other adjustments ⁽²⁾		(279)
Balance at December 31, 2011		62,215
Other adjustments ⁽²⁾		720
Balance at December 31, 2012	$	62,935

(1) In 2010, we fully impaired $16.7 million of goodwill associated with our Australian well intervention subsidiary (“WOSEA”) (see below).

(2) Reflects foreign currency adjustment for certain amounts of our goodwill.

In 2010, WOSEA placed its main revenue generating asset back in service subsequent to major repairs to this equipment following an incident in which it was damaged. WOSEA also entered into an Australian joint venture in February 2010 (Note 5). Despite these positive developments, in 2010 WOSEA’s operating results were disappointing and its near-term outlook reflected the uncertainties involving the subsea market in the Southeast Asia region, including increased competition and a fragmented market. These factors were considered in our impairment test at November 1, 2010. Based on the results of that evaluation, WOSEA no longer passed its step one test and we concluded that a full write-off of its goodwill ($16.7 million) was required after we determined the fair value of its assets under the step two requirements. This impairment charge is reflected as a separate line item in the accompanying consolidated statement of operations titled “Goodwill impairment.” WOSEA is part of our Contracting Services segment.

At December 31, 2012, our remaining intangible assets, other than goodwill, was $1.7 million ($0.5 million, net of accumulated amortization of $1.2 million) for intellectual property and patented technology related to our well intervention operations. Total amortization expenses for intangible assets was $0.1 million for each of the years ended December 31, 2012, 2011, and 2010. We expect to record approximately $0.1 million of amortization expense related to our remaining unamortized intangible assets for each of the next four years.

Recertification Costs and Deferred Dry Dock Charges

Our contracting services vessels are required by regulation to be recertified after certain periods of time. Recertification costs are incurred while a vessel is in dry dock. In addition, routine repairs and maintenance are performed and at times, major replacements and improvements are performed. We expense routine repairs and maintenance costs as they are incurred. We defer and amortize dry dock and related recertification costs over the length of time for which we expect to receive benefits from the dry dock and related recertification, which is generally 30 months but can be as long as 60 months if the appropriate permitting is obtained. Vessels are typically available to earn revenue for the period between dry dock and related recertification processes. A dry dock and related recertification process typically lasts one to two months, a period during which the vessel is not available to earn revenue. Major replacements and improvements that extend the vessel’s economic useful life or functional operating capability are capitalized and depreciated over the vessel’s remaining economic useful life.

As of December 31, 2012 and 2011, capitalized deferred dry dock charges included within “Other assets, net” in the accompanying consolidated balance sheets (Note 4) totaled $22.7 million and $5.4 million, respectively. The increase in our deferred dry dock costs in 2012 was associated with extended regulatory dry docks of the Q4000, Seawell and Well Enhancer well intervention vessels. During the years ended December 31, 2012, 2011 and 2010, dry dock amortization expense was $8.6 million, $7.6 million and $6.9 million, respectively.

Convertible Preferred Stock

In December 2012, the holder of the remaining $1 million of Convertible Preferred Stock converted it into 361,402 shares of our common stock. We had previously presented the Convertible Preferred Stock below liabilities but not as a component of shareholders’ equity, because we were, under certain instances, required to settle any future conversions in cash. The dividend rate was 4% for 2012, 2011 and 2010. In May 2010, the holder converted $5 million of its Convertible Preferred stock into 1,807,011 shares of our common stock. Our Convertible Preferred Stock was assessed for inclusion in our diluted earnings per share calculation using the if converted method (see “Earnings Per Share”) below.

Revenue Recognition

Revenues from contracting services are derived from contracts, which are both short-term and long-term in duration. Our long-term contracting services contracts are contracts that contain either lump-sum, turnkey provisions or provisions for specific time, material and equipment charges, which are billed in accordance with the terms of such contracts. We recognize revenue as it is earned at estimated collectible amounts. Further, we record revenues net of taxes collected from customers and remitted to governmental authorities.

Unbilled revenue represents revenue attributable to work completed prior to period end that has not yet been invoiced. All amounts included in unbilled revenue at December 31, 2012 and 2011 are expected to be billed and collected within one year.

Dayrate Contracts. Revenues generated from specific time, materials and equipment contracts are generally earned on a dayrate basis and recognized as amounts are earned in accordance with contract terms. In connection with these contracts, we may receive revenues for mobilization of equipment and personnel. Revenues related to mobilization are deferred and recognized over the period in which contracted services are performed using the straight-line method. Incremental costs incurred directly for mobilization of equipment and personnel to the contracted site, which typically consist of materials, supplies and transit costs, are also deferred and recognized over the period in which contracted services are performed using the straight-line method. Our policy to amortize the revenues and costs related to mobilization on a straight-line basis over the estimated contract service period is consistent with the general pace of activity, level of services being provided and dayrates being earned over the service period of the contract. Mobilization costs to move vessels when a contract does not exist are expensed as incurred.

Turnkey Contracts. Revenue on significant turnkey contracts is recognized on the percentage-of-completion method based on the ratio of costs incurred to total estimated costs at completion. In determining whether a contract should be accounted for using the percentage-of-completion method, we consider whether:

	•		the customer provides specifications for the construction of facilities or for the provision of related services;
	•		we can reasonably estimate our progress towards completion and our costs;
	•		the contract includes provisions as to the enforceable rights regarding the goods or services to be provided, consideration to be received, and the manner and terms of payment;
	•		the customer can be expected to satisfy its obligations under the contract; and
	•		we can be expected to perform our contractual obligations.

Under the percentage-of-completion method, we recognize estimated contract revenue based on costs incurred to date as a percentage of total estimated costs. Changes in the expected cost of materials and labor, productivity, scheduling and other factors affect the total estimated costs. Additionally, external factors, including weather and other factors outside of our control, may also affect the progress and estimated cost of a project’s completion and, therefore, the timing of income and revenue recognition. We routinely review estimates related to our contracts and reflect revisions to profitability in earnings on a current basis. If a current estimate of total contract cost indicates an ultimate loss on a contract, we recognize the projected loss in full when it is first determined. We recognize additional contract revenue related to claims when the claim is probable and legally enforceable.

Whenever we have a contract that qualifies as a loss contract, we estimate the future shortfall between our anticipated future revenues and future costs. See Note 13 for information regarding our more significant loss contracts during the three-year period ended December 31, 2012.

Income Taxes

Deferred income taxes are based on the differences between financial reporting and tax bases of assets and liabilities. We utilize the liability method of computing deferred income taxes. The liability method is based on the amount of current and future taxes payable using tax rates and laws in effect at the balance sheet date. Income taxes have been provided based upon the tax laws and rates in the countries in which operations are conducted and income is earned. A valuation allowance for deferred tax assets is recorded when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. We consider the undistributed earnings of our principal non-U.S. subsidiaries to be permanently reinvested.

It is our policy to provide for uncertain tax positions and the related interest and penalties based upon management’s assessment of whether a tax benefit is more likely than not to be sustained upon examination by tax authorities. At December 31, 2012, we believe we have appropriately accounted for any unrecognized tax benefits. To the extent we prevail in matters for which a liability for an unrecognized tax benefit is established or are required to pay amounts in excess of the liability, our effective tax rate in a given financial statement period may be affected.

Foreign Currency

Because we operate in various regions in the world, we conduct a portion of our business in currencies other than the U.S. dollar (primarily with respect to Helix Well Ops (U.K.) Limited (“WOUK”)). The functional currency for WOUK is the applicable local currency (British Pound). Previously, WOSEA also had currency risk as its functional currency was the applicable local currency (Australian Dollar). We ceased operations in Australia in 2012. Results of operations for these subsidiaries are translated into U.S. dollars using average exchange rates during the period. Assets and liabilities of these foreign subsidiaries are translated into U.S. dollars using the exchange rate in effect at December 31, 2012 and 2011 and the resulting translation adjustment, which was an unrealized gain (loss) of $7.3 million and $(1.0) million, respectively, is included in accumulated other comprehensive income (loss), a component of shareholders’ equity. All foreign currency transaction gains and losses are recognized currently in the consolidated statements of operations.

Our foreign currency gains (losses) totaled $(0.5) million in 2012, $(2.1) million in 2011 and $1.9 million in 2010. These realized amounts are exclusive of any unrealized gains or losses from our foreign currency exchange derivative contracts.

Derivative Instruments and Hedging Activities

Our continuing operations are exposed to market risks associated with interest rates and foreign currency exchange rates. Our risk management activities involve the use of derivative financial instruments to hedge the impact of market risk exposure related to variable interest rates and foreign currency exchange rates. All derivatives are reflected in our balance sheet at fair value, unless otherwise noted.

We formally document all relationships between hedging instruments and the related hedged items, as well as our risk management objectives, strategies for undertaking various hedge transactions and our methods for assessing and testing correlation and hedge ineffectiveness. All hedging instruments are linked to the hedged asset, liability, firm commitment or forecasted transaction. We also assess, both at the inception of the hedge and on an on-going basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows of the hedged items. We discontinue hedge accounting if we determine that a derivative is no longer highly effective as a hedge, or it is probable that a hedged transaction will not occur. If hedge accounting is discontinued because it is probable the hedged transaction will not occur, deferred gains or losses on the hedging instruments are recognized in earnings immediately. If the forecasted transaction continues to be probable of occurring, any deferred gains or losses in accumulated other comprehensive income (loss) are amortized to earnings over the remaining period of the original forecasted transaction.

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 or 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.

Interest Rate Risk

As some of our long-term debt has variable interest rates and therefore 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 fair value of an interest rate swap are deferred to the extent the swap is effective. These changes 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, is recognized immediately in earnings within the line titled “Net interest expense.” The amount of ineffectiveness associated with our interest rate swap contracts was immaterial in 2011 and 2010.

Under the terms of our Credit Agreement, we are required to use at a minimum 60% of the after-tax proceeds from the sales of the Caesar, the Express and ERT to make payments to reduce our Term Loan debt and borrowings under the Revolving Credit Facility. Because it was probable that we would pay off the Term Loan debt before the expiration of our interest rate swaps, we concluded that the swaps no longer qualified as cash flow hedges in December 2012. At December 31, 2012, we recorded losses of approximately $0.6 million ($0.4 million net of tax) to reflect the mark-to-market adjustments for changes in the fair values of the interest rate swaps. We settled all of our remaining interest rate swap contracts for $0.6 million in February 2013.

Foreign Currency Exchange Rate Risk

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 that are denominated in British pounds. The aggregate fair value of the foreign currency forwards was a net asset of $0.1 million at December 31, 2012 and a net liability of $0.1 million at December 31, 2011. All of our remaining foreign exchange contracts are not accounted for as hedge contracts and changes in their fair value are being marked-to-market each reporting period. We recorded gains (losses) totaling $0.4 million in 2012, $0.2 million in 2011 and $(2.6) million in 2010 associated with foreign exchange contracts not qualifying for hedge accounting.

In January 2013, we entered into foreign currency exchange contracts to hedge the foreign currency exposure to potential variability in cash flows associated with Grand Canyon charter payments ($104.6 million) denominated in Norwegian Kroner (NOK591.3 million), through September 2017. These contracts currently qualify for hedge accounting treatment.

See Note 17 for more information regarding the accounting for our derivative contracts including our commodity contracts associated with ERT.

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 consolidated statements of operations 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 consolidated statements of operations for the years ended December 31, 2012, 2011 and 2010 are as follows (in thousands):


		Year Ended December 31,
		2012			2011			2010
		Income	Shares		Income	Shares		Income	Shares
Basic:
Net income (loss) applicable to Helix common shareholders	$	(46,334)		$	129,939		$	(127,102)
Less: Undistributed net income allocable to participating securities		-			(1,599)			-
Undistributed net income (loss) applicable to common shareholders		(46,334)			128,340			(127,102)
Less: (Income) loss from discontinued operations, net of tax		(23,684)			(95,221)			106,657
Add: Undistributed net income from discontinued operations allocable to participating securities		-			1,172			-
Income (loss) from continuing operations applicable to Helix common shareholders	$	(70,018)	104,449	$	34,291	104,528	$	(20,445)	103,857


Diluted:
Income (loss) from continuing operations applicable to Helix common shareholders - Basic	$	(70,018)	104,449	$	34,291	104,528	$	(20,445)	103,857
Effect of dilutive securities:
Share-based awards other than participating securities		-	-		-	64		-	-
Undistributed net income reallocated to participating securities		-	-		2	-		-	-
Convertible preferred stock		-	-		40	361		-	-
Income (loss) from continuing operations applicable to Helix common shareholders - Diluted		(70,018)			34,333			(20,445)
Income (loss) from discontinued operations, net of tax		23,684			95,221			(106,657)
Net income (loss) applicable to Helix common shareholders - Diluted	$	(46,334)	104,449	$	129,554	104,953	$	(127,102)	103,857

We had net losses from continuing operations for the years ended December 31, 2012 and 2010. Accordingly, our diluted EPS calculation for 2012 and 2010 was equivalent to our basic EPS calculation because it excluded any assumed exercise or conversion of common stock equivalents because they were deemed to be anti-dilutive, meaning their inclusion would have reduced the reported net loss per share in those respective years. Shares that otherwise would have been included in the diluted per share calculations for the year ended December 31, 2012 and 2010, assuming we had earnings from continuing operations, are as follows (in thousands):


	2012	2010

Diluted shares (as reported)	104,449	103,857
Share-based awards	382	466
Convertible preferred stock	334	1,015
Total	105,165	105,338

The diluted EPS calculation also excluded dividends and related costs associated with the convertible preferred stock that otherwise would have been added back to net income if assumed conversion of the shares was dilutive during the year.

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 any of the years ended December 31, 2012, 2011 and 2010. Also, no diluted shares were included for our 2032 Notes for the year ended December 31, 2012 as the conversion price of $25.02 (and conversion trigger of $32.53 per share) was not met, and because we have the right to settle any such future conversions in cash at our sole discretion (Note 7).

Major Customers and Concentration of Credit Risk

The market for our products and services is primarily the offshore oil and gas industry. Oil and gas companies spend capital on exploration, drilling and production operations, the amount of which is generally dependent on the prevailing view of future oil and gas prices that are subject to many external factors which may contribute to significant volatility. Our customers consist primarily of major oil and gas companies, well-established oil and gas pipeline companies and independent oil and gas producers and suppliers. We perform ongoing credit evaluations of our customers and provide allowances for probable credit losses when necessary. The percent of consolidated revenue from major customers, those whose total represented 10% or more of our consolidated revenues from continuing operations is as follows: 2012 — Shell (12%); 2011 — Shell (10%) and 2010 — BP plc. (26%). The percent of revenue from major customers, those whose total represented 10% or more of our discontinued oil and gas revenues, is as follows: 2012 — Shell (64%) and JP Morgan Ventures (26%); 2011 — Shell (89%); and 2010 — Shell (67%) and Louis Dreyfus Energy Services (19%). We estimate that in 2012 we provided subsea services to over 70 customers.

Fair Value Measurements

Current fair value accounting standards define fair value, establish a consistent framework for measuring fair value and expand disclosure for each major asset and liability category measured at fair value on either a recurring or nonrecurring basis. These standards also clarify that fair value is an exit price, representing the amount that would be received to sell an asset, or paid to transfer a liability, in an orderly transaction between market participants. These fair value accounting rules establish a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:


	•		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).

Our financial instruments include cash and cash equivalents, accounts receivable, accounts payable, our long-term debt and various derivative instruments. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value due to the highly liquid nature of these instruments. The following table provides additional information related to other financial instruments measured at fair value on a recurring basis at December 31, 2012 (in thousands):


		Level 1		Level 2 ⁽¹⁾		Level 3		Total	Valuation Technique
Assets:
Oil contracts	$	–	$	5,800	$	–	$	5,800	(c)
Foreign currency forwards		–		146		–		146	(c)

Liabilities:
Oil contracts		–		15,777		–		15,777	(c)
Fair value of long-term debt ⁽²⁾		994,311		123,187		–		1,117,498	(a)
Interest rate swaps		–		521		–		521	(c)
Total net liability	$	994,311	$	133,539	$	–	$	1,127,850

(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 based on market data. 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 December 31, 2012 and 2011 is as follows:


		2012				2011
		Carrying Value		Fair Value		Carrying Value		Fair Value

Term Loans (mature July 2015) ^(a)	$	367,181	$	368,295	$	279,750	$	279,750
Revolving Credit Facility (matures July 2015) ^(a)		100,000		100,000		-		-
2025 Notes (mature December 2025) ^(b)		3,487		3,487		300,000		300,543
2032 Notes (mature March 2032) ^(c)		200,000		239,320		-		-
Senior Unsecured Notes (mature January 2016)		274,960		283,209		474,960		501,083
MARAD Debt (matures February 2027) ^(d)		105,288		123,187		110,166		124,488
Total debt	$	1,050,916	$	1,117,498	$	1,164,876	$	1,205,864

(a) In February 2013, we repaid $293.9 million of our Term Loans and $24.5 million under our Revolving Credit Facility with the after-tax proceeds from the sale of ERT.

(b) Carrying value excludes the related unamortized debt discount of $9.6 million at December 31, 2011. This remaining amount was repurchased by us in February 2013.

(d ) 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.

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

Debt Discount

On January 1, 2009, we recorded a discount of $60.2 million related to our Convertible Senior Notes due 2025 (“2025 Notes”) as required. To arrive at this discount amount, we estimated the fair value of the liability component of the 2025 Notes as of the date of their issuance (March 30, 2005) 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 7.75 years, which represented the earliest period that the holders could require us to repurchase the 2025 Notes (Note 7). The discount related to our 2025 Notes became fully amortized in December 2012.

In connection with the issuance of our Convertible Senior Notes due 2032 (“2032 Notes”), we recorded a discount of $35.4 million 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 holders could require us to repurchase all or a portion of the 2032 Notes (March 15, 2018). The remaining unamortized amount of the discount of the 2032 Notes was $31.7 million at December 31, 2012 (Note 7).

Investment Available for Sale

In 2009 we sold substantially all of our owned shares of the publicly-traded Cal Dive common stock for net proceeds of $418.2 million, net of underwriting fees. Following these sale transactions, we owned 0.5 million shares of Cal Dive common stock, representing less than 1% of the total outstanding shares of Cal Dive. Accordingly we classified our remaining interest in Cal Dive as an investment available for sale. As an investment available for sale, the value of our remaining interest was marked-to-market at each period end with the corresponding change in value being reported as a component of accumulated other comprehensive income (loss) in the accompanying consolidated balance sheet. In 2010, we recorded a $2.2 million non-cash other than temporary impairment charge that reflected the substantial reduction in Cal Dive’s common stock price since our sale of shares of Cal Dive common stock in 2009. In March 2011, we sold our remaining 0.5 million shares of Cal Dive common stock on the open market for gross proceeds of $3.6 million resulting in a pre-tax gain of $0.8 million.

New Accounting Standards

In December 2011, the FASB issued ASU No. 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities” (“ASU 2011-11”). Offsetting, otherwise known as netting, is the presentation of assets and liabilities as a single net amount in the statement of financial position (balance sheet). U.S. GAAP allows companies the option to present net in their balance sheets derivatives that are subject to a legally enforceable netting arrangement with the same party where rights of set-off are only available in the event of default or bankruptcy. ASU 2011-11 requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. An entity is required to apply the amendments for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. An entity should provide the disclosures required by those amendments retrospectively for all comparative periods presented. We are currently assessing the impact of ASU 2011-11 on our consolidated financial statements.

Oil And Gas Properties

12 Months Ended

Dec. 31, 2012

Oil And Gas Properties [Abstract]

Oil And Gas Properties

Note 3 — Oil and Gas Properties

Discontinued Operations

In December 2012, we announced a definitive agreement for the sale of ERT. On February 6, 2013, we sold ERT for $620 million plus contingent consideration in the form of overriding royalty interests in the Wang well and certain other future exploration prospects. As a result, we have presented the assets and liabilities included in the sale of ERT and the historical operating results of our former Oil and Gas segment as discontinued operations in the accompanying consolidated financial statements.

Oil and Gas Significant Accounting Policies

Restricted Cash

We had restricted cash totaling $28.4 million at December 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 the South Marsh Island Block 130 field. These escrowed funds were included in the sale of ERT in February 2013. These amounts are reflected in “Non-current assets of discontinued operations” in the accompanying consolidated balance sheets.

Inventories

We had oil and gas inventory totaling $11.9 million at December 31, 2012 and $16.4 million at December 31, 2011. This inventory primarily represents the cost of supplies to be used in our oil and gas drilling and development activities, primarily drilling pipe, tubulars and certain wellhead equipment, including two subsea trees. Our inventories are stated at the lower of cost or market value and we utilize the average cost method of maintaining our inventory. There were no charges to reduce inventory to its lower cost or market value in 2012. In December 2011, we agreed to sell approximately $4.6 million of our drilling pipe inventory for $2.5 million. In connection with this sale, we recorded a $2.1 million loss to reduce its value to its expected realized value at December 31, 2011.

Property and Equipment

Depreciation and Depletion. Depletion expense for oil and gas properties is determined on a field-by-field basis using the units-of-production method, with depletion rates for leasehold acquisition costs based on estimated total remaining proved reserves. Depletion rates for well and related facility costs are based on estimated total remaining proved developed reserves associated with each individual field. The depletion rates are changed whenever there is an indication of the need for a revision, but at a minimum, are evaluated annually. Any such revisions are accounted for prospectively as a change in accounting estimate. Depletion was discontinued when we announced the sale of ERT. We depreciate our other property and equipment over its estimated useful life on a straight-line basis.

Oil and Gas Properties. All of our former oil and gas properties are located in the United States offshore in the Gulf of Mexico. We followed the successful efforts method of accounting for our oil and natural gas exploration and development activities. Under this 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 and are reflected as a reduction of investing cash flows in the accompanying consolidated statements of cash flows.

Proved Properties. Proved oil and gas properties are assessed for possible impairment at least annually or when events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. An impairment loss is recognized as a result of a triggering event and when the estimated undiscounted future cash flows from a property are less than the carrying value. If impairment is indicated, an impairment charge is recorded equal to the difference between the carrying amount and the fair value of the property based on discounted future cash flows. In the discounted cash flow method, estimated future cash flows are based on prices based on published forward commodity price curves as of the date of the estimate and management’s estimates of future operating and development costs and a risk adjusted discount rate. See “Impairments” below for additional information regarding our oil and gas property impairments.

Unproved Properties. Unproved properties are also periodically assessed for impairment based on exploration and drilling efforts to date on the individual prospects and lease expiration dates. The amounts and timing of impairment provisions are also impacted by management’s assessment of the results of exploration activities, availability of funds for future activities and the current and projected political climate in areas in which we operate. We recorded impairments to unproved oil and gas properties totaling $0.8 million in 2012, $8.3 million in 2011 and $6.4 million in 2010. Such impairments were included in exploration expenses.

Exploratory Costs. The costs of drilling an exploratory well are capitalized as uncompleted or “suspended” wells pending the determination of whether the well has found proved reserves. If proved reserves are found these costs remain capitalized; if no reserves are found the capitalized costs are charged to exploration expenses. See “Exploration and Other” below for additional information regarding our exploration costs.

Accounting for Asset Retirement Obligations

We are required to record our asset retirement obligations at fair value in the period such obligations are incurred. The associated asset retirement costs are capitalized as part of the carrying cost of the asset. Our asset retirement obligations consisted of estimated costs for dismantlement, removal, site reclamation and similar activities associated with our former oil and gas properties. An asset retirement obligation and the related asset retirement cost are recorded when an asset is first constructed or purchased. The asset retirement cost is determined and discounted to present value using a credit-adjusted risk-free rate. After the initial recording, the liability is increased for the passage of time, with the increase being reflected as accretion expense, which is a component of our depreciation, depletion and amortization expense.

The following table describes the changes in our asset retirement obligations for ERT (both current and long-term) for the years ended December 31, 2012 and 2011 (in thousands):


		2012		2011
Asset retirement obligations at January 1,	$	227,090	$	222,653
Liability incurred during the period		3,664		4,982
Liability settled during the period		(105,160)		(37,769)
Other revisions in estimated cash flows ⁽¹⁾		62,834		22,345
Accretion expense (included in depreciation and amortization)		12,550		14,879
Asset retirement obligations at December 31,	$	200,978	$	227,090

(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 fields ($12.4 million and $22.5 million during the year ended December 31, 2012 and 2011, respectively) include corresponding abandonment expense charges to cost of sales within our consolidated statements of operations while changes in estimates for producing properties are recorded as an increase to property and equipment carrying costs of the related oil and gas properties within our consolidated balance sheets.

Revenue Recognition

Revenues from sales of crude oil and natural gas are recorded when delivery to the customer has occurred, title has transferred, prices are fixed and determinable and collection is reasonably assured. This occurs when production has been delivered to a pipeline or when a barge lifting has occurred. We may have an interest with other producers in certain properties. In this case, the entitlements method is used to account for sales of production. Under the entitlements method, we may receive more or less than our entitled share of production. If more than our entitled share of production is received, the imbalance is treated as a liability. If less than our entitled share is received, the imbalance is recorded as an asset. As of December 31, 2012, the net imbalance was a $1.0 million asset and was included in “Current assets of discontinued operations” ($4.0 million) and “Current liabilities of discontinued operations” ($3.0 million).

Derivative Instruments and Hedging Activities

As previously noted, our risk management activities often involve the use of derivative financial instruments to hedge the impact of market risk exposure, including those related to the market prices of oil and natural gas. To reduce the impact of these risks on earnings and increase the predictability of our cash flows, from time to time we have entered into certain derivative contracts, including costless collars and swaps for a portion of our oil and gas production. These derivative contracts are reflected in our balance sheet at fair value. See Note 2 for additional disclosure regarding our accounting for derivative contracts.

The fair value of our oil and gas derivative contracts 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 estimates of future prices, price correlation and market volatility and liquidity. Our actual results may differ from our estimates, and these differences can be positive or negative.

Prior to the announcement of the sale of ERT in December 2012, all of the effect of our oil and gas hedging contracts were reflected as a component of our discontinued operations in the accompanying consolidated financial statements. As a result of the announcement of the sale of ERT, we de-designated all of our remaining oil and natural gas derivative contracts as hedging instruments. Because the hedging contracts were not part of the sale of ERT, the effect post announcement of the sale are included within continuing operations in the accompanying consolidated financial statements.

At December 31, 2012, all of our commodity derivative contracts were subject to mark-to-market adjustments to reflect the changes in their fair values. In connection with the de-designation of these derivative contracts as hedging instruments, we were required to recognize amounts previously recorded in accumulated other comprehensive income (loss) and related deferred taxes into earnings. At December 31, 2012, we recorded losses of approximately $10.5 million ($6.8 million net of tax) to reflect the mark-to-market adjustments for changes in the fair values of the oil and gas commodity derivative contracts. See Note 17 for additional information regarding our commodity derivative contracts.

Impairments

Proved property impairment charges are reflected as reductions in cost of sales in our discontinued operations. We had no oil and gas proved property impairment charges in 2012.

In December 2012, following the announcement of our intention to sell ERT, we recorded a $138.6 million impairment charge to reduce our carrying value of ERT to its estimated fair value less costs to sell as determined by the negotiated sales price for ERT.

In 2011, we recorded $90.9 million of oil and gas property impairment charges associated with 11 of our Gulf of Mexico oil and gas fields. These impairment charges were primarily related to changes in the field economics of the affected oil and gas properties. During 2011, the price of natural gas decreased significantly. When natural gas prices decrease this often affects the assumptions regarding future development of certain fields as some or all of those proved reserves may become uneconomic to develop or produce. Our impairment charges also reflect end of field life factors, including premature depletion or capital allocation decisions, primarily those affecting third party operated fields.

In 2010, we recorded $176.7 million of oil and gas property impairment charges, including $4.1 million related to our one U.K. oil and gas property which is reflected in continuing operations as it was not included in the sale of ERT. A total of 21 of our former Gulf of Mexico oil and gas properties were affected by impairment charges in 2010. The impairment charges associated with producing fields totaled $172.6 million, which primarily reflected reduction in our estimates of proved reserves (Note 16).

Results of Discontinued Operations

The following summarized financial information relates to ERT, which is reported as “Income (loss) from discontinued operations, net of tax” in the accompanying consolidated statements of operations:


		Year Ended December 31,
		2012		2011		2010

Revenues	$	557,231	$	696,607	$	425,369
Costs:
Production (lifting) costs		164,663		176,269		131,156
Hurricane repair expense		662		(4,838)		4,699
Exploration expenses ⁽¹⁾		3,295		10,914		8,276
Depreciation, depletion, amortization and accretion		158,284		219,915		235,243
Proved property impairment and abandonment charges ⁽²⁾		151,045		113,439		177,138
(Gain) loss on sale of oil and gas properties		1,714		(4,531)		(287)
Non-hedge gain on commodity derivative contracts		(5,550)		-		(1,088)
Selling, general and administrative expenses		17,823		12,951		15,966
Net interest expense and other ⁽³⁾		28,191		25,558		19,687
Total costs		520,127		549,677		590,790
Pretax income (loss) from discontinued operations		37,104		146,930		(165,421)
Income tax provision (benefit)		13,420		51,709		(58,764)
Income (loss) from discontinued operations, net of tax	$	23,684	$	95,221	$	(106,657)

(1) See “Exploration and Other” below for additional information related to the components of our exploration costs, including impairment charges for expiring unproved leases.

(2) Includes $138.6 million recorded to reduce our carrying value of ERT to its estimated fair value less costs to sell.

(3) Net interest expense of $27.7 million, $25.2 million and $19.7 million for the years ended December 31, 2012, 2011 and 2010, respectively, was allocated to ERT primarily based on interest associated with indebtedness directly attributed to the substantial acquisition made by our oil and gas subsidiary in 2006. This includes interest related to debt required to be paid upon the disposition of ERT.

Included in the accompanying consolidated balance sheets are the following major classes of assets and liabilities associated with ERT as of December 31, 2012 and 2011:


		2012		2011

Cash and cash equivalents	$	2	$	2
Accounts receivable		63,762		90,882
Other current assets		20,236		28,037
Current assets of discontinued operations		84,000		118,921
Property and equipment, net		787,852		871,658
Restricted cash and other		28,375		33,741
Non-current assets of discontinued operations	$	816,227	$	905,399

Accounts payable	$	110,569	$	73,124
Accrued liabilities		18,217		27,968
Current asset retirement obligations		53,741		65,883
Current liabilities of discontinued operations		182,527		166,975
Asset retirement obligations		147,237		161,208
Non-current liabilities of discontinued operations	$	147,237	$	161,208

Exploration and Other

As of December 31, 2012, we had $8.2 million of capitalized costs associated with ongoing exploration and/or appraisal activities. The following table provides a detail of our capitalized exploratory project costs at December 31, 2012 and 2011 (in thousands):


		2012		2011

Wang ⁽¹⁾	$	-	$	3,096
Danny II		-		2,619
T-6 ⁽¹⁾		8,122		-
Other		125		125
Total	$	8,247	$	5,840

(1) Both of these wells are located within the Phoenix field at Green Canyon Block 237.

The following table reflects net changes in exploratory well costs during the years ended December 31, 2012, 2011 and 2010 (in thousands):


		2012		2011		2010

Beginning balance at January 1,	$	5,840	$	3,252	$	3,059
Additions pending the determination of proved reserves		135,311		2,513		(944)
Reclassifications to proved properties		(132,959)		5		713
Charged to dry hole expense		55		70		424
Ending balance at December 31,	$	8,247	$	5,840	$	3,252

Further, the following table details the components of exploration expenses for the years ended December 31, 2012, 2011 and 2010 (in thousands):


		Year Ended December 31,
		2012		2011		2010

Delay rental and geological and geophysical costs	$	2,517	$	2,650	$	2,306
Impairment of unproved properties		833		8,334		6,394
Dry hole expense		(55)		(70)		(424)
Total exploration expense	$	3,295	$	10,914	$	8,276

Our oil and gas activities in the United States are regulated by the federal government and require significant third-party involvement, such as refinery processing and pipeline transportation. We record revenue from our offshore properties net of royalties paid to the Office of Natural Resources Revenue. Royalty fees paid totaled approximately $78.1 million, $85.4 million and $37.2 million for the years ended December 31, 2012, 2011 and 2010, respectively.

United Kingdom Property

Since 2006, we have maintained an ownership interest in the Camelot field, located offshore in the North Sea. In 2007, we sold half of our 100% working interest in Camelot to a third party with whom we agreed to jointly pursue future development and production of the field. In February 2010, we acquired this third party thereby assuming its obligations, most notably the asset retirement obligation, related to its 50% working interest in the field.

In connection with the valuation of assets acquired and liabilities assumed in this acquisition, we reassessed the fair value associated with our original 50% interest in the field. Based on these evaluations, it was concluded that an impairment of the property was required based on the unlikely probability of our spending the future capital necessary to further develop the Camelot field. In 2010, we recorded $4.1 million of impairment charges to fully impair the property and $0.9 million of charges to expense to increase the asset retirement obligation for the Camelot field.

Our plan was to fully abandon the field in 2012 in accordance with applicable regulations in the United Kingdom. Modifications to U.K. regulations governing such operations required us to reassess our existing abandonment plan and cost estimates in 2011. The results of this review concluded that the scope of work to be performed in the abandoning of the wells in the field would be significantly expanded and as a result our cost estimates significantly increased. Based on our abandonment plan, we increased the asset retirement obligation by recording a corresponding $20.0 million charge to expense. At December 31, 2011, the remaining asset retirement obligation for the Camelot field was $27.3 million.

During 2012, we recorded $15.5 million of additional charges to expense to reflect further increases in our estimated costs to complete our abandonment activities at Camelot, including the removal of certain environmentally sensitive materials. The abandonment of the Camelot field is substantially complete. At December 31, 2012, the recorded asset retirement obligation for the Camelot field was $2.9 million.

The operating results and financial position associated with our U.K. property do not qualify for discontinued operations accounting treatment as this property was not classified as held for sale and thus they are reflected as continuing operations in our consolidated financial statements for all periods presented.

Details Of Certain Accounts

12 Months Ended

Dec. 31, 2012

Details Of Certain Accounts

Note 4 — Details of Certain Accounts

Other current assets consisted of the following as of December 31, 2012 and 2011 (in thousands):


		2012		2011

Other receivables	$	1,086	$	618
Prepaid insurance		11,999		12,608
Other prepaids		11,751		11,328
Spare parts inventory		2,480		1,677
Income tax receivable ⁽¹⁾		14,201		-
Current deferred tax assets		43,942		41,449
Derivative assets		5,946		21,579
Other		5,529		4,325
Total other current assets	$	96,934	$	93,584

(1) Reflects the total amount of estimated tax receivable in excess of the estimated current income tax liability.

Other assets, net, consisted of the following as of December 31, 2012 and 2011 (in thousands):


		2012		2011

Deferred dry dock expenses, net ⁽¹⁾	$	22,704	$	5,381
Deferred financing costs, net		24,338		26,483
Intangible assets with finite lives, net		491		531
Other		2,304		2,771
Total other assets, net	$	49,837	$	35,166

(1) The increase subsequent to December 31, 2011 reflects the costs associated with the regulatory dry docks for our Q4000, Seawell and Well Enhancer vessels during 2012.

Accrued liabilities consisted of the following as of December 31, 2012 and 2011 (in thousands):


		2012		2011

Accrued payroll and related benefits	$	51,561	$	45,217
Current asset retirement obligations ⁽¹⁾		2,898		27,300
Unearned revenue		6,137		7,654
Billing in excess of cost ⁽²⁾		6,445		28,839
Accrued interest		17,451		24,028
Derivative liability ⁽³⁾		16,266		1,247
Taxes payable excluding income tax payable		5,164		3,748
Pipelay assets sale deposit ⁽⁴⁾		50,000		-
Other		5,592		8,079
Total accrued liabilities	$	161,514	$	146,112

(1) Reflects the substantial completion of the abandonment of the Camelot field (Note 3).

(2) Decrease reflects fewer ongoing subsea construction projects using the percentage-of-completion method of accounting as a result of the expected sales of our remaining pipelay vessels.

(3) Primarily reflects the fair value of oil commodity derivative contracts of $15.8 million at December 31, 2012 (Note 17). These contracts were settled in February 2013.

(4) Reflects the cash deposit we received in association with the expected sales of our two remaining pipelay vessels, the Express and the Caesar, and other related pipelay equipment (Note 2), which is refundable in very limited circumstances. The sales of these vessels are scheduled to close and fund in two stages in 2013 following the completion of each vessel’s existing backlog of work.

Equity Investments

12 Months Ended

Dec. 31, 2012

Equity Investments [Abstract]

Equity Investments

Note 5 — Equity Investments

As of December 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 $91.4 million and $96.0 million as of December 31, 2012 and 2011, respectively (including capitalized interest of $1.3 million and $1.4 million at December 31, 2012 and 2011, 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. Our investment in Independence Hub was $76.2 million and $79.7 million as of December 31, 2012 and 2011, respectively (including capitalized interest of $4.6 million and $4.9 million at December 31, 2012 and 2011, respectively).

We made the following contributions to our equity investments during the years ended December 31, 2012, 2011 and 2010 (in thousands):


		Year Ended December 31,
		2012		2011		2010

Clough Helix Pty Ltd. (see below)	$	-	$	2,699	$	8,253
Total	$	-	$	2,699	$	8,253

We received the following distributions from our equity investments during the years ended December 31, 2012, 2011 and 2010 (in thousands):


		Year Ended December 31,
		2012		2011		2010

Deepwater Gateway	$	8,157	$	7,600	$	8,125
Independence Hub		8,073		18,580		21,615
Other		-		-		268
Total	$	16,230	$	26,180	$	30,008

In February 2010, we announced the formation of a joint venture with Australian-based engineering and construction company, Clough Limited (“Clough”), to provide a range of subsea services to offshore operators in the Asia Pacific region. The joint venture, then named Clough Helix Pty Ltd, was to perform its services using the Normand Clough, a 118-meter long multi-service chartered vessel. The joint venture also utilized each member’s personnel and equipment to perform its subsea services as provided in the joint venture agreement. In 2011, our share of the income associated with the Australian joint venture’s operations was $2.1 million. Our share of its losses was $3.6 million in 2010, which primarily reflects the cost associated with the commencement of its operations.

In December 2011, the marine construction and offshore engineering operations of Clough were acquired by a third party, including Clough’s 50% ownership interest in the joint venture. At December 31, 2011, we conducted an impairment assessment of our investment in the joint venture based on uncertainties concerning the continued availability of the Normand Clough and the limited backlog of existing projects at the time. We concluded that the $10.6 million carrying amount of the investment in the joint venture was fully impaired and recorded a $10.6 million other than temporary impairment charge in the accompanying consolidated statements of operations.

In the first quarter of 2012, we recorded additional losses totaling $3.8 million, including a $3.0 million fee when we negotiated our exit from the joint venture. In April 2012, we paid this fee. In connection with our exit, we were entitled to 50% of the value 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 such assets of the joint venture, 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.

The summarized aggregated financial information related to the subsidiaries we record using the equity investment is as follows (in thousands):


		Year Ended December 31,
		2012		2011		2010

Revenues	$	53,159	$	193,521	$	141,705
Operating income		30,463		97,954		93,324
Net income		30,463		93,215		93,005


		December 31,
		2012		2011		2010

Current assets	$	16,682	$	39,754	$	25,352
Total assets		537,251		591,761		594,645
Current liabilities		706		11,012		6,434
Total liabilities		5,320		27,163		19,695

The entire disclosure for equity method investments and joint ventures. Equity method investments are investments that give the investor the ability to exercise significant influence over the operating and financial policies of an investee. Joint ventures are entities owned and operated by a small group of businesses as a separate and specific business or project for the mutual benefit of the members of the group.

Kommandor LLC	12 Months Ended
Kommandor LLC	Dec. 31, 2012
Kommandor LLC [Abstract]
Kommandor LLC	Note 6 — Kommandor LLC In October 2006, we partnered with Kommandor RØMØ, a Danish corporation, to form Kommandor LLC, a Delaware limited liability company, the purpose of which was to convert a ferry vessel into a ship-shaped dynamically-positioned floating production unit vessel. Upon completion of the conversion in April 2009, the vessel, (the HP I) was leased to us under a bareboat charter. We subsequently installed topside oil and gas processing equipment, at 100% our cost, that allows the HP I to serve as a floating production system. The HP I will primarily service fields in the Deepwater of the Gulf of Mexico. The initial plan was to utilize the HP I at the Phoenix field, in which we held a 70% working interest prior to the sale of ERT. In June 2010, the HP I was certified for use as a floating production unit by the U.S. Coast Guard. Following that certification, the HP I was preparing to initiate service to the Phoenix field; however, it was then contracted by BP to participate in the Macondo well control and containment efforts. The HP I participated in those response and containment efforts until early October 2010 at which time BP released it from its contract and the HP I returned to the Phoenix field where production commenced in October 2010. The HP I is under contract with ERT to service the Phoenix field through at least December 31, 2016. The total cost of the conversion of the vessel was $148.7 million. The total cost of us to install the topside oil and gas processing facilities was $196.3 million. The operating agreement with Kommandor RØMØ provides that for a period of two months immediately following the fifth anniversary of the completion of the initial conversion (April 2014 – June 2014, the “Helix Option Period”), we may purchase Kommandor RØMØ’s membership interest at a value specified in the agreement. In addition, for a period of two months starting from 30 days after the Helix Option Period, Kommandor RØMØ can require us to purchase its share of the company at a value specified in the operating agreement. We estimate that the cash outlay to Kommandor RØMØ for its interest in Kommandor LLC at the time the put or call is exercised will be approximately $19 million. The consolidated results of Kommandor LLC are included in our Production Facilities segment. We own approximately 81% of Kommandor LLC at December 31, 2012.

Long-Term Debt

12 Months Ended

Dec. 31, 2012

Long-Term Debt [Abstract]

Long-Term Debt

Note 7 — Long-Term Debt

Long-term debt consisted of the following as of December 31, 2012 and 2011 (in thousands):


		2012		2011

Term Loans (mature July 2015)	$	367,181	$	279,750
Revolving Credit Facility (matures July 2015)		100,000		-
2025 Notes (mature December 2025)		3,487		300,000
2032 Notes (mature March 2032)		200,000		-
Senior Unsecured Notes (mature January 2016)		274,960		474,960
MARAD Debt (matures February 2027)		105,288		110,166
Unamoritized debt discount		(31,688)		(9,555)
Total debt		1,019,228		1,155,321
Less current maturities		(16,607)		(7,877)
Long-term debt	$	1,002,621	$	1,147,444

Senior Unsecured Notes

In December 2007, we issued $550 million of 9.5% Senior Unsecured Notes due 2016 (“Senior Unsecured Notes”). 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.

The Senior Unsecured Notes are junior in right of payment to all our existing and future secured indebtedness and obligations and rank equally in right of payment with all of our existing and future senior unsecured indebtedness. The Senior Unsecured Notes rank senior in right of payment to any of our future subordinated indebtedness.

The Senior Unsecured Notes mature on January 15, 2016. Interest on the Senior Unsecured Notes accrues at the fixed rate of 9.5% per annum and is payable semiannually in arrears on each January 15 and July 15, and commenced on July 15, 2008. Interest is computed on the basis of a 360-day year comprising twelve 30-day months.

Included in the Indenture governing the Senior Unsecured Notes are terms, conditions and covenants that are customary for this type of indebtedness. The covenants include limitations on our and our subsidiaries’ ability to incur additional indebtedness, pay dividends, repurchase our common stock, and sell or transfer assets. As of December 31, 2012, we were in compliance with these covenants.

Prior to stated maturity, 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, if any, thereon to the applicable redemption date.


Year		Redemption Price

2012		104.750%
2013		102.375%
2014 and thereafter		100.000%

In the event a change of control (as defined in the governing Indenture) of the Company occurs, each holder of the Senior Unsecured Notes will have the right to require us to purchase all or any part of such holder’s Senior Unsecured Notes. In such event, we are required to offer to purchase all of the Senior Unsecured Notes at a purchase price in cash in an amount equal to 101% of the principal amount, plus accrued and unpaid interest, if any, to the date of purchase.

At December 31, 2010, we had $550.0 million of Senior Unsecured Notes outstanding. In 2011, we purchased a portion of our Senior Unsecured Notes that resulted in the early extinguishment of an aggregate $75.0 million of those notes. In these transactions we paid an aggregate amount of $77.4 million, including $75.0 million in principal and $2.4 million in premium for the repurchased Senior Unsecured Notes. We also paid the accrued interest on these Senior Unsecured Notes totaling $0.8 million and we recorded a $0.9 million charge to interest expense to accelerate a pro rata portion of the deferred financing costs associated with the issuance of the Senior Unsecured Notes in 2007.

At December 31, 2011, we had $475.0 million of Senior Unsecured Notes outstanding. In March 2012, we purchased a portion of these Senior Unsecured Notes which 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 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 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 consolidated statements of operations.

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 B”) 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 seven times, with the most recent amendment occurring in September 2012. These amendments address certain issues with regard to covenants, maturity and the borrowing limits under the Term Loan B and the Revolving Loans.

In February 2013, we amended the credit agreement to waive certain year end oil and gas reporting requirements and covenant compliance as a result of the sale of ERT.

In September 2012, we amended the credit agreement to primarily:

	•		permit investments in (i) non-guarantor, non-pledged subsidiaries and (ii) joint ventures, provided that after giving effect to each such investment, a minimum consolidated liquidity requirement of $400 million is met on a pro forma basis;
	•		increase the debt basket for foreign subsidiaries (other than specified foreign subsidiaries that currently are excepted from this debt basket) from $200 million to $400 million provided that such indebtedness is non-recourse to us and our other subsidiaries (the “Foreign Subsidiary Debt Basket”); and
	•		exclude, to the extent it otherwise would be included in the calculation of financial covenants, EBITDA, interest charges and indebtedness related to assets secured by, or otherwise subject to, the indebtedness permitted by the Foreign Subsidiary Debt Basket.

In February 2012, we entered into a separate amendment to our Credit Agreement. Under the terms of this amendment, the participating lenders agreed to loan us $100.0 million pursuant to an additional term loan (the “Term Loan A”). The terms of the 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.

Our Term Loan debt 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. The average interest rates on our Term Loan debt for the years ended December 31, 2012 and 2011 were approximately 3.7% and 3.8%, respectively, including the effects of our interest rate swaps (Note 17). The Term Loans are 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.

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. These letters of credit primarily guarantee asset retirement obligations as well as various contract bidding, contractual performance, insurance activities and shipyard commitments. 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. Fees associated with outstanding letters of credit range from 2.0% to 3.0%, depending on our consolidated leverage ratio. We also pay a fixed commitment fee of 0.5% on the unused portion of our Revolving Credit Facility. In March 2012, we borrowed $100.0 million under our Revolving Credit Facility to repurchase a portion of our Senior Unsecured Notes. Accordingly, at December 31, 2012, we had $100.0 million drawn on the Revolving Credit Facility and our availability under the Revolving Credit Facility totaled $487.6 million, net of $12.4 million of letters of credit issued. The average interest rate under the Revolving Credit Facility totaled 3.0% for the period in which we had borrowings outstanding during the year ended December 31, 2012. There were no borrowings outstanding at December 31, 2011.

We may elect to prepay amounts outstanding under the Term Loans without prepayment penalty, but may not reborrow any amounts prepaid. We may prepay amounts outstanding under the Revolving Loans without prepayment penalty, and may reborrow amounts prepaid prior to maturity. In addition, upon the occurrence of certain dispositions or the issuance or incurrence of certain types of indebtedness, we may be required to prepay a portion of the Term Loan debt and borrowings under the Revolving Credit Facility equal to the amount of proceeds received from such occurrences (in the event of a disposition of assets comprising collateral, 60% of the after-tax proceeds). Such prepayments will be applied first to the Term Loan B, and any excess will then be applied to the Term Loan A and the Revolving Credit Facility on a pro rata basis. In February 2013, we repaid $293.9 million of our Term Loans and $24.5 million under our Revolving Credit Facility with the after-tax proceeds from the sale of ERT. At February 19, 2013, the remaining balance on our Term Loan debt totaled $73.3 million and the balance outstanding on our Revolving Credit Facility totaled $78.1 million.

The Credit Agreement and the other ancillary loan documents (together, the “Loan Documents”) include terms, conditions and covenants that we consider customary for this type of indebtedness. The covenants include restrictions on the Company’s and our subsidiaries’ ability to grant liens, incur indebtedness, make investments, merge or consolidate, sell or transfer assets and pay dividends. The Credit Agreement also places certain annual and aggregate limits on expenditures for acquisitions, investments in joint ventures and capital expenditures. The Credit Agreement requires us to meet certain minimum financial ratios for interest coverage, consolidated leverage, senior secured debt leverage and, until we achieve investment grade ratings from Standard & Poor’s and Moody’s, collateral coverage.

If we or any of our subsidiaries do not pay any amounts owed to the lenders under the Credit Agreement when due, breach any other covenant to the lenders or fail to pay other debt above a stated threshold, in each case, subject to applicable cure periods, the lenders have the right to stop making advances to us and to declare the outstanding loans immediately due. The Credit Agreement includes other events of default that are customary for this type of transaction. As of December 31, 2012, we were in compliance with all debt covenants and restrictions.

The loans and our other obligations to the lenders under the Credit Agreement are guaranteed by all of our U.S. subsidiaries except Cal Dive I-Title XI, Inc., and are secured by a lien on substantially all of our assets and properties and all the assets and properties of our U.S. subsidiaries except Cal Dive I-Title XI, Inc. In addition, we have pledged a portion of the shares of our significant foreign subsidiaries to the lenders as additional security. The Credit Agreement also contains provisions that limit our ability to incur certain types of additional indebtedness. These provisions effectively prohibit us from incurring any additional secured indebtedness or indebtedness guaranteed by us. The Credit Agreement does however permit us to incur certain unsecured indebtedness, and also provides for our subsidiaries to incur project financing indebtedness (such as our MARAD loans) secured by the underlying asset, provided that the indebtedness is not guaranteed by us.

Convertible Senior Notes Due 2025

In March 2005, we issued $300 million of our 3.25% Convertible Senior Notes due 2025 at 100% of the principal amount to certain qualified institutional buyers (“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 2025 Notes at their inception.

In association with the issuance of additional Convertible Senior Notes (see “Convertible Senior Notes Due 2032” below) in March 2012, 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. 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 consolidated statements of operations. The loss on early extinguishment includes the acceleration of $3.5 million of related unamortized discount 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.

As of the date of this filing, there are no outstanding 2025 Notes. The repayment of this debt occurred when holders of $154.3 million of the 2025 Notes exercised their option on December 15, 2012 to require us to repurchase their 2025 Notes and we repurchased the remaining $3.5 million of the 2025 Notes in February 2013.

Our weighted average share price for 2012, 2011 and 2010 was below the $32.14 per share conversion price. As a result, there are no shares included in our diluted earnings per share calculation associated with the assumed conversion of our 2025 Notes.

Convertible Senior Notes Due 2032

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 (“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. The remaining net proceeds were used 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, and are 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 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 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 (as defined in the governing indenture).

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.

Our weighted average share price for 2012 was below the $25.02 per share conversion price. As a result, there are no shares included in our diluted earnings per share calculation associated with the assumed conversion of our 2032 Notes.

MARAD Debt

This U.S. government guaranteed financing ("MARAD Debt") is pursuant to Title XI of the Merchant Marine Act of 1936 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). In accordance with the MARAD Debt agreements, we are required to comply with certain covenants and restrictions, including the maintenance of minimum net worth, working capital and debt-to-equity requirements. At December 31, 2012, we were in compliance with these debt covenants.

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 December 31, 2012, we were in compliance with these covenants and restrictions.

We paid financing costs associated with our debt totaling $7.6 million in 2012 and $9.3 million in 2011. Unamortized deferred financing costs are included in “Other assets, net” in the accompanying consolidated balance sheets and are being amortized over the life of the respective debt agreements. The following table reflects the components of our deferred financing costs for the years ended December 31, 2012 and 2011 (in thousands):


		2012						2011
		Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net

Term Loans (mature July 2015)	$	15,318	$	(11,595)	$	3,723	$	13,680	$	(10,257)	$	3,423
Revolving Credit Facility (matures July 2015)		20,021		(12,466)		7,555		19,236		(9,640)		9,596
2025 Notes (mature December 2025)		8,189		(8,189)		-		8,189		(7,340)		849
2032 Notes (mature March 2032)		4,251		(534)		3,717		78		-		78
Senior Unsecured Notes (mature January 2016)		10,643		(8,252)		2,391		10,643		(5,546)		5,097
MARAD Debt (matures February 2027)		12,200		(5,248)		6,952		12,200		(4,760)		7,440
Total deferred financing costs	$	70,622	$	(46,284)	$	24,338	$	64,026	$	(37,543)	$	26,483

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


		Term Loan⁽¹⁾		Revolving Credit Facility ⁽¹⁾		Senior Unsecured Notes		2025 Notes⁽²⁾		MARAD Debt		2032 Notes⁽³⁾		Total

Less than one year	$	8,000	$	-	$	-	$	3,487	$	5,120	$	-	$	16,607
One to two years		8,000		-		-		-		5,376		-		13,376
Two to three years		351,181		100,000		-		-		5,644		-		456,825
Three to four years		-		-		274,960		-		5,926		-		280,886
Four to five years		-		-		-		-		6,222		-		6,222
Over five years		-		-		-		-		77,000		200,000		277,000
Total debt		367,181		100,000		274,960		3,487		105,288		200,000		1,050,916
Current maturities		(8,000)		-		-		(3,487)		(5,120)		-		(16,607)
Long-term debt, less current maturities	$	359,181	$	100,000	$	274,960	$	-	$	100,168	$	200,000	$	1,034,309
Unamortized debt discount⁽⁴⁾		-		-		-		-		-		(31,688)		(31,688)
Long-term debt	$	359,181	$	100,000	$	274,960	$	-	$	100,168	$	168,312	$	1,002,621

(1) Term Loan amounts reflect both our Term Loan A and Term Loan B. In February 2013, we repaid $293.9 million of our Term Loans and $24.5 million under our Revolving Credit Facility with the after-tax proceeds from the sale of ERT.

(2) We repurchased the remainder of the 2025 Notes in February 2013 (see “2025 Notes” above).

(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 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 March 2018 for the Convertible Senior Notes due 2032.

The following table details our interest expense and capitalized interest for the years ended December 31, 2012, 2011 and 2010 (in thousands):


		Year Ended December 31,
		2012		2011		2010

Interest expense	$	53,601	$	72,824	$	78,609
Interest income		(548)		(1,366)		(546)
Capitalized interest		(4,893)		(1,277)		(12,474)
Interest expense, net	$	48,160	$	70,181	$	65,589

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

Income Taxes

12 Months Ended

Dec. 31, 2012

Income Taxes [Abstract]

Income Taxes

Note 8 — Income Taxes

We and our subsidiaries, including acquired companies from their respective dates of acquisition, file a consolidated U.S. federal income tax return. 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.

Components of income tax provision (benefit) on continuing operations reflected in the consolidated statements of operations consisted of the following (in thousands):


		Year Ended December 31,
		2012		2011		2010

Current	$	6,572	$	(78,150)	$	(22,930)
Deferred		(65,730)		41,344		42,096
	$	(59,158)	$	(36,806)	$	19,166


Domestic	$	(78,211)	$	(51,590)	$	1,596
Foreign		19,053		14,784		17,570
	$	(59,158)	$	(36,806)	$	19,166

Income taxes have been provided based on the U.S. statutory rate of 35% and at the local statutory rate for each foreign jurisdiction adjusted for items which are allowed as deductions for federal and foreign income tax reporting purposes, but not for book purposes. The primary differences between the statutory rate and our effective rate from continuing operations are as follows:


	Year Ended December 31,
	2012		2011		2010

Statutory rate	35.0	%	35.0	%	35.0	%
Foreign provision	11.2		(291.0)		418.2
Effect of Australian reorganization	-		(2,984.3)		-
Nondeductible goodwill impairment (Note 2)	-		-		301.0
Valuation allowance on certain deferred tax assets	-		-		427.8
Other	0.8		(265.0)		(34.3)
Effective rate	47.0	%	(3,505.3)	%	1,147.7	%

In 2011, we reorganized our Australian operating companies. The reorganization resulted in a recorded net tax benefit of $31.3 million associated with the impairment of our U.S. investment in the Australian subsidiaries.

Deferred income taxes result from the effect of transactions that are recognized in different periods for financial and tax reporting purposes. The nature of these differences and the income tax effect of each as of December 31, 2012 and 2011 are as follows (in thousands):


		2012		2011
Deferred tax liabilities:
Depreciation and depletion	$	336,471	$	396,355
Original Issue Discount on 2025 and 2032 Notes		13,098		37,067
Equity investments in production facilities		81,082		76,911
Prepaid and other		10,548		14,779
Total deferred tax liabilities	$	441,199	$	525,112

Deferred tax assets:
Net operating loss carryforward	$	(36,981)	$	(34,987)
Asset retirement obligations		(70,085)		(88,279)
Reserves, accrued liabilities and other		(35,229)		(39,995)
Total deferred tax assets		(142,295)		(163,261)
Valuation allowance		16,391		14,310

Net deferred tax liabilities	$	315,295	$	376,161

Deferred income tax is presented as:
Current deferred tax assets		(43,942)		(41,449)
Noncurrent deferred tax liabilities		359,237		417,610
Net deferred tax liabilities	$	315,295	$	376,161

At December 31, 2012, our U.S. net operating loss carryforward totaled $17.6 million and our foreign tax credit carryforward totaled $6.7 million. The net operating loss carryforward will expire in 2030, while the foreign tax credit carryforward will expire in 2020. At this time, we anticipate utilizing these tax attributes before the statute of limitations expires. At December 31, 2012, we had a $16.4 million valuation allowance related to certain non-U.S. deferred tax assets, primarily net operating losses generated in Australia, as management believed it is more likely than not that we will not be able to utilize the tax benefit. Additional valuation allowances may be made in the future if in management’s opinion it is more likely than not that the tax benefit will not be utilized. Any limitations on our ability to utilize our tax benefit carryforward could result in an increase in our federal income tax liability in future taxable periods.

We consider the undistributed earnings of our principal non-U.S. subsidiaries to be permanently reinvested. At December 31, 2012 and 2011, our principal non-U.S. subsidiaries had accumulated earnings and profits of approximately $167.9 million and $113.4 million, respectively. We have not provided deferred U.S. income tax on the accumulated earnings and profits.

We had $4.5 million related to uncertain tax positions as of December 31, 2012. In 2012, we reversed a $2.8 million long-term liability related to an uncertain tax position that was projected to be included on our 2011 tax return. The tax position was not taken when the 2011 tax return was filed. We account for tax-related interest in interest expense and tax penalties in operating expenses. We charged $0.2 million, $0.2 million and $0.7 million to income tax expense for interest and penalties accrued in 2012, 2011 and 2010, respectively, which brought our total liabilities for interest and penalties to $1.1 million and $0.9 million on our accompanying consolidated balance sheets at December 31, 2012 and 2011, respectively. As of December 31, 2012, 2011, and 2010, there were $3.4 million, $6.2 million and $3.4 million of unrecognized tax benefits that if recognized would affect the annual effective rate. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in thousands):


		2012		2011		2010

Balance at January 1,	$	7,085	$	4,085	$	3,417
Additions based on tax positions related to current year		-		2,785		-
Additions for tax positions of prior years		206		215		668
Reductions for tax positions of prior years		(2,785)		-		-
Balance at December 31,	$	4,506	$	7,085	$	4,085

We file tax returns in the U.S. and in various state, local and non-U.S. jurisdictions. We anticipate that any potential adjustments to our state, local and non-U.S. jurisdiction tax returns by tax authorities would not have a material impact on our financial position. The tax periods ending December 31, 2010, 2009, 2008, 2007 and 2006 are under examination by the U.S. Internal Revenue Service (“IRS”). The tax periods ended December 31, 2012 and 2011 remain open to future review and examination by the IRS. In non-U.S. jurisdictions, the open tax periods include 2012, 2011, 2010, 2009 and 2008.

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

Employee Benefit Plans

12 Months Ended

Dec. 31, 2012

Employee Benefit Plans [Abstract]

Employee Benefit Plans

Note 9 — Employee Benefit Plans

Defined Contribution Plan

We sponsor a defined contribution 401(k) retirement plan covering substantially all of our employees. Our contributions are in the form of cash and are determined annually as a 50% match of each employee’s contribution up to 5% of the employee’s salary. Our costs related to the 401(k) plan totaled $1.6 million, $1.4 million and $1.6 million for the years ended December 31, 2012, 2011 and 2010, respectively.

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”).

Upon adoption of the 1995 Incentive Plan in May 1995, a maximum of 10% of the total shares of common stock issued and outstanding were eligible to be granted to executive officers, selected management employees and non-employee members of our Board of Directors. Following the approval by shareholders of the 2005 Incentive Plan in May 2005, no further grants have been or will be made under the 1995 Incentive Plan.

In May 2012, the shareholders approved an amendment to and restatement of 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 December 31, 2012, there were 6.6 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.

The 1995 and 2005 Incentive Plans are administered by the Compensation Committee of Helix’s Board of Directors. The Compensation Committee also determines the type of award to be made to each participant and, as set forth in the related award agreement, the terms, conditions and limitations applicable to each award. The Compensation Committee may grant stock options, restricted stock, restricted stock units, and cash awards. Awards granted to employees under the incentive plans have typically vested 20% per year over a five-year period. Commencing in 2012, awards granted under the 2005 Incentive Plan have a vesting period of three years or 33% per year. There have been no stock options granted since 2004. Stock options granted have a maximum exercise life of 10 years.

Compensation cost for restricted shares is the product of grant date fair value of each share and the number of shares granted and is recognized over the respective vesting periods on a straight-line basis. Forfeitures on restricted stock totaled approximately 12% based on our most recent five-year average of historical forfeiture rates. Tax deduction benefits for an award in excess of recognized compensation cost is reported as a financing cash flow rather than as an operating cash flow. Stock based compensation that is based solely on service conditions is recognized on a straight line basis over the vesting period of the related shares.

Stock Options

The following table summarizes information about our stock options during the years ended December 31, 2012, 2011 and 2010:


	2012			2011			2010
			Weighted			Weighted			Weighted
			Average			Average			Average
			Exercise			Exercise			Exercise
	Shares		Price	Shares		Price	Shares		Price

Options outstanding at beginning of year	192,800	$	10.52	432,918	$	10.78	501,318	$	10.74
Exercised	(140,000)		9.24	(181,670)		10.92	(68,400)		10.52
Terminated	-		-	(58,448)		11.20	-		-
Options outstanding at end of year	52,800	$	13.91	192,800	$	10.52	432,918	$	10.78
Options exercisable at end of year	52,800	$	13.91	192,800	$	10.52	432,918	$	10.78

There was no compensation recognized associated with stock options in 2012, 2011 or 2010 as all stock options outstanding are vested. The aggregate intrinsic value of the stock options exercised in 2012, 2011 and 2010 was approximately $1.3 million, $1.1 million and $0.1 million, respectively. The aggregate intrinsic value of options exercisable at December 31, 2012, 2011 and 2010 was approximately $0.4 million, $1.0 million and $0.6 million, respectively. The weighted average remaining contractual life of stock option awards at December 31, 2012 was 1.4 years.

Share-based Awards

We grant share-based awards (restricted stock, restricted stock units (“RSUs”) and/or performance share units (“PSUs”)) to members of our Board of Directors, executive officers and selected management employees. The following table summarizes information about our share-based awards during the years ended December 31, 2012, 2011 and 2010:


	2012			2011			2010
			Grant Date			Grant Date			Grant Date
	Shares		Fair Value ⁽¹⁾	Shares		Fair Value ⁽¹⁾	Shares		Fair Value ⁽¹⁾

Awards outstanding at beginning of year	1,263,218	$	14.80	1,463,298	$	16.93	1,443,265	$	21.55
Granted	482,340		18.33	571,163		12.77	599,996		12.01
Vested ⁽²⁾	(400,180)		18.07	(504,813)		19.87	(444,905)		25.10
Forfeited	(21,066)		15.00	(266,430)		12.55	(135,058)		17.48
Awards outstanding at end of year	1,324,312	$	15.09	1,263,218	$	14.80	1,463,298	$	16.93

(1) Represents the weighted average grant date fair value, which is based on the quoted market price of the common stock on the business day prior to the date of grant.

(2) Total fair value of share-based awards that vested during the years ended December 31, 2012, 2011 and 2010 was $6.7 million, $6.7 million and $5.6 million, respectively.

For the years ended December 31, 2012, 2011 and 2010, $7.7 million, $8.4 million, $9.0 million, respectively, was recognized as stock-based compensation expense related to share-based awards. Future compensation cost associated with unvested share-based awards at December 31, 2012, 2011, and 2010 totaled approximately $13.2 million, $12.0 million and $16.8 million, respectively. The weighted average vesting period related to unvested share-based awards at December 31, 2012 was approximately 2.2 years.

The following grants of share-based awards were made in 2012 under the amended and restated 2005 Incentive Plan:


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

January 3, 2012 ⁽¹⁾	272,153	$	15.80	33% per year over three years
January 3, 2012 ⁽²⁾	132,910		23.68	100% on January 1, 2015
January 3, 2012⁽³⁾	1,958		15.80	100% on January 1, 2014
April 1, 2012⁽³⁾	1,879		17.80	100% on January 1, 2014
July 2, 2012⁽³⁾	1,885		16.41	100% on January 1, 2014
August 23, 2012⁽³⁾	3,539		18.84	20% per year over five years
October 1, 2012⁽³⁾	1,830		18.27	100% on January 1, 2014
December 6, 2012⁽³⁾	66,186		18.13	33% per year over three years

(1) Reflects the grant of 132,910 restricted shares to our executive officers and 139,243 RSUs to selected management employees that are convertible into 139,243 shares of our common stock upon vesting. These RSUs may be settled in cash or common stock at the Company’s option.

(2) Reflects the grant of PSUs to 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.

(3) Reflects grants to our directors.

In January 2013, we granted our executive officers 89,329 restricted shares under the 2005 Long-Term Incentive Plan. The market value of the restricted shares was $20.64 per share or $1.8 million and the shares vest 33% per year for a three-year period. Separately, we issued our executive officers 89,329 PSUs. The PSUs provide for an award based on the performance of our common stock over a three-year period with the maximum amount of the award being 200% of the original awarded PSUs and the minimum amount being zero. The PSUs vest 100% on the three-year anniversary date of the grant. 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 determines to pay in cash.

Stock Compensation Modifications

Under our 1995 Incentive Plan and our 2005 Long-Term Incentive Plan, upon a stock recipient’s termination of employment, which is defined as employment with us and any of our majority-owned subsidiaries, any unvested restricted stock and stock options are forfeited immediately, and all unexercised vested options are forfeited as specified under the applicable plan or agreement.

Employee Stock Purchase Plan

In May 2012, 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, subject to certain restrictions and limitations established by the Compensation Committee of our Board of Directors (which administers the ESPP) and Section 423 of the Internal Revenue Code. The per share price of common stock purchased under the ESPP is equal to 85% of the lesser of (i) its fair market value on the first trading day of the purchase period or (ii) its fair market value on the last trading day of the purchase period. The first purchase period under the ESPP began on September 1, 2012. The total value of the ESPP awards is calculated using the component approach where each award is computed as the sum of 15% of a share of non-vested stock, a call option on 85% of a share of non-vested stock, and a put option on 15% of a share of non-vested stock. Share-based compensation expense with respect to the ESPP was $0.3 million for the year ended December 31, 2012.

Long-Term Incentive Cash 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. Our executive officers and certain other members of senior management as designated from time to time by the Compensation Committee of our Board of Directors are granted cash awards. Under the terms of the 2009 LTI Plan, cash awards historically have been both fixed sum amounts payable (for non-executive management only) as well as cash awards indexed to our common stock with the payment amount at each vesting date fluctuating based on the performance of our common stock (for both executive and non-executive management). These are measured based on the performance of our stock price over the applicable award period compared to a base price determined by the Compensation Committee of our Board of Directors at the time of the award. The measurement period to determine the annual payment for the share-based cash awards is generally the last 20 trading days of the year (the last 30 trading days for the 2009 awards). Payment amounts are based on the calculated ratio of the average stock price during the applicable measurement period over the original base price as determined by the Compensation Committee of our Board of Directors. The maximum amount payable under these share-based cash awards is twice the original targeted award and if the average price during the measurement period is less than 75% (50% for 2010 grants) of the base price, no payout will be made at the applicable anniversary date. Payments under the 2009 LTI Plan are made each year on the anniversary date of the award. Awards granted prior to 2012 have a vesting period of five years and awards granted in 2012 and 2013 have a vesting period of three years. 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 awards made under the 2009 LTI Plan totaled $4.2 million in 2012, $5.2 million in 2011, and $10.2 million in 2010. All such awards were made to our executive officers except for $4.3 million of the total award in 2010. Total compensation expense associated with the 2009 LTI Plan was $8.7 million ($7.3 million related to our executive officers), $7.9 million ($6.5 million related to our executive officers) and $8.6 million ($6.9 million related to our executive officers), respectively, for the years ended December 31, 2012, 2011 and 2010. The liability balance under the 2009 LTI Plan was $13.0 million at December 31, 2012 and $9.9 million at December 31, 2011, including $11.7 million at December 31, 2012 and $8.5 million at December 31, 2011 associated with the variable portion of the 2009 LTI plan. During 2012, 2011 and 2010, we paid $5.5 million, $5.9 million and $4.4 million of the liability associated with the 2009 LTI plan. We paid $7.1 million of this liability on January 4, 2013. In January 2013, $5.9 million was awarded under the 2009 LTI Plan to executive officers and selected management employees. No cash awards were given to non-executive employees in 2012 or 2011.

The entire disclosure for compensation-related costs for equity-based compensation, which may include disclosure of policies, compensation plan details, allocation of equity compensation, incentive distributions, equity-based arrangements to obtain goods and services, deferred compensation arrangements, employee stock ownership plan details and employee stock purchase plan details.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 14

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 123R
-Paragraph 64, 65, A240
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
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-Name Statement of Position (SOP)
-Number 93-6
-Paragraph 53
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Stockholders' Equity Note [Abstract]

Shareholders' Equity

12 Months Ended

Dec. 31, 2012

Stockholders' Equity Note Disclosure

Note 10 — Shareholders’ Equity

Our amended and restated Articles of Incorporation provide for authorized Common Stock of 240,000,000 shares with no stated par value per share and 5,000,000 shares of preferred stock, $0.01 par value per share issuable in one or more series.

The components of accumulated other comprehensive loss as of December 31, 2012 and 2011 are as follows (in thousands):



		2012		2011

Cumulative foreign currency translation adjustment	$	(15,667)	$	(22,958)
Unrealized gain on hedges, net ⁽¹⁾		-		12,941
Accumulated other comprehensive loss	$	(15,667)	$	(10,017)

(1) Amount at December 31, 2011 is net of deferred income tax liabilities totaling $7.0 million. In December 2012, all of our oil and natural gas commodity derivative contracts no longer qualified for hedge accounting following the announcement of the sale of ERT (Note 2).

The entire disclosure for shareholders' equity, comprised of portions attributable to the parent entity and noncontrolling interest, if any, including other comprehensive income (as applicable). Including, but not limited to: (1) balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings; (2) accumulated balance for each classification of other comprehensive income and total amount of comprehensive income; (3) amount and nature of changes in separate accounts, including the number of shares authorized and outstanding, number of shares issued upon exercise and conversion, and for other comprehensive income, the adjustments for reclassifications to net income; (4) rights and privileges of each class of stock authorized; (5) basis of treasury stock, if other than cost, and amounts paid and accounting treatment for treasury stock purchased significantly in excess of market; (6) dividends paid or payable per share and in the aggregate for each class of stock for each period presented; (7) dividend restrictions and accumulated preferred dividends in arrears (in aggregate and per share amount); (8) retained earnings appropriations or restrictions, such as dividend restrictions; (9) impact of change in accounting principle, initial adoption of new accounting principle and correction of an error in previously issued financial statements; (10) shares held in trust for Employee Stock Ownership Plan (ESOP); (11) deferred compensation related to issuance of capital stock; (12) note received for issuance of stock; (13) unamortized discount on shares; (14) description, terms, and number of warrants or rights outstanding; (15) shares under subscription and subscription receivables, effective date of new retained earnings after quasi-reorganization and deficit eliminated by quasi-reorganization and, for a period of at least ten years after the effective date, the point in time from which the new retained dates; and (16) retroactive effective of subsequent change in capital structure.

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-Name Accounting Standards Codification
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Reference 14: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Research Bulletin (ARB)
-Number 43
-Section B
-Paragraph 7, 11A
-Chapter 1
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 15: http://www.xbrl.org/2003/role/presentationRef
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 16: http://www.xbrl.org/2003/role/presentationRef
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-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph d
-Article 4

Reference 18: http://www.xbrl.org/2003/role/presentationRef
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Reference 19: http://www.xbrl.org/2003/role/presentationRef
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Reference 20: http://www.xbrl.org/2003/role/presentationRef
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Reference 21: http://www.xbrl.org/2003/role/presentationRef
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Reference 22: http://www.xbrl.org/2003/role/presentationRef
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Reference 23: http://www.xbrl.org/2003/role/presentationRef
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-Name Regulation S-X (SX)
-Number 210
-Section 04
-Article 3

Stock Buyback Program	12 Months Ended
Stock Buyback Program	Dec. 31, 2012
Stock Buyback Program [Abstract]
Stock Buyback Program	Note 11 — Stock Buyback Program In June 2009, we announced that we intended to purchase up to 1.5 million shares of our common stock plus an amount equal to additional shares of our common stock granted under our stock-based compensation plans (Note 9) as permitted under our Credit Agreement (Note 7). Our Board of Directors had previously granted us the authority to repurchase shares of our common stock in an amount equal to any equity based grants made pursuant to our stock-based compensation plans. We may continue to make repurchases pursuant to this authority from time to time as additional equity based grants are made under our stock based compensation plans depending on prevailing market conditions and other factors. All repurchases may be commenced or suspended at any time at the discretion of management. In June 2012, we purchased the remaining 405,063 shares then available under this plan for $6.4 million or an average of $15.82 per share. As of December 31, 2012, we had repurchased a total of 2,878,793 shares of our common stock for $36.9 million or an average of $12.83 per share. We retire all repurchased shares.

Related Party Transactions	12 Months Ended
Related Party Transactions	Dec. 31, 2012
Related Party Transactions [Abstract]
Related Party Transactions	Note 12 — 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 management, in exchange for a revenue interest that is an overriding royalty interest of 25% of Helix’s working interest. Production began in December 2003. Our payments to OKCD totaled $6.9 million, $8.3 million and $11.2 million in the years ended December 31, 2012, 2011 and 2010, 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. A former member of our Board of Directors is part of the senior management team of Weatherford International, Ltd (Weatherford). This individual resigned from our Board of Directors in May 2011. We paid Weatherford, an oil and gas industry company, $3.6 million for services provided to us in 2011 and $6.9 million for services provided in 2010.

The entire disclosure for related party transactions. Examples of related party transactions include transactions between (a) a parent company and its subsidiary; (b) subsidiaries of a common parent; (c) and entity and its principal owners; and (d) affiliates.

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-Number 210
-Section 04
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 57
-Paragraph 1-4
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Commitments And Contingencies and Other Matters [Abstract]

Commitments And Contingencies

12 Months Ended

Dec. 31, 2012

Commitments And Contingencies

Note 13 — Commitments and Contingencies and Other Matters

Commitments

Commitments Related to Expansion of Well Intervention Fleet

In March 2012, we executed a contract with a shipyard in Singapore for the construction of a newbuild semisubmersible well intervention vessel, the Q5000. This $386.5 million shipyard contract represents the majority of the expected costs associated with the construction of the Q5000. Under the terms of this contract, payments are made in a fixed percentage of the contract price, together with any variations, on contractually scheduled dates. At December 31, 2012, our total investment in the Q5000 was $139.6 million, including $115.9 million of scheduled payments made to the shipyard in 2012.

In July 2012, we contracted to charter the Skandi Constructor for use in our North Sea and Canadian well intervention operations. The initial term of the charter will be three years once the vessel is delivered to us in the first half of 2013.

In August 2012, we acquired the Discoverer 534 drillship from a subsidiary of Transocean Ltd. for $85 million. The vessel, renamed the Helix 534, is currently undergoing upgrades and modifications in Singapore to render it suitable for use as a well intervention vessel. At December 31, 2012, our investment in the acquisition and subsequent upgrades and modifications of the Helix 534 totaled $113.5 million.

Lease Commitments

We lease several facilities, ROVs and vessels under non-cancelable operating leases. Future minimum rentals under these leases at December 31, 2012 are as follows:


		ROVs and Vessels		Facilities and Other		Total

2013	$	84,409	$	1,948	$	86,357
2014		87,942		3,077		91,019
2015		86,155		3,620		89,775
2016		60,019		3,289		63,308
2017		38,188		3,153		41,341
Thereafter		4,905		22,778		27,683
Total lease commitments	$	361,618	$	37,865	$	399,483

Total rental expense under these operating leases was approximately $85.0 million, $62.2 million and $66.2 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Contingencies and Claims

Under terms of the ERT equity purchase agreement, we have required the buyer to provide bonding in a sufficient amount as determined by the BOEM to replace and allow for a full discharge of our existing guaranty to the BOEM for ERT’s lease obligations. The BOEM is in the process of reevaluating its decommissioning assessments for lease properties in the Gulf of Mexico and as such it is currently uncertain as to the amount of bonding that will be required, and thus also the amount of collateral that the buyer will be required to post to its surety/ies to secure such bonding. To the extent that the purchaser is required to post bonding collateral in an amount greater than $100 million to obtain bonds in the aggregate amount required by the BOEM in order for the BOEM to release our guaranty of ERT’s lease obligations, we have agreed to provide incremental collateral above that amount, if and to the extent required, to the surety/ies providing bonding for the deepwater properties (the Bushwood and Phoenix fields) in the form of letter(s) of credit, up to the next $50 million of required collateral, for a period not to exceed one year from issuance of the letter(s) of credit, after which the purchaser would then be required to provide all collateral associated with the bonding requirements with respect to our former oil and gas properties. As the BOEM conducts its review of the Gulf of Mexico decommissioning assessments, we intend to work closely with the purchaser to provide specific information regarding our former lease properties. We anticipate that the BOEM will determine its assessments of decommissioning costs for our former deepwater fields in the near term and that the bonding amounts, and therefore the bonding collateral requirements, to obtain a release of our guaranty with respect to ERT’s lease obligations will be known. At the time of this filing it is uncertain whether the amount of collateral will exceed the $100 million threshold so as to require any incremental bonding collateral on our part.

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 a $4 million allowance against our trade receivable balance that reduces its balance to an amount we believe is ultimately realizable. 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 2010, 2009, 2008 and 2007 related to an Indian subsea construction and diving contract that we entered into in December 2006. 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.

Litigation

On July 8, 2011, a shareholder derivative lawsuit styled City of Sterling Heights Police & Fire Retirement System v. Owen Kratz, et al. was filed in the United States District Court for the Southern District of Texas, Houston Division. In the suit, the plaintiff makes claims against our Board of Directors, certain of our former directors, our top current and former executives and the independent compensation consultant to the Compensation Committee of our Board of Directors, for breaches of the fiduciary duty of 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 the Company’s executive officers. The Company filed a motion to dismiss the claim asserting that the plaintiff has not (i) pled specific facts excusing its failure to make pre-suit demand on the Company’s Board of Directors as required by Minnesota law; (ii) filed proper verification; or (iii) stated a claim. A ruling regarding the motion is pending.

On May 12, 2012, a shareholder derivative lawsuit styled Mark Lucas v. Owen Kratz, et al. was filed in the 270^th 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 described above. 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.

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.

Insurance

We carry Hull and Increased Value insurance which provides coverage for physical damage up to an agreed amount for each vessel. The deductibles are based on the value of the vessel with a maximum deductible of $1.0 million on the Q4000, HP I and Well Enhancer, $500,000 on the Seawell, Express and Helix 534, and $750,000 on the Caesar. In addition to the primary deductibles, the vessels are subject to an annual aggregate deductible of $5 million. We also carry Protection and Indemnity (“P&I”) insurance which covers liabilities arising from the operation of the vessels and General Liability insurance which covers liabilities arising from construction operations. The deductible on both the P&I and General Liability is $100,000 per occurrence. Onshore employees are covered by Workers’ Compensation. Offshore employees and marine crews are covered by a Maritime Employers Liability (“MEL”) insurance policy which covers Jones Act exposures and includes a deductible of $100,000 per occurrence plus a $1.0 million annual aggregate deductible. In addition to the liability policies described above, we currently carry various layers of Umbrella Liability for total limits of $500 million excess of primary limits. Our self-insured retention on our medical and health benefits program for employees is $250,000 per participant.

We incur workers’ compensation, MEL, and other insurance claims in the normal course of business, which management believes are covered by insurance. The Company analyzes each claim for potential exposure and estimates the ultimate liability of each claim. At December 31, 2012, we did not have any claims exceeding our deductible limits. We have not incurred any significant losses as a result of claims denied by our insurance carriers. Our services are provided in hazardous environments where accidents involving catastrophic damage or loss of life could occur, and litigation arising from such an event may result in our being named a defendant in lawsuits asserting large claims. Although there can be no assurance the amount of insurance we carry is sufficient to protect us fully in all events, or that such insurance will continue to be available at current levels of cost or coverage, we believe that our insurance protection is adequate for our business operations. A successful liability claim for which we are underinsured or uninsured could have a material adverse effect on our business.

Loss Contracts

Whenever we have a contract that qualifies as a loss contract, we estimate the future shortfall between our anticipated future revenues and future costs. In 2010, we had two contracts that resulted in significant losses. The first of these contracts represented the initial project performed by the Caesar. The project, which included a primary work scope of laying 36-miles of pipe in the Gulf of Mexico, was completed in the third quarter of 2010 at a total loss of $12.0 million. The loss was primarily the result of certain start-up performance issues with the vessel as well as non-reimbursable costs associated with weather delays. The second contract was entered into by our WOSEA subsidiary to plug, abandon and salvage subsea wells in an oil and gas field located offshore China. The project commenced in the second half of 2010 and was initially expected to be completed by the end of October 2010. However, the subsea wells were structurally difficult to plug. WOSEA also experienced some start-up issues with its recently repaired subsea intervention device, which was significantly damaged in March 2009. In the fourth quarter of 2010, WOSEA experienced significant weather delays corresponding with the peak of typhoon season in the China Sea, which added additional non reimbursable time and related costs to the project. As a result of the continued weather delays, it was mutually agreed that WOSEA would discontinue the project and in connection with that decision, the parties also agreed to a reduced scope of work for this project. Our operating results for the year ending December 31, 2010 included an aggregate $30 million pre-tax loss, which reflects the costs to complete the project over the contractual revenues as modified. In the first quarter of 2011, this project ended and we recorded an additional pre-tax loss of approximately $0.2 million.

The entire disclosure for commitments and contingencies.

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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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Business Segment Information [Abstract]

Business Segment Information

12 Months Ended

Dec. 31, 2012

Business Segment Information

Note 14 — Business Segment Information

In 2012, our operations were conducted through the following lines of business: contracting services and oil and gas. We have disaggregated our contracting services operations into two reportable segments which consist of Contracting Services and Production Facilities. Our Contracting Services segment includes well intervention, robotics and subsea construction operations (see Note 2 for disclosures regarding the planned dispositions of our subsea construction vessels and related assets). 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. All material intercompany transactions between the segments have been eliminated. In December 2012, we announced a definitive agreement for the sale of ERT. In February 2013, we sold ERT. As a result, we have presented the assets and liabilities included in the sale of ERT and the historical operating results of our former Oil and Gas segment as discontinued operations in the accompanying consolidated financial statements. See Note 3 for additional information regarding our discontinued operations.

We evaluate our performance based on operating income and income before income taxes of each segment. Segment assets are comprised of all assets attributable to the reportable segment. Certain financial data by reportable segment are summarized as follows (in thousands):


		Year Ended December 31,
		2012		2011		2010
Revenues —
Contracting Services	$	899,793	$	738,235	$	780,339
Production Facilities		80,091		75,460		117,300
Intercompany elimination		(133,775)		(111,695)		(123,170)
Total	$	846,109	$	702,000	$	774,469

Income (loss) from operations —
Contracting Services	$	(7,702)	$	107,013	$	77,391
Production Facilities		40,082		38,404		63,863
Corporate		(92,985)		(82,470)		(71,080)
Intercompany elimination		(7,878)		93		(19,095)
Total	$	(68,483)	$	63,040	$	51,079

Net interest expense and other —
Contracting Services	$	702	$	765	$	1,299
Production Facilities		365		442		865
Corporate and eliminations		64,845		72,435		64,474
Total	$	65,912	$	73,642	$	66,638

Equity in earnings of equity investments	$	8,434	$	22,215	$	19,469


Income (loss) before income taxes —
Contracting Services	$	(8,529)	$	97,798	$	72,459
Production Facilities		48,276		58,064		86,100
Corporate and eliminations		(165,708)		(154,812)		(156,889)
Total	$	(125,961)	$	1,050	$	1,670

Income tax provision (benefit) —
Contracting Services	$	(15,707)	$	29,235	$	42,828
Production Facilities		15,784		19,233		29,049
Corporate and eliminations		(59,235)		(85,274)		(52,711)
Total	$	(59,158)	$	(36,806)	$	19,166


Identifiable assets —
Contracting Services	$	1,982,822	$	2,023,251	$	1,872,141
Production Facilities		503,531		534,776		512,990
Discontinued operations		900,227		1,024,320		1,206,889
Total	$	3,386,580	$	3,582,347	$	3,592,020

Capital expenditures —
Contracting Services	$	322,216	$	69,259	$	65,949
Production Facilities		823		30,896		56,269
Total	$	323,039	$	100,155	$	122,218


Depreciation and amortization —
Contracting Services	$	77,442	$	73,291	$	66,333
Production Facilities		16,828		14,935		9,907
Corporate and eliminations		2,931		2,962		5,638
Total	$	97,201	$	91,188	$	81,878

Intercompany segment revenues during the years ended December 31, 2012, 2011 and 2010 are as follows (in thousands):


		Year Ended December 31,
		2012		2011		2010

Contracting Services	$	87,718	$	65,638	$	109,012
Production Facilities		46,057		46,057		14,158
Total	$	133,775	$	111,695	$	123,170

Intercompany segment profits (losses) (which only relate to intercompany capital projects) during the years ended December 31, 2012, 2011 and 2010 are as follows (in thousands):


		Year Ended December 31,
		2012		2011		2010

Contracting Services	$	8,053	$	104	$	15,655
Production Facilities		(175)		(197)		3,457
Total	$	7,878	$	(93)	$	19,112

Revenue associated with our continuing operations by individually significant country during the years ended December 31, 2012, 2011 and 2010 is as follows (in thousands):


		Year Ended December 31,
		2012		2011		2010

United States	$	281,308	$	316,869	$	402,228
United Kingdom		345,074		275,499		198,011
Other		219,727		109,632		174,230
Total	$	846,109	$	702,000	$	774,469

We include the property and equipment, net in the country in which it is legally owned. The following table provides our property and equipment, net of accumulated depreciation, associated with our continuing operations by individually significant country (in thousands):


		Year Ended December 31,
		2012		2011		2010

United States	$	1,180,586	$	1,163,320	$	1,162,217
United Kingdom		304,062		281,430		275,012
Other		1,227		14,919		15,613
Total	$	1,485,875	$	1,459,669	$	1,452,842

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

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Supplemental Oil and Gas Disclosures [Abstract]

Allowance Accounts

12 Months Ended

Dec. 31, 2012

Allowance Accounts [Abstract]

Allowance Accounts

Note 15 — Allowance Accounts

The following table sets forth the activity in our valuation accounts for each of the three years in the period ended December 31, 2012 (in thousands):


		Allowance		Deferred
		for		Tax Asset
		Uncollectible		Valuation
		Accounts		Allowance

Balance at December 31, 2009	$	5,105	$	-
Additions ⁽¹⁾		4,108		8,497
Deductions ⁽²⁾		(4,753)		-
Balance at December 31, 2010		4,460		8,497
Additions ⁽³⁾		61		5,813
Deductions		(521)		-
Balance at December 31, 2011		4,000		14,310
Additions ⁽⁴⁾		1,257		2,081
Deductions		(105)		-
Balance at December 31, 2012	$	5,152	$	16,391

(1) Amounts include a $4.0 million bad debt allowance related to a large international construction contract and a $7.3 million increase in valuation allowance related to our WOSEA operations with the remaining allowance being related to our acquisition of the remaining 50% of the Camelot field in the United Kingdom.

(2) Includes the $3.7 million of bad debt expense related to settlement of third party claims related to a terminated international construction contract in Australia (Note 13).

(3) The increase in valuation allowance includes $4.9 million related to our WOSEA and $0.9 million to our oil and gas operations in the United Kingdom.

(4) The increase in valuation allowance includes $2.0 million related to our WOSEA operations and $0.1 million to our oil and gas operations in the United Kingdom. WOSEA has a full valuation allowance against its deferred tax asset balance.

See Note 2 for a detailed discussion regarding our accounting policy on accounts receivable and allowance for uncollectible accounts and Note 8 for a detailed discussion of the valuation allowance related to our deferred tax assets.

Supplemental Oil And Gas Disclosures

12 Months Ended

Dec. 31, 2012

Oil and Gas Exploration and Production Industries Disclosures

Note 16 — Supplemental Oil and Gas Disclosures (Unaudited)

As previously disclosed, we sold ERT on February 6, 2013. The following oil and gas disclosures concerning our costs and estimated proved reserves are required and provided for your information as we continued to own the oil and gas properties at December 31, 2012. Our only remaining involvement in the oil and gas business is the substantially-abandoned Camelot field in the U.K. (Note 3) and our remaining overriding royalty interest in the Wang well (Green Canyon Block 237) and certain other future exploration prospects.

Capitalized Costs

Aggregate amounts of capitalized costs relating to our oil and gas activities and the aggregate amount of related accumulated depletion, depreciation and amortization as of the dates indicated are presented below (in thousands):


		2012		2011

Unproved oil and gas properties	$	51,513	$	50,389
Proved oil and gas properties		2,453,667		2,516,363
Total oil and gas properties		2,505,180		2,566,752
Accumulated depletion, depreciation and amortization		(1,717,314)		(1,695,105)
Net capitalized costs	$	787,866	$	871,647

Included in the depreciable basis of our proved oil and gas properties is the estimate of our proportionate share of asset retirement obligations relating to these properties which are also reflected as asset retirement obligations within our non-current liabilities of discontinued operations (Note 3). At December 31, 2012 and 2011, our oil and gas asset retirement obligations totaled $203.9 million and $254.4 million, respectively.

Costs Incurred in Oil and Gas Producing Activities

The following table reflects the costs incurred in oil and gas property acquisition and development activities, including estimated asset retirement obligations, during the years indicated (in thousands):


		Year Ended December 31,
		2012		2011		2010

Property acquisition costs:
Proved properties	$	-	$	-	$	-
Unproved properties		-		41		364
Total property acquisition costs		-		41		364
Exploration costs		135,311		2,513		1,362
Development costs ⁽¹⁾		17,344		126,196		53,002
Asset retirement costs ⁽²⁾		59,715		46,446		25,356
Total costs incurred	$	212,370	$	175,196	$	80,084

(1) Development costs include costs incurred to obtain access to proved reserves to drill and equip development wells.

(2) Asset retirement costs include $15.5 million, $20.0 million, $0.9 million, respectively, associated with the Camelot field in the United Kingdom during the years ended December 31, 2012, 2011 and 2010.

Estimated Quantities of Proved Oil and Gas Reserves

We have employed full-time experienced reserve engineers and geologists who are responsible for determining proved reserves in compliance with SEC guidelines. Our engineering reserve estimates were prepared based upon interpretation of production performance data and sub-surface information obtained from the drilling of existing wells. ERT’s Vice President — Reservoir Engineering and Business Development, our internal reservoir engineers and geologists analyzed 100% of our significant United States oil and gas fields (40 fields as of December 31, 2012). We consider any field with discounted future net revenues of 1% or greater of the total discounted future net revenues of all our fields to be significant.

We used our internal estimates of proved reserves for the related disclosures at December 31, 2012. The reports to estimate our proved reserves at December 31, 2011 and 2010 were prepared by an independent reservoir engineering firm.

The following table presents our net ownership interest in proved oil reserves (MBbls) and proved gas reserves, including natural gas liquids (MMcf):


			Total
	Oil	Gas	(MBOE)

Total proved reserves at December 31, 2009 ⁽¹⁾	29,727	399,315	96,280
Revision of previous estimates ^{(1), (2)}	(1,555)	(144,954)	(25,714)
Production	(3,354)	(27,097)	(7,870)
Purchases of reserves in place	-	-	-
Sales of reserves in place	-	-	-
Extensions and discoveries	-	-	-
Total proved reserves at December 31, 2010	24,818	227,264	62,696
Revision of previous estimates ⁽³⁾	3,475	(108,947)	(14,683)
Production	(5,785)	(17,458)	(8,694)
Purchases of reserves in place	-	-	-
Sales of reserves in place	(205)	(4,109)	(890)
Extensions and discoveries	386	271	431
Total proved reserves at December 31, 2011	22,689	97,021	38,860
Revision of previous estimates ⁽⁴⁾	647	(12,926)	(1,508)
Production	(4,725)	(11,361)	(6,619)
Purchases of reserves in place	-	-	-
Sales of reserves in place	(75)	(3,473)	(654)
Extensions and discoveries	1,434	4,026	2,105
Total proved reserves at December 31, 2012	19,970	73,287	32,184

Total proved developed reserves as of:
December 31, 2009	14,850	124,763	35,644
December 31, 2010	11,796	75,664	24,407
December 31, 2011	12,754	59,859	22,731
December 31, 2012	12,431	43,475	19,677

(1) Total proved gas reserves at December 31, 2009 include 12 Bcf associated with the Camelot field in the United Kingdom. The U.K. reserves were reversed in 2010 as a result of our decision to no longer develop the field and to pursue its full abandonment.

(2) Includes an approximate 1.8 MMBbls decrease in oil reserve and an approximate 131 Bcf decrease in gas reserve as reflected in our independent petroleum engineer reserve report at June 30, 2010 resulting from a combination of factors, including well performance issues at certain producing fields, most notably the Bushwood field at Garden Banks Blocks 462/463/506/507, as well as changes in the field economics of other oil and gas properties. The changes in field economics primarily affected properties that were either close to the end of their production life or in which we had proved undeveloped reserves, which would have been required to be developed in the near term. The decision not to develop these properties in light of these economic changes was also driven by our desire to pursue potential alternatives to divest all or a portion of our oil and gas assets and the increasing uncertainties about future oil and gas operations in the Gulf of Mexico as a result of the Macondo well control incident.

(3) The positive revision in oil reserves reflects the better than expected production volumes primarily from the Phoenix field at Green Canyon Blocks 236, 237, 238 and 282 since it began production in October 2010. The decrease in gas reserve primarily represents a reclassification of estimated proved reserves to the probable reserve category following the receipt and interpretation of new seismic data. The field with the largest shift from the proved to probable reserve category was the Bushwood field, where we reclassified approximately 87 Bcf at December 31, 2011.

(4) Decrease primarily represents revisions at several gas fields due to well performance and future capital investment plans.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following table reflects the standardized measure of discounted future net cash flows relating to our interest in proved oil and gas reserves (in thousands):


		United		United
		States		Kingdom		Total
As of December 31, 2012 —
Future cash inflows	$	2,341,354	$	-	$	2,341,354
Future costs:
Production		509,408		-		509,408
Development and abandonment		507,074		2,897		509,971
Total future costs		1,016,482		2,897		1,019,379
Future net cash flows before income taxes		1,324,872		(2,897)		1,321,975
Future income tax expense		330,630		-		330,630
Future net cash flows		994,242		(2,897)		991,345
Discount at 10% annual rate		153,032		-		153,032
Standardized measure of discounted future net cash flows	$	841,210	$	(2,897)	$	838,313


As of December 31, 2011 —
Future cash inflows	$	2,811,956	$	-	$	2,811,956
Future costs:
Production		419,617		-		419,617
Development and abandonment		557,323		27,300		584,623
Total future costs		976,940		27,300		1,004,240
Future net cash flows before income taxes		1,835,016		(27,300)		1,807,716
Future income tax expense		477,630		-		477,630
Future net cash flows		1,357,386		(27,300)		1,330,086
Discount at 10% annual rate		266,954		-		266,954
Standardized measure of discounted future net cash flows	$	1,090,432	$	(27,300)	$	1,063,132


As of December 31, 2010 —
Future cash inflows	$	2,925,744	$	-	$	2,925,744
Future costs:
Production		583,050		-		583,050
Development and abandonment		590,870		12,200		603,070
Total future costs		1,173,920		12,200		1,186,120
Future net cash flows before income taxes		1,751,824		(12,200)		1,739,624
Future income tax expense		430,153		-		430,153
Future net cash flows		1,321,671		(12,200)		1,309,471
Discount at 10% annual rate		318,404		-		318,404
Standardized measure of discounted future net cash flows	$	1,003,267	$	(12,200)	$	991,067

Future cash inflows are computed by applying the appropriate average 12-month commodity prices as based on the price of oil and natural gas on the first day of each month during the year, adjusted for location and quality differentials on a property-by-property basis, to year-end quantities of proved reserves. The discounted future cash flow estimates do not include the effects of our derivative instruments. See the following table for base prices used in determining the standardized measure:


		Year Ended December 31,
		2012		2011		2010

Oil price per Bbl	$	104.85	$	105.35	$	77.55
Natural gas price per Mcf	$	3.38	$	4.34	$	4.40

The future income tax expense was computed by applying the appropriate year-end statutory rates, with consideration of future tax rates already legislated, to the future pretax net cash flows less the tax basis of the associated properties. Future net cash flows are discounted at the prescribed rate of 10%. We caution that actual future net cash flows may vary considerably from these estimates. Although our estimates of total proved reserves, development costs and production rates were based on the best information available, the development and production of oil and gas reserves may not occur in the periods assumed. Actual prices realized, costs incurred and production quantities may vary significantly from those assumed. Therefore, such estimated future net cash flow computations should not be considered to represent our estimate of the expected revenues or the current value of existing proved reserves.

Changes in Standardized Measure of Discounted Future Net Cash Flows

Principal changes in the standardized measure of discounted future net cash flows attributable to our proved oil and gas reserves are as follows (in thousands):


		Year Ended December 31,
		2012		2011		2010

Standardized measure, beginning of year	$	1,063,132	$	991,067	$	991,060
Changes during the year:
Sales, net of production costs		(379,910)		(516,895)		(294,212)
Net change in prices and production costs		(242,037)		414,426		577,687
Changes in future development costs		(65,854)		(108,007)		84,907
Development costs incurred ⁽¹⁾		149,702		168,005		55,646
Accretion of discount		147,157		131,464		129,083
Net change in income taxes		101,720		(54,613)		(41,115)
Purchases of reserves in place		-		-		-
Extensions and discoveries		110,655		29,479		-
Sales of reserves in place		(6,096)		(14,324)		-
Net change due to revision in quantity estimates		28,627		(186,197)		(422,987)
Changes in production rates (timing) and other		(68,783)		208,727		(89,002)
Total		(224,819)		72,065		7
Standardized measure, end of year	$	838,313	$	1,063,132	$	991,067

Derivative Instruments And Hedging Activities

12 Months Ended

Dec. 31, 2012

Derivative Instruments And Hedging Activities [Abstract]

Derivative Instruments And Hedging Activities

Note 17 — Derivative Instruments and Hedging Activities

Derivatives designated as hedging instruments as defined in FASB Codification Topic No. 815 Derivatives in Hedging are as follows (in thousands):


	As of December 31, 2012			As of December 31, 2011
	Balance Sheet		Fair	Balance Sheet		Fair
	Location		Value	Location		Value
Asset Derivatives:
Natural gas contracts	Other current assets	$	-	Other current assets	$	12,957
Oil contracts	Other current assets		-	Other current assets		8,567
Natural gas contracts	Other assets, net		-	Other assets, net		857
Interest rate swaps	Other assets, net		-	Other assets, net		327
		$	-		$	22,708

Liability Derivatives:
Oil contracts	Accrued liabilities	$	-	Accrued liabilities	$	886
Interest rate swaps	Accrued liabilities		-	Accrued liabilities		202
Oil contracts	Other long-term liabilities		-	Other long-term liabilities		1,712
		$	-		$	2,800

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


	As of December 31, 2012			As of December 31, 2011
	Balance Sheet		Fair	Balance Sheet		Fair
	Location		Value	Location		Value
Asset Derivatives:
Oil contracts	Other current assets	$	5,800	Other current assets	$	-
Foreign exchange forwards	Other current assets		146	Other current assets		55
		$	5,946		$	55

Liability Derivatives:
Oil contracts	Accrued liabilities	$	15,777	Accrued liabilities	$	-
Interest rate swaps	Accrued liabilities		489	Accrued liabilities		-
Foreign exchange forwards	Accrued liabilities		-	Accrued liabilities		159
Interest rate swaps	Other long-term liabilities		32	Other long-term liabilities		-
		$	16,298		$	159

As a result of recent declines in natural gas production from our properties, including the effects Hurricane Isaac had on our properties in August 2012, sales of certain of our natural gas producing properties and the continued deferral of initiating production from our Nancy well in the Bushwood field, we de-designated four of our natural gas derivative contracts as hedging instruments. We concluded that these contracts no longer qualified for hedge accounting treatment because we could no longer forecast that we would have the necessary production volumes to cover the volumes in these contracts. All four of these contracts were settled as of December 31, 2012. The mark-to-market adjustments associated with these contracts are recorded as a component of “Income (loss) from discontinued operations, net of tax” in the accompanying consolidated statements of operations.

As a result of the announcement of the sale of ERT, we de-designated all of our remaining oil and natural gas derivative contracts as hedging instruments. In addition, under the terms of our Credit Agreement (Note 7), we are required to use at a minimum 60% of the after-tax proceeds from the sales of the Caesar, the Express and ERT to make payments to reduce our Term Loan debt and borrowings under the Revolving Credit Facility. Because it is probable that we will pay off the Term Loan debt before the expiration of our interest rate swaps, we also concluded that the swaps no longer qualified as cash flow hedges. At December 31, 2012, we recorded the mark-to-market adjustments for these derivatives to reflect the changes in their fair values and to recognize amounts previously recorded in accumulated other comprehensive income (loss) and related deferred taxes into earnings. The mark-to-market adjustments related to our commodity derivative contracts and interest rate swaps are reflected in “Non-hedge loss on commodity derivative contracts” and “Other income (expense), net”, respectively, in the accompanying consolidated statements of operations. In February 2013, we settled all of our remaining commodity derivative contracts and interest rate swap contracts for approximately $22.5 million and $0.6 million, respectively.

The following tables present the impact that derivative instruments designated as cash flow hedges had on our accumulated comprehensive income (loss) and our consolidated statements of operations for the years ended December 31, 2012, 2011 and 2010 (in thousands). The amount of any ineffectiveness associated with our oil contracts was immaterial for the years ended December 31, 2012, 2011 and 2010. These amounts are reflected in “Income (loss) from discontinued operations, net of tax” in the accompanying consolidated statements of operations. Ineffectiveness associated with our interest rate swaps was immaterial for all periods presented.


		Gain (Loss) Recognized in OCI on Derivatives
		(Effective Portion)
		Year Ended December 31,
		2012		2011		2010

Oil and natural gas commodity contracts	$	(12,860)	$	28,749	$	(6,486)
Interest rate swaps		(81)		1,294		(1,213)
	$	(12,941)	$	30,043	$	(7,699)


			Gain (Loss) Reclassified from
	Reclassified from		Accumulated OCI into Income
	Location of Gain (Loss)		(Effective Portion)
	Accumulated OCI into Income		Year Ended December 31,
	(Effective Portion)		2012		2011		2010

Oil and natural gas commodity contracts	Income (loss) from discontinued operations, net of tax	$	3,184	$	(21,659)	$	25,575
Interest rate swaps	Net interest expense		(523)		(2,010)		(1,849)
		$	2,661	$	(23,669)	$	23,726

The following table presents the impact that derivative instruments not designated as hedges had on our consolidated statement of operations for the years ended December 31, 2012, 2011 and 2010 (in thousands):


			Gain (Loss) Recognized in Income
	Location of Gain (Loss)		on Derivatives
	Recognized in Income		Year Ended December 31,
	on Derivatives		2012		2011		2010

Oil and natural gas commodity contracts	Income (loss) from discontinued operations, net of tax	$	5,550	$	-	$	1,088
Oil and natural gas commodity contracts	Non-hedge loss on commodity derivative contracts		(10,507)		-		-
Interest rate swaps	Other income (expense), net		(567)		-		-
Foreign exchange forwards	Other income (expense), net		411		249		(2,560)
		$	(5,113)	$	249	$	(1,472)

The entire disclosure for the entity's entire derivative instruments and hedging activities. Describes an entity's risk management strategies, derivatives in hedging activities and non-hedging derivative instruments, the assets, obligations, liabilities, revenues and expenses arising therefrom, and the amounts of and methodologies and assumptions used in determining the amounts of such items.

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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 22: http://www.xbrl.org/2003/role/presentationRef
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Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Information

12 Months Ended

Dec. 31, 2012

Quarterly Financial Information

Note 18 — Quarterly Financial Information (Unaudited)

The offshore marine construction industry in the Gulf of Mexico is highly seasonal as a result of weather conditions and the timing of capital expenditures by oil and gas companies. Historically, a substantial portion of our services has been performed during the summer and fall months. As a result, historically a disproportionate portion of our revenues and net income is earned during such period. The following is a summary of consolidated quarterly financial information for 2012 and 2011 (in thousands, except per share data):


		Quarter Ended
		March 31,		June 30,		September 30,		December 31,
2012
Net revenues ⁽¹⁾	$	229,842	$	197,461	$	217,110	$	201,696
Gross profit (loss) ⁽²⁾		72,483		28,438		57,919		(108,925)
Net income (loss)		65,737		44,651		14,875		(171,560)
Net income (loss) applicable to common shareholders:
Income (loss) from continuing operations	$	16,874	$	2,425	$	10,362	$	(99,679)
Income (loss) from discontinued operations ⁽³⁾		48,853		42,216		4,503		(71,888)
Net income (loss) applicable to common shareholders	$	65,727	$	44,641	$	14,865	$	(171,567)
Basic earnings (loss) per common share:
Income (loss) from continuing operations	$	0.16	$	0.02	$	0.10	$	(0.95)
Income (loss) from discontinued operations		0.46		0.40		0.04		(0.69)
Basic earnings (loss) per common share	$	0.62	$	0.42	$	0.14	$	(1.64)
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	0.16	$	0.02	$	0.10	$	(0.95)
Income (loss) from discontinued operations		0.46		0.40		0.04		(0.69)
Diluted earnings (loss) per common share	$	0.62	$	0.42	$	0.14	$	(1.64)


		Quarter Ended
		March 31,		June 30,		September 30,		December 31,
2011
Net revenues ⁽⁴⁾	$	122,748	$	165,861	$	213,278	$	200,113
Gross profit ⁽⁵⁾		14,395		44,043		64,972		26,273
Net income ⁽⁶⁾		25,867		41,323		46,026		16,763
Net income applicable to common shareholders:
Income (loss) from continuing operations	$	(9,315)	$	10,547	$	15,999	$	17,487
Income (loss) from discontinued operations		35,172		30,766		30,017		(734)
Net income applicable to common shareholders	$	25,857	$	41,313	$	46,016	$	16,753
Basic earnings per common share:
Income (loss) from continuing operations	$	(0.09)	$	0.10	$	0.15	$	0.17
Income (loss) from discontinued operations		0.33		0.29		0.28		(0.01)
Basic earnings per common share	$	0.24	$	0.39	$	0.43	$	0.16
Diluted earnings per common share:
Income (loss) from continuing operations	$	(0.09)	$	0.10	$	0.15	$	0.17
Income (loss) from discontinued operations		0.33		0.29		0.29		(0.01)
Diluted earnings per common share	$	0.24	$	0.39	$	0.44	$	0.16

(1) Excludes revenues from discontinued operations of $178.1 million, $149.9 million, $119.1 million and $110.1 million for the quarters ended March 31, June 30, September 30 and December 31, 2012.

(2) Excludes gross profit (loss) from discontinued operations of $89.2 million, $64.8 million, $27.8 million and $(102.6) million for the quarters ended March 31, June 30, September 30 and December 31, 2012. Includes impairment charges totaling $14.6 million in the second quarter of 2012, $4.6 million in the third quarter of 2012 and $158.0 million in the fourth quarter of 2012 (Note 2).

(3) Our net loss in the fourth quarter of 2012 includes a $138.6 million impairment charge associated with the sale of ERT (Note 3).

(4) Excludes revenues from discontinued operations of $168.9 million, $172.5 million, $159.2 million and $196.1 million for the quarters ended March 31, June 30, September 30 and December 31, 2011.

(5) Excludes gross profit from discontinued operations of $62.7 million, $56.2 million, $57.3 million and $4.8 million for the quarters ended March 31, June 30, September 30 and December 31, 2011. The fourth quarter includes a $6.6 million impairment charge to reduce our Australian well intervention equipment to its estimated fair value at December 31, 2011.

(6) Our net income in the fourth quarter of 2011 includes a $10.6 million other than temporary impairment loss on our equity investment in our Australian joint venture (Note 5). The fourth quarter also includes a $31.3 million tax benefit related to reorganization of our Australian well intervention operations.

The entire disclosure for the quarterly financial data in the annual financial statements. The disclosure may include a tabular presentation of financial information for each fiscal quarter for the current and previous year, including revenues, gross profit, income or loss before extraordinary items and earnings per share data. It also includes an indication if the information in the note is unaudited, comments on the aggregate effect of year-end adjustments, and an explanation of matters or transactions that affect comparability or are pertinent to an understanding of the information furnished.

Condensed Consolidated Guarantor And Non-Guarantor Financial Information [Abstract]

Condensed Consolidated Guarantor And Non-Guarantor Financial Information

12 Months Ended

Dec. 31, 2012

Condensed Financial Statements

Note 19 — 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 reported based 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 primarily relate to the elimination of investments in subsidiaries and associated intercompany balances and transactions.

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(in thousands)


		As of December 31, 2012
						Non-		Consolidating
		Helix		Guarantors		Guarantors		Entries		Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	381,599	$	4,436	$	51,065	$	-	$	437,100
Accounts receivable, net		39,203		37,378		75,652		-		152,233
Unbilled revenue		13,959		875		19,006		-		33,840
Income taxes receivable		24,611		-		306		(10,716)		14,201
Other current assets		54,588		16,418		11,696		31		82,733
Current assets of discontinued operations		-		84,000		-		-		84,000
Total current assets		513,960		143,107		157,725		(10,685)		804,107
Intercompany		(154,756)		352,210		(125,889)		(71,565)		-
Property and equipment, net		208,190		351,746		930,556		(4,617)		1,485,875
Other assets:
Equity investments in unconsolidated affiliates		-		-		167,599		-		167,599
Equity investments in affiliates		1,762,359		53,461		-		(1,815,820)		-
Goodwill		-		45,107		17,828		-		62,935
Other assets, net		47,355		130		34,848		(32,496)		49,837
Due from subsidiaries/parent		294,461		485,096		-		(779,557)		-
Non-current assets of discontinued operations		-		816,227		-		-		816,227
Total assets	$	2,671,569	$	2,247,084	$	1,182,667	$	(2,714,740)	$	3,386,580

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	45,784	$	17,229	$	29,385	$	-	$	92,398
Accrued liabilities		117,902		26,019		17,593		-		161,514
Income taxes payable		-		26,618		-		(26,618)		-
Current maturities of long-term debt		11,487		-		5,120		-		16,607
Current liabilities of discontinued operations		-		182,527		-		-		182,527
Total current liabilities		175,173		252,393		52,098		(26,618)		453,046
Long-term debt		902,453		-		100,168		-		1,002,621
Deferred tax liabilities		168,688		86,925		109,171		(5,547)		359,237
Other long-term liabilities		1,453		3,086		486		-		5,025
Due to parent		-		-		323,049		(323,049)		-
Non-current liabilities of discontinued operations		-		147,237		-		-		147,237
Total liabilities		1,247,767		489,641		584,972		(355,214)		1,967,166
Convertible preferred stock		-		-		-		-		-
Total equity		1,423,802		1,757,443		597,695		(2,359,526)		1,419,414
Total liabilities and shareholders' equity	$	2,671,569	$	2,247,084	$	1,182,667	$	(2,714,740)	$	3,386,580

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(in thousands)


		As of December 31, 2011
						Non-		Consolidating
		Helix		Guarantors		Guarantors		Entries		Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	495,484	$	2,432	$	48,547	$	-	$	546,463
Accounts receivable, net		79,290		26,885		41,724		-		147,899
Unbilled revenue		10,530		155		26,690		-		37,375
Income taxes receivable		80,388		-		-		(80,388)		-
Other current assets		68,627		20,624		10,159		(5,826)		93,584
Current assets of discontinued operations		-		118,921		-		-		118,921
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		550,668		682,899		(4,844)		1,459,669
Other assets:
Equity investments in unconsolidated affiliates		-		-		175,656		-		175,656
Equity investments in affiliates		1,952,392		37,239		-		(1,989,631)		-
Goodwill		-		45,107		17,108		-		62,215
Other assets, net		53,425		2,712		16,809		(37,780)		35,166
Due from subsidiaries/parent		64,655		430,496		-		(495,151)		-
Non-current assets of discontinued operations		-		905,399		-		-		905,399
Total assets	$	2,888,550	$	2,456,459	$	916,766	$	(2,679,428)	$	3,582,347

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	39,280	$	9,626	$	25,013	$	-	$	73,919
Accrued liabilities		115,921		3,841		26,350		-		146,112
Income taxes payable		-		97,692		217		(96,616)		1,293
Current maturities of long-term debt		3,000		-		10,377		(5,500)		7,877
Current liabilities of discontinued operations		-		166,975		-		-		166,975
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 tax liabilities		231,255		88,625		103,552		(5,822)		417,610
Other long-term liabilities		4,150		4,647		571		-		9,368
Due to parent		-		-		98,285		(98,285)		-
Non-current liabilities of discontinued operations		-		161,208		-		-		161,208
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
Total liabilities and shareholders' equity	$	2,888,550	$	2,456,459	$	916,766	$	(2,679,428)	$	3,582,347

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

AND COMPREHENSIVE INCOME (LOSS)

(in thousands)


		Year Ended December 31, 2012
						Non-		Consolidating
		Helix		Guarantors		Guarantors		Entries		Consolidated

Net revenues	$	90,552	$	404,628	$	464,331	$	(113,402)	$	846,109
Cost of sales		111,531		444,956		351,283		(111,576)		796,194
Gross profit (loss)		(20,979)		(40,328)		113,048		(1,826)		49,915
Loss on sale of assets, net		-		(13,475)		(1)		-		(13,476)
Non-hedge loss on commodity derivative contracts		-		(10,507)		-		-		(10,507)
Selling, general and administrative expenses		(53,539)		(22,782)		(20,018)		1,924		(94,415)
Income (loss) from operations		(74,518)		(87,092)		93,029		98		(68,483)
Equity in earnings of investments		(12,264)		16,222		8,434		(3,958)		8,434
Net interest expense and other		(59,759)		392		(6,517)		(28)		(65,912)
Income (loss) before income taxes		(146,541)		(70,478)		94,946		(3,888)		(125,961)
Income tax provision (benefit)		(96,328)		24,186		12,951		33		(59,158)
Income (loss) from continuing operations		(50,213)		(94,664)		81,995		(3,921)		(66,803)
Income (loss) from discontinued operations, net of tax		(1,621)		25,305		-		-		23,684
Net income (loss) applicable to Helix		(51,834)		(69,359)		81,995		(3,921)		(43,119)
Net income applicable to noncontrolling interests		-		-		-		(3,178)		(3,178)
Preferred stock dividends		(37)		-		-		-		(37)
Net income (loss) applicable to Helix common shareholders	$	(51,871)	$	(69,359)	$	81,995	$	(7,099)	$	(46,334)

Total comprehensive income (loss) applicable to Helix common shareholders	$	(51,952)	$	(82,219)	$	89,260	$	(7,073)	$	(51,984)


		Year Ended December 31, 2011
						Non-		Consolidating
		Helix		Guarantors		Guarantors		Entries		Consolidated

Net revenues	$	84,748	$	362,648	$	367,114	$	(112,510)	$	702,000
Cost of sales		72,902		281,267		309,429		(111,281)		552,317
Gross profit		11,846		81,381		57,685		(1,229)		149,683
Loss on sale of assets, net		(6)		-		-		-		(6)
Selling, general and administrative expenses		(74,205)		(25,963)		12,101		1,430		(86,637)
Income (loss) from operations		(62,365)		55,418		69,786		201		63,040
Equity in earnings of investments		262,990		7,340		22,215		(270,330)		22,215
Other than temporary loss on equity investments		-		-		(10,563)		-		(10,563)
Net interest expense and other		(157,546)		(6,787)		67,181		23,510		(73,642)
Income (loss) before income taxes		43,079		55,971		148,619		(246,619)		1,050
Income tax provision (benefit)		(63,242)		18,181		8,186		69		(36,806)
Income (loss) from continuing operations		106,321		37,790		140,433		(246,688)		37,856
Income from discontinued operations, net of tax		-		95,221		-		-		95,221
Net income (loss) applicable to Helix		106,321		133,011		140,433		(246,688)		133,077
Net income applicable to noncontrolling interests		-		-		-		(3,098)		(3,098)
Preferred stock dividends		(40)		-		-		-		(40)
Net income (loss) applicable to Helix common shareholders	$	106,281	$	133,011	$	140,433	$	(249,786)	$	129,939

Total comprehensive income (loss) applicable to Helix common shareholders	$	107,575	$	161,760	$	140,214	$	(250,569)	$	158,980

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

AND COMPREHENSIVE INCOME (LOSS)

(in thousands)


		Year Ended December 31, 2010
						Non-		Consolidating
		Helix		Guarantors		Guarantors		Entries		Consolidated

Net revenues	$	183,147	$	376,134	$	334,726	$	(119,538)	$	774,469
Cost of sales		124,722		287,709		302,051		(104,830)		609,652
Gross profit		58,425		88,425		32,675		(14,708)		164,817
Goodwill impairment		-		-		(16,743)		-		(16,743)
Gain on sale of assets, net		3,159		-		5,959		-		9,118
Selling, general and administrative expenses		(67,165)		(18,268)		(22,482)		1,802		(106,113)
Loss from operations		(5,581)		70,157		(591)		(12,906)		51,079
Equity in earnings of investments		(60,443)		8,473		19,469		51,970		19,469
Other than temporary loss on equity investments		(2,240)		-		-		-		(2,240)
Net interest expense and other		(59,522)		(1,991)		(5,125)		-		(66,638)
Income (loss) before income taxes		(127,786)		76,639		13,753		39,064		1,670
Income tax provision (benefit)		(9,175)		23,465		9,405		(4,529)		19,166
Income (loss) from continuing operations		(118,611)		53,174		4,348		43,593		(17,496)
Loss from discontinued operations, net of tax		-		(106,657)		-		-		(106,657)
Net income (loss) applicable to Helix		(118,611)		(53,483)		4,348		43,593		(124,153)
Net income applicable to noncontrolling interests		-		-		-		(2,835)		(2,835)
Preferred stock dividends		(114)		-		-		-		(114)
Net income (loss) applicable to Helix common shareholders	$	(118,725)	$	(53,483)	$	4,348	$	40,758	$	(127,102)

Total comprehensive income (loss) applicable to Helix common shareholders	$	(119,051)	$	(59,969)	$	(5,653)	$	40,754	$	(143,919)

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(in thousands)


		Year Ended December 31, 2012
						Non-		Consolidating
		Helix		Guarantors		Guarantors		Entries		Consolidated
Cash flows from operating activities:
Net income (loss), including noncontrolling interests	$	(51,834)	$	(69,359)	$	81,995	$	(3,921)	$	(43,119)
Adjustments to reconcile net income (loss), including noncontrolling interests to net cash provided by (used in) operating activities:
Equity in earnings of affiliates		12,264		(16,222)		-		3,958		-
Other adjustments		106,022		126,672		6,349		(19,856)		219,187
Cash provided by (used in) operating activities		66,452		41,091		88,344		(19,819)		176,068
Cash provided by discontinued operations		1,621		274,809		-		-		276,430
Net cash provided by (used in) operating activities		68,073		315,900		88,344		(19,819)		452,498

Cash flows from investing activities:
Capital expenditures		(2,422)		(38,197)		(282,420)		-		(323,039)
Distributions from equity investments, net		-		-		7,797		-		7,797
Proceeds from sale of assets		-		19,530		-		-		19,530
Cash used in investing activities		(2,422)		(18,667)		(274,623)		-		(295,712)
Cash used in discontinued operations		-		(120,057)		-		-		(120,057)
Net cash used in investing activities		(2,422)		(138,724)		(274,623)		-		(415,769)

Cash flows from financing activities:
Borrowings of debt		400,000		-		-		-		400,000
Repayments of debt		(520,357)		-		(4,877)		-		(525,234)
Deferred financing costs		(7,580)		-		-		-		(7,580)
Distributions to noncontrolling interests		-		-		(5,287)		-		(5,287)
Repurchases of common stock		(7,197)		-		-		-		(7,197)
Excess tax from stock-based compensation		(1,186)		-		-		-		(1,186)
Exercise of stock options, net and other		1,252		-		-		-		1,252
Intercompany financing		(44,468)		(175,172)		199,821		19,819		-
Net cash provided by (used in) financing activities		(179,536)		(175,172)		189,657		19,819		(145,232)

Effect of exchange rate changes on cash and cash equivalents		-		-		(860)		-		(860)
Net increase (decrease) in cash and cash equivalents		(113,885)		2,004		2,518		-		(109,363)
Cash and cash equivalents:
Balance, beginning of year		495,484		2,434		48,547		-		546,465
Balance, end of year		381,599		4,438		51,065		-		437,102
Less cash from discontinued operations, end of year		-		2		-		-		2
Cash from continuing operations, end of year	$	381,599	$	4,436	$	51,065	$	-	$	437,100

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(in thousands)


		Year Ended December 31, 2011
						Non-		Consolidating
		Helix		Guarantors		Guarantors		Entries		Consolidated
Cash flows from operating activities:
Net income (loss), including noncontrolling interests	$	106,321	$	133,011	$	140,433	$	(246,688)	$	133,077
Adjustments to reconcile net income (loss), including noncontrolling interests to net cash provided by (used in) operating activities:
Equity in earnings of affiliates		(262,990)		(7,340)		-		270,330		-
Other adjustments		39,860		(30,770)		40,293		198		49,581
Cash provided by (used in) operating activities		(116,809)		94,901		180,726		23,840		182,658
Cash provided by discontinued operations		-		384,498		-		-		384,498
Net cash provided by (used in) operating activities		(116,809)		479,399		180,726		23,840		567,156

Cash flows from investing activities:
Capital expenditures		(32,417)		(55,124)		(12,613)		-		(100,154)
Distributions from equity investments, net		-		-		1,266		-		1,266
Proceeds from sale of Cal Dive common stock		3,588		-		-		-		3,588
Cash used in investing activities		(28,829)		(55,124)		(11,347)		-		(95,300)
Cash used in discontinued operations		-		(87,017)		-		-		(87,017)
Net cash used in investing activities		(28,829)		(142,141)		(11,347)		-		(182,317)

Cash flows from financing activities:
Borrowings of debt		109,400		-		-		-		109,400
Repayments of debt		(317,485)		-		(4,645)		-		(322,130)
Deferred financing costs		(9,311)		-		-		-		(9,311)
Repurchases of common stock		(7,604)		-		-		-		(7,604)
Excess tax from stock-based compensation		(1,013)		-		-		-		(1,013)
Exercise of stock options, net and other		1,978		-		(1,215)		-		763
Intercompany financing		488,723		(338,118)		(126,765)		(23,840)		-
Net cash provided by (used in) financing activities		264,688		(338,118)		(132,625)		(23,840)		(229,895)

Effect of exchange rate changes on cash and cash equivalents		-		-		436		-		436
Net increase (decrease) in cash and cash equivalents		119,050		(860)		37,190		-		155,380
Cash and cash equivalents:
Balance, beginning of year		376,434		3,294		11,357		-		391,085
Balance, end of year		495,484		2,434		48,547		-		546,465
Less cash from discontinued operations, end of year		-		2		-		-		2
Cash from continuing operations, end of year	$	495,484	$	2,432	$	48,547	$	-	$	546,463

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(in thousands)


		Year Ended December 31, 2010
						Non-		Consolidating
		Helix		Guarantors		Guarantors		Entries		Consolidated
Cash flows from operating activities:
Net income (loss), including noncontrolling interests	$	(118,611)	$	(53,483)	$	4,348	$	43,593	$	(124,153)
Adjustments to reconcile net income (loss), including noncontrolling interests to net cash provided by (used in) operating activities:
Equity in earnings of affiliates		60,443		(8,473)		-		(51,970)		-
Other adjustments		94,376		45,567		76,865		(21,283)		195,525
Cash provided by (used in) operating activities		36,208		(16,389)		81,213		(29,660)		71,372
Cash provided by discontinued operations		-		260,082		-		-		260,082
Net cash provided by (used in) operating activities		36,208		243,693		81,213		(29,660)		331,454

Cash flows from investing activities:
Capital expenditures		(56,650)		(37,155)		(28,413)		-		(122,218)
Distributions from equity investments, net		-		-		2,286		-		2,286
Proceeds from insurance reimbursement		7,020		-		-		-		7,020
Proceeds from sale of assets		6,042		-		-		-		6,042
Cash used in investing activities		(43,588)		(37,155)		(26,127)		-		(106,870)
Cash used in discontinued operations		-		(74,686)		-		-		(74,686)
Net cash used in investing activities		(43,588)		(111,841)		(26,127)		-		(181,556)

Cash flows from financing activities:
Repayments of debt		(4,326)		-		(4,424)		-		(8,750)
Deferred financing costs		(2,947)		-		-		-		(2,947)
Repurchases of common stock		(11,680)		-		-		-		(11,680)
Excess tax from stock-based compensation		(3,945)		-		-		-		(3,945)
Exercise of stock options, net and other		560		-		(2,517)		-		(1,957)
Intercompany financing		147,410		(131,080)		(45,990)		29,660		-
Net cash provided by (used in) financing activities		125,072		(131,080)		(52,931)		29,660		(29,279)

Effect of exchange rate changes on cash and cash equivalents		-		-		(207)		-		(207)
Net increase in cash and cash equivalents		117,692		772		1,948		-		120,412
Cash and cash equivalents:
Balance, beginning of year		258,742		2,522		9,409		-		270,673
Balance, end of year		376,434		3,294		11,357		-		391,085
Less cash from discontinued operations, end of year		-		1		-		-		1
Cash from continuing operations, end of year	$	376,434	$	3,293	$	11,357	$	-	$	391,084

Summary Of Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2012

Accounting Policies [Abstract]

Principles of Consolidation

Use of Estimates

Cash and Cash Equivalents

Cash and cash equivalents are highly liquid financial instruments with original maturities of three months or less. They are carried at cost plus accrued interest, which approximates fair value.

Statement Of Cash Flow Information

Statement of Cash Flow Information

The following table provides supplemental cash flow information for the periods stated (in thousands):


		Year Ended December 31,
		2012		2011		2010

Interest paid, net of interest capitalized	$	68,735	$	81,000	$	68,534
Income taxes paid	$	43,111	$	11,216	$	10,071

Accounts Receivable and Allowance for Uncollectible Accounts

Property and Equipment


	Estimated Useful Life		2012		2011

ROVs/Vessels	10 to 30 years	$	1,822,642	$	1,616,772
Machinery, equipment, buildings and leasehold improvements	5 to 30 years		229,154		198,240
Total property and equipment		$	2,051,796	$	1,815,012

Equity Investments

Goodwill and Other Intangible Assets

The changes in the carrying amount of goodwill are as follows (in thousands):


Balance at December 31, 2010 ⁽¹⁾	$	62,494
Other adjustments ⁽²⁾		(279)
Balance at December 31, 2011		62,215
Other adjustments ⁽²⁾		720
Balance at December 31, 2012	$	62,935

(1) In 2010, we fully impaired $16.7 million of goodwill associated with our Australian well intervention subsidiary (“WOSEA”) (see below).

(2) Reflects foreign currency adjustment for certain amounts of our goodwill.

Recertification Costs and Deferred Dry Dock Charges

Convertible Preferred Stock Policy

Convertible Preferred Stock

Revenue Recognition

	•		the customer provides specifications for the construction of facilities or for the provision of related services;
	•		we can reasonably estimate our progress towards completion and our costs;
	•		the contract includes provisions as to the enforceable rights regarding the goods or services to be provided, consideration to be received, and the manner and terms of payment;
	•		the customer can be expected to satisfy its obligations under the contract; and
	•		we can be expected to perform our contractual obligations.

Income Taxes

Foreign Currency

Derivative Instruments and Hedging Activities

Interest Rate Risk

Foreign Currency Exchange Rate Risk

See Note 17 for more information regarding the accounting for our derivative contracts including our commodity contracts associated with ERT.

Earnings Per Share


		Year Ended December 31,
		2012			2011			2010
		Income	Shares		Income	Shares		Income	Shares
Basic:
Net income (loss) applicable to Helix common shareholders	$	(46,334)		$	129,939		$	(127,102)
Less: Undistributed net income allocable to participating securities		-			(1,599)			-
Undistributed net income (loss) applicable to common shareholders		(46,334)			128,340			(127,102)
Less: (Income) loss from discontinued operations, net of tax		(23,684)			(95,221)			106,657
Add: Undistributed net income from discontinued operations allocable to participating securities		-			1,172			-
Income (loss) from continuing operations applicable to Helix common shareholders	$	(70,018)	104,449	$	34,291	104,528	$	(20,445)	103,857


Diluted:
Income (loss) from continuing operations applicable to Helix common shareholders - Basic	$	(70,018)	104,449	$	34,291	104,528	$	(20,445)	103,857
Effect of dilutive securities:
Share-based awards other than participating securities		-	-		-	64		-	-
Undistributed net income reallocated to participating securities		-	-		2	-		-	-
Convertible preferred stock		-	-		40	361		-	-
Income (loss) from continuing operations applicable to Helix common shareholders - Diluted		(70,018)			34,333			(20,445)
Income (loss) from discontinued operations, net of tax		23,684			95,221			(106,657)
Net income (loss) applicable to Helix common shareholders - Diluted	$	(46,334)	104,449	$	129,554	104,953	$	(127,102)	103,857


	2012	2010

Diluted shares (as reported)	104,449	103,857
Share-based awards	382	466
Convertible preferred stock	334	1,015
Total	105,165	105,338

Major Customers and Concentration of Credit Risk

Fair Value Measurements


	•		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).


		Level 1		Level 2 ⁽¹⁾		Level 3		Total	Valuation Technique
Assets:
Oil contracts	$	–	$	5,800	$	–	$	5,800	(c)
Foreign currency forwards		–		146		–		146	(c)

Liabilities:
Oil contracts		–		15,777		–		15,777	(c)
Fair value of long-term debt ⁽²⁾		994,311		123,187		–		1,117,498	(a)
Interest rate swaps		–		521		–		521	(c)
Total net liability	$	994,311	$	133,539	$	–	$	1,127,850

(2) See Note 7 for additional information regarding our long-term debt. The fair value of our long-term debt at December 31, 2012 and 2011 is as follows:


		2012				2011
		Carrying Value		Fair Value		Carrying Value		Fair Value

Term Loans (mature July 2015) ^(a)	$	367,181	$	368,295	$	279,750	$	279,750
Revolving Credit Facility (matures July 2015) ^(a)		100,000		100,000		-		-
2025 Notes (mature December 2025) ^(b)		3,487		3,487		300,000		300,543
2032 Notes (mature March 2032) ^(c)		200,000		239,320		-		-
Senior Unsecured Notes (mature January 2016)		274,960		283,209		474,960		501,083
MARAD Debt (matures February 2027) ^(d)		105,288		123,187		110,166		124,488
Total debt	$	1,050,916	$	1,117,498	$	1,164,876	$	1,205,864

(a) In February 2013, we repaid $293.9 million of our Term Loans and $24.5 million under our Revolving Credit Facility with the after-tax proceeds from the sale of ERT.

(b) Carrying value excludes the related unamortized debt discount of $9.6 million at December 31, 2011. This remaining amount was repurchased by us in February 2013.

Debt Discount

Investment Available for Sale

New Accounting Pronouncements, Policy [Policy Text Block]

New Accounting Standards

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2012

Accounting Policies [Abstract]

Supplemental Cash Flow Information


		Year Ended December 31,
		2012		2011		2010

Interest paid, net of interest capitalized	$	68,735	$	81,000	$	68,534
Income taxes paid	$	43,111	$	11,216	$	10,071

Property, Plant and Equipment


	Estimated Useful Life		2012		2011

ROVs/Vessels	10 to 30 years	$	1,822,642	$	1,616,772
Machinery, equipment, buildings and leasehold improvements	5 to 30 years		229,154		198,240
Total property and equipment		$	2,051,796	$	1,815,012

Schedule of Goodwill


Balance at December 31, 2010 ⁽¹⁾	$	62,494
Other adjustments ⁽²⁾		(279)
Balance at December 31, 2011		62,215
Other adjustments ⁽²⁾		720
Balance at December 31, 2012	$	62,935

(1) In 2010, we fully impaired $16.7 million of goodwill associated with our Australian well intervention subsidiary (“WOSEA”) (see below).

(2) Reflects foreign currency adjustment for certain amounts of our goodwill.

Computations Of Basic And Diluted EPS


		Year Ended December 31,
		2012			2011			2010
		Income	Shares		Income	Shares		Income	Shares
Basic:
Net income (loss) applicable to Helix common shareholders	$	(46,334)		$	129,939		$	(127,102)
Less: Undistributed net income allocable to participating securities		-			(1,599)			-
Undistributed net income (loss) applicable to common shareholders		(46,334)			128,340			(127,102)
Less: (Income) loss from discontinued operations, net of tax		(23,684)			(95,221)			106,657
Add: Undistributed net income from discontinued operations allocable to participating securities		-			1,172			-
Income (loss) from continuing operations applicable to Helix common shareholders	$	(70,018)	104,449	$	34,291	104,528	$	(20,445)	103,857


Diluted:
Income (loss) from continuing operations applicable to Helix common shareholders - Basic	$	(70,018)	104,449	$	34,291	104,528	$	(20,445)	103,857
Effect of dilutive securities:
Share-based awards other than participating securities		-	-		-	64		-	-
Undistributed net income reallocated to participating securities		-	-		2	-		-	-
Convertible preferred stock		-	-		40	361		-	-
Income (loss) from continuing operations applicable to Helix common shareholders - Diluted		(70,018)			34,333			(20,445)
Income (loss) from discontinued operations, net of tax		23,684			95,221			(106,657)
Net income (loss) applicable to Helix common shareholders - Diluted	$	(46,334)	104,449	$	129,554	104,953	$	(127,102)	103,857

Excluded Securities On Diluted Shares Calculation


	2012	2010

Diluted shares (as reported)	104,449	103,857
Share-based awards	382	466
Convertible preferred stock	334	1,015
Total	105,165	105,338

Assets And Liabilities Measured At Fair Value On A Recurring Basis

		Level 1		Level 2 ⁽¹⁾		Level 3		Total	Valuation Technique
Assets:
Oil contracts	$	–	$	5,800	$	–	$	5,800	(c)
Foreign currency forwards		–		146		–		146	(c)

Liabilities:
Oil contracts		–		15,777		–		15,777	(c)
Fair value of long-term debt ⁽²⁾		994,311		123,187		–		1,117,498	(a)
Interest rate swaps		–		521		–		521	(c)
Total net liability	$	994,311	$	133,539	$	–	$	1,127,850

(2) See Note 7 for additional information regarding our long-term debt. The fair value of our long-term debt at December 31, 2012 and 2011 is as follows:

Fair Value Of Long Term Debt


		2012				2011
		Carrying Value		Fair Value		Carrying Value		Fair Value

Term Loans (mature July 2015) ^(a)	$	367,181	$	368,295	$	279,750	$	279,750
Revolving Credit Facility (matures July 2015) ^(a)		100,000		100,000		-		-
2025 Notes (mature December 2025) ^(b)		3,487		3,487		300,000		300,543
2032 Notes (mature March 2032) ^(c)		200,000		239,320		-		-
Senior Unsecured Notes (mature January 2016)		274,960		283,209		474,960		501,083
MARAD Debt (matures February 2027) ^(d)		105,288		123,187		110,166		124,488
Total debt	$	1,050,916	$	1,117,498	$	1,164,876	$	1,205,864

(a) In February 2013, we repaid $293.9 million of our Term Loans and $24.5 million under our Revolving Credit Facility with the after-tax proceeds from the sale of ERT.

(b) Carrying value excludes the related unamortized debt discount of $9.6 million at December 31, 2011. This remaining amount was repurchased by us in February 2013.

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

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-Number 210
-Section 02
-Paragraph 22
-Article 5

Tabular disclosure of goodwill by reportable segment and in total which includes a rollforward schedule.

Changes In Asset Retirement Obligations

Oil And Gas Properties (Tables)

12 Months Ended

Dec. 31, 2012

Oil And Gas Properties [Abstract]


		2012		2011
Asset retirement obligations at January 1,	$	227,090	$	222,653
Liability incurred during the period		3,664		4,982
Liability settled during the period		(105,160)		(37,769)
Other revisions in estimated cash flows ⁽¹⁾		62,834		22,345
Accretion expense (included in depreciation and amortization)		12,550		14,879
Asset retirement obligations at December 31,	$	200,978	$	227,090

Results of Operations for Oil and Gas Producing Activities Disclosure


		Year Ended December 31,
		2012		2011		2010

Revenues	$	557,231	$	696,607	$	425,369
Costs:
Production (lifting) costs		164,663		176,269		131,156
Hurricane repair expense		662		(4,838)		4,699
Exploration expenses ⁽¹⁾		3,295		10,914		8,276
Depreciation, depletion, amortization and accretion		158,284		219,915		235,243
Proved property impairment and abandonment charges ⁽²⁾		151,045		113,439		177,138
(Gain) loss on sale of oil and gas properties		1,714		(4,531)		(287)
Non-hedge gain on commodity derivative contracts		(5,550)		-		(1,088)
Selling, general and administrative expenses		17,823		12,951		15,966
Net interest expense and other ⁽³⁾		28,191		25,558		19,687
Total costs		520,127		549,677		590,790
Pretax income (loss) from discontinued operations		37,104		146,930		(165,421)
Income tax provision (benefit)		13,420		51,709		(58,764)
Income (loss) from discontinued operations, net of tax	$	23,684	$	95,221	$	(106,657)

(1) See “Exploration and Other” below for additional information related to the components of our exploration costs, including impairment charges for expiring unproved leases.

(2) Includes $138.6 million recorded to reduce our carrying value of ERT to its estimated fair value less costs to sell.

Schedule of Results of Discontinued Operations


		2012		2011

Cash and cash equivalents	$	2	$	2
Accounts receivable		63,762		90,882
Other current assets		20,236		28,037
Current assets of discontinued operations		84,000		118,921
Property and equipment, net		787,852		871,658
Restricted cash and other		28,375		33,741
Non-current assets of discontinued operations	$	816,227	$	905,399

Accounts payable	$	110,569	$	73,124
Accrued liabilities		18,217		27,968
Current asset retirement obligations		53,741		65,883
Current liabilities of discontinued operations		182,527		166,975
Asset retirement obligations		147,237		161,208
Non-current liabilities of discontinued operations	$	147,237	$	161,208

Schedule of Aging of Capitalized Exploratory Well Costs


		2012		2011

Wang ⁽¹⁾	$	-	$	3,096
Danny II		-		2,619
T-6 ⁽¹⁾		8,122		-
Other		125		125
Total	$	8,247	$	5,840

(1) Both of these wells are located within the Phoenix field at Green Canyon Block 237.

Capitalized Exploratory Well Costs, Roll Forward


		2012		2011		2010

Beginning balance at January 1,	$	5,840	$	3,252	$	3,059
Additions pending the determination of proved reserves		135,311		2,513		(944)
Reclassifications to proved properties		(132,959)		5		713
Charged to dry hole expense		55		70		424
Ending balance at December 31,	$	8,247	$	5,840	$	3,252

Components Of Exploration Expenses


		Year Ended December 31,
		2012		2011		2010

Delay rental and geological and geophysical costs	$	2,517	$	2,650	$	2,306
Impairment of unproved properties		833		8,334		6,394
Dry hole expense		(55)		(70)		(424)
Total exploration expense	$	3,295	$	10,914	$	8,276

Tabular disclosure of the results of operations for oil and gas producing activities for the year.

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Tabular disclosure of disposal groups, which may include the gain (loss) recognized in the income statement and the income statement caption that includes that gain (loss), amounts of revenues and pretax profit or loss reported in discontinued operations, the classification and carrying value of the assets and liabilities comprising the disposal group, and the segment in which the disposal group was reported. Also may include the amount of adjustments to amounts previously reported in discontinued operations such as resolution of contingencies arising from the disposal transaction or the operations of the component prior to disposal.

Details Of Certain Accounts (Tables)

12 Months Ended

Dec. 31, 2012

Schedule of Other Current Assets


		2012		2011

Other receivables	$	1,086	$	618
Prepaid insurance		11,999		12,608
Other prepaids		11,751		11,328
Spare parts inventory		2,480		1,677
Income tax receivable ⁽¹⁾		14,201		-
Current deferred tax assets		43,942		41,449
Derivative assets		5,946		21,579
Other		5,529		4,325
Total other current assets	$	96,934	$	93,584

(1) Reflects the total amount of estimated tax receivable in excess of the estimated current income tax liability.

Other Assets, Net


		2012		2011

Deferred dry dock expenses, net ⁽¹⁾	$	22,704	$	5,381
Deferred financing costs, net		24,338		26,483
Intangible assets with finite lives, net		491		531
Other		2,304		2,771
Total other assets, net	$	49,837	$	35,166

(1) The increase subsequent to December 31, 2011 reflects the costs associated with the regulatory dry docks for our Q4000, Seawell and Well Enhancer vessels during 2012.

Accrued Liabilities


		2012		2011

Accrued payroll and related benefits	$	51,561	$	45,217
Current asset retirement obligations ⁽¹⁾		2,898		27,300
Unearned revenue		6,137		7,654
Billing in excess of cost ⁽²⁾		6,445		28,839
Accrued interest		17,451		24,028
Derivative liability ⁽³⁾		16,266		1,247
Taxes payable excluding income tax payable		5,164		3,748
Pipelay assets sale deposit ⁽⁴⁾		50,000		-
Other		5,592		8,079
Total accrued liabilities	$	161,514	$	146,112

(1) Reflects the substantial completion of the abandonment of the Camelot field (Note 3).

(2) Decrease reflects fewer ongoing subsea construction projects using the percentage-of-completion method of accounting as a result of the expected sales of our remaining pipelay vessels.

(3) Primarily reflects the fair value of oil commodity derivative contracts of $15.8 million at December 31, 2012 (Note 17). These contracts were settled in February 2013.

Equity Investments (Tables)

12 Months Ended

Dec. 31, 2012

Equity Investments [Abstract]

Contributions To Equity Investments


		Year Ended December 31,
		2012		2011		2010

Clough Helix Pty Ltd. (see below)	$	-	$	2,699	$	8,253
Total	$	-	$	2,699	$	8,253

Distributions From Equity Investments


		Year Ended December 31,
		2012		2011		2010

Deepwater Gateway	$	8,157	$	7,600	$	8,125
Independence Hub		8,073		18,580		21,615
Other		-		-		268
Total	$	16,230	$	26,180	$	30,008

Schedule Of Summarized Aggregated Financial Information Related To The Subsidiaries


		Year Ended December 31,
		2012		2011		2010

Revenues	$	53,159	$	193,521	$	141,705
Operating income		30,463		97,954		93,324
Net income		30,463		93,215		93,005


		December 31,
		2012		2011		2010

Current assets	$	16,682	$	39,754	$	25,352
Total assets		537,251		591,761		594,645
Current liabilities		706		11,012		6,434
Total liabilities		5,320		27,163		19,695

Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2012

Long-Term Debt [Abstract]

Schedule Of Debt


		2012		2011

Term Loans (mature July 2015)	$	367,181	$	279,750
Revolving Credit Facility (matures July 2015)		100,000		-
2025 Notes (mature December 2025)		3,487		300,000
2032 Notes (mature March 2032)		200,000		-
Senior Unsecured Notes (mature January 2016)		274,960		474,960
MARAD Debt (matures February 2027)		105,288		110,166
Unamoritized debt discount		(31,688)		(9,555)
Total debt		1,019,228		1,155,321
Less current maturities		(16,607)		(7,877)
Long-term debt	$	1,002,621	$	1,147,444

Schedule Of Redemption Price By Maturity


Year		Redemption Price

2012		104.750%
2013		102.375%
2014 and thereafter		100.000%

Schedule of Deferred Financing Costs


		2012						2011
		Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net

Term Loans (mature July 2015)	$	15,318	$	(11,595)	$	3,723	$	13,680	$	(10,257)	$	3,423
Revolving Credit Facility (matures July 2015)		20,021		(12,466)		7,555		19,236		(9,640)		9,596
2025 Notes (mature December 2025)		8,189		(8,189)		-		8,189		(7,340)		849
2032 Notes (mature March 2032)		4,251		(534)		3,717		78		-		78
Senior Unsecured Notes (mature January 2016)		10,643		(8,252)		2,391		10,643		(5,546)		5,097
MARAD Debt (matures February 2027)		12,200		(5,248)		6,952		12,200		(4,760)		7,440
Total deferred financing costs	$	70,622	$	(46,284)	$	24,338	$	64,026	$	(37,543)	$	26,483

Schedule of Maturities Of Long-Term Debt


		Term Loan⁽¹⁾		Revolving Credit Facility ⁽¹⁾		Senior Unsecured Notes		2025 Notes⁽²⁾		MARAD Debt		2032 Notes⁽³⁾		Total

Less than one year	$	8,000	$	-	$	-	$	3,487	$	5,120	$	-	$	16,607
One to two years		8,000		-		-		-		5,376		-		13,376
Two to three years		351,181		100,000		-		-		5,644		-		456,825
Three to four years		-		-		274,960		-		5,926		-		280,886
Four to five years		-		-		-		-		6,222		-		6,222
Over five years		-		-		-		-		77,000		200,000		277,000
Total debt		367,181		100,000		274,960		3,487		105,288		200,000		1,050,916
Current maturities		(8,000)		-		-		(3,487)		(5,120)		-		(16,607)
Long-term debt, less current maturities	$	359,181	$	100,000	$	274,960	$	-	$	100,168	$	200,000	$	1,034,309
Unamortized debt discount⁽⁴⁾		-		-		-		-		-		(31,688)		(31,688)
Long-term debt	$	359,181	$	100,000	$	274,960	$	-	$	100,168	$	168,312	$	1,002,621

(2) We repurchased the remainder of the 2025 Notes in February 2013 (see “2025 Notes” above).

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

Schedule of Interest Expense And Capitalized Interest


		Year Ended December 31,
		2012		2011		2010

Interest expense	$	53,601	$	72,824	$	78,609
Interest income		(548)		(1,366)		(546)
Capitalized interest		(4,893)		(1,277)		(12,474)
Interest expense, net	$	48,160	$	70,181	$	65,589

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2012

Income Taxes [Abstract]

Schedule of Effective Income Tax Rate Reconciliation


	Year Ended December 31,
	2012		2011		2010

Statutory rate	35.0	%	35.0	%	35.0	%
Foreign provision	11.2		(291.0)		418.2
Effect of Australian reorganization	-		(2,984.3)		-
Nondeductible goodwill impairment (Note 2)	-		-		301.0
Valuation allowance on certain deferred tax assets	-		-		427.8
Other	0.8		(265.0)		(34.3)
Effective rate	47.0	%	(3,505.3)	%	1,147.7	%

Schedule of Components of Income Tax Expense (Benefit)


		Year Ended December 31,
		2012		2011		2010

Current	$	6,572	$	(78,150)	$	(22,930)
Deferred		(65,730)		41,344		42,096
	$	(59,158)	$	(36,806)	$	19,166


Domestic	$	(78,211)	$	(51,590)	$	1,596
Foreign		19,053		14,784		17,570
	$	(59,158)	$	(36,806)	$	19,166

Schedule of Deferred Tax Assets and Liabilities


		2012		2011
Deferred tax liabilities:
Depreciation and depletion	$	336,471	$	396,355
Original Issue Discount on 2025 and 2032 Notes		13,098		37,067
Equity investments in production facilities		81,082		76,911
Prepaid and other		10,548		14,779
Total deferred tax liabilities	$	441,199	$	525,112

Deferred tax assets:
Net operating loss carryforward	$	(36,981)	$	(34,987)
Asset retirement obligations		(70,085)		(88,279)
Reserves, accrued liabilities and other		(35,229)		(39,995)
Total deferred tax assets		(142,295)		(163,261)
Valuation allowance		16,391		14,310

Net deferred tax liabilities	$	315,295	$	376,161

Deferred income tax is presented as:
Current deferred tax assets		(43,942)		(41,449)
Noncurrent deferred tax liabilities		359,237		417,610
Net deferred tax liabilities	$	315,295	$	376,161

Reconciliation of Beginning and Ending Amount of Unrecognized Tax Benefits


		2012		2011		2010

Balance at January 1,	$	7,085	$	4,085	$	3,417
Additions based on tax positions related to current year		-		2,785		-
Additions for tax positions of prior years		206		215		668
Reductions for tax positions of prior years		(2,785)		-		-
Balance at December 31,	$	4,506	$	7,085	$	4,085

Tabular disclosure of tax positions taken in the tax returns filed or to be filed for which it is more likely than not that the tax position will not be sustained upon examination by taxing authorities (i.e., uncertain tax positions) and other types of income tax contingencies, including: (1) the policy on classification of interest and penalties; (2) a tabular reconciliation of the total amounts of unrecognized tax benefits at the beginning and end of the period; the total amount(s) of: (3) unrecognized tax benefits that, if recognized, would affect the effective tax rate, and (4) interest and penalties recognized in each of the income statement and balance sheet; (5) for positions for which it is reasonably possible that the total amounts unrecognized will significantly change within 12 months of the reporting date the: (i) nature of the uncertainty, (ii) nature of the event that could occur that would cause the change, and (iii) an estimate of the range of the reasonably possible change or a statement that an estimate of the range cannot be made; and (6) a description of tax years that remain subject to examination by major tax jurisdictions.

Schedule of Share-based Compensation, Stock Options, Activity

Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2012

Employee Benefit Plans [Abstract]


	2012			2011			2010
			Weighted			Weighted			Weighted
			Average			Average			Average
			Exercise			Exercise			Exercise
	Shares		Price	Shares		Price	Shares		Price

Options outstanding at beginning of year	192,800	$	10.52	432,918	$	10.78	501,318	$	10.74
Exercised	(140,000)		9.24	(181,670)		10.92	(68,400)		10.52
Terminated	-		-	(58,448)		11.20	-		-
Options outstanding at end of year	52,800	$	13.91	192,800	$	10.52	432,918	$	10.78
Options exercisable at end of year	52,800	$	13.91	192,800	$	10.52	432,918	$	10.78

Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity

	2012			2011			2010
			Grant Date			Grant Date			Grant Date
	Shares		Fair Value ⁽¹⁾	Shares		Fair Value ⁽¹⁾	Shares		Fair Value ⁽¹⁾

Awards outstanding at beginning of year	1,263,218	$	14.80	1,463,298	$	16.93	1,443,265	$	21.55
Granted	482,340		18.33	571,163		12.77	599,996		12.01
Vested ⁽²⁾	(400,180)		18.07	(504,813)		19.87	(444,905)		25.10
Forfeited	(21,066)		15.00	(266,430)		12.55	(135,058)		17.48
Awards outstanding at end of year	1,324,312	$	15.09	1,263,218	$	14.80	1,463,298	$	16.93

(1) Represents the weighted average grant date fair value, which is based on the quoted market price of the common stock on the business day prior to the date of grant.

(2) Total fair value of share-based awards that vested during the years ended December 31, 2012, 2011 and 2010 was $6.7 million, $6.7 million and $5.6 million, respectively.

Schedule Of Restricted Shares Granted To Executive Officers Management Employees And Non Employee Members Table

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

January 3, 2012 ⁽¹⁾	272,153	$	15.80	33% per year over three years
January 3, 2012 ⁽²⁾	132,910		23.68	100% on January 1, 2015
January 3, 2012⁽³⁾	1,958		15.80	100% on January 1, 2014
April 1, 2012⁽³⁾	1,879		17.80	100% on January 1, 2014
July 2, 2012⁽³⁾	1,885		16.41	100% on January 1, 2014
August 23, 2012⁽³⁾	3,539		18.84	20% per year over five years
October 1, 2012⁽³⁾	1,830		18.27	100% on January 1, 2014
December 6, 2012⁽³⁾	66,186		18.13	33% per year over three years

(3) Reflects grants to our directors.

Shareholders' Equity (Tables)

12 Months Ended

Dec. 31, 2012

Stockholders' Equity Note [Abstract]

Components Of Accumulated Other Comprehensive Loss



		2012		2011

Cumulative foreign currency translation adjustment	$	(15,667)	$	(22,958)
Unrealized gain on hedges, net ⁽¹⁾		-		12,941
Accumulated other comprehensive loss	$	(15,667)	$	(10,017)

(1) Amount at December 31, 2011 is net of deferred income tax liabilities totaling $7.0 million.

Commitments And Contingencies (Tables)

12 Months Ended

Dec. 31, 2012

Commitments And Contingencies and Other Matters [Abstract]

Schedule of Future Minimum Rental Payments for Operating Leases


		ROVs and Vessels		Facilities and Other		Total

2013	$	84,409	$	1,948	$	86,357
2014		87,942		3,077		91,019
2015		86,155		3,620		89,775
2016		60,019		3,289		63,308
2017		38,188		3,153		41,341
Thereafter		4,905		22,778		27,683
Total lease commitments	$	361,618	$	37,865	$	399,483

Business Segment Information (Tables)

12 Months Ended

Dec. 31, 2012

Business Segment Information [Abstract]

Schedule Of Segment Reporting Information By Segment


		Year Ended December 31,
		2012		2011		2010
Revenues —
Contracting Services	$	899,793	$	738,235	$	780,339
Production Facilities		80,091		75,460		117,300
Intercompany elimination		(133,775)		(111,695)		(123,170)
Total	$	846,109	$	702,000	$	774,469

Income (loss) from operations —
Contracting Services	$	(7,702)	$	107,013	$	77,391
Production Facilities		40,082		38,404		63,863
Corporate		(92,985)		(82,470)		(71,080)
Intercompany elimination		(7,878)		93		(19,095)
Total	$	(68,483)	$	63,040	$	51,079

Net interest expense and other —
Contracting Services	$	702	$	765	$	1,299
Production Facilities		365		442		865
Corporate and eliminations		64,845		72,435		64,474
Total	$	65,912	$	73,642	$	66,638

Equity in earnings of equity investments	$	8,434	$	22,215	$	19,469


Income (loss) before income taxes —
Contracting Services	$	(8,529)	$	97,798	$	72,459
Production Facilities		48,276		58,064		86,100
Corporate and eliminations		(165,708)		(154,812)		(156,889)
Total	$	(125,961)	$	1,050	$	1,670

Income tax provision (benefit) —
Contracting Services	$	(15,707)	$	29,235	$	42,828
Production Facilities		15,784		19,233		29,049
Corporate and eliminations		(59,235)		(85,274)		(52,711)
Total	$	(59,158)	$	(36,806)	$	19,166


Identifiable assets —
Contracting Services	$	1,982,822	$	2,023,251	$	1,872,141
Production Facilities		503,531		534,776		512,990
Discontinued operations		900,227		1,024,320		1,206,889
Total	$	3,386,580	$	3,582,347	$	3,592,020

Capital expenditures —
Contracting Services	$	322,216	$	69,259	$	65,949
Production Facilities		823		30,896		56,269
Total	$	323,039	$	100,155	$	122,218


Depreciation and amortization —
Contracting Services	$	77,442	$	73,291	$	66,333
Production Facilities		16,828		14,935		9,907
Corporate and eliminations		2,931		2,962		5,638
Total	$	97,201	$	91,188	$	81,878

Summary Of Intercompany Segment Revenues


		Year Ended December 31,
		2012		2011		2010

Contracting Services	$	87,718	$	65,638	$	109,012
Production Facilities		46,057		46,057		14,158
Total	$	133,775	$	111,695	$	123,170

Intercompany Segment Gross Profit (Losses)


		Year Ended December 31,
		2012		2011		2010

Contracting Services	$	8,053	$	104	$	15,655
Production Facilities		(175)		(197)		3,457
Total	$	7,878	$	(93)	$	19,112

Schedule of Revenue from External Customers Attributed to Foreign Countries by Geographic Area


		Year Ended December 31,
		2012		2011		2010

United States	$	281,308	$	316,869	$	402,228
United Kingdom		345,074		275,499		198,011
Other		219,727		109,632		174,230
Total	$	846,109	$	702,000	$	774,469

Schedule of Disclosure on Geographic Areas, Long-Lived Assets in Individual Foreign Countries by Country


		Year Ended December 31,
		2012		2011		2010

United States	$	1,180,586	$	1,163,320	$	1,162,217
United Kingdom		304,062		281,430		275,012
Other		1,227		14,919		15,613
Total	$	1,485,875	$	1,459,669	$	1,452,842

Tabular disclosure of the profit or loss and total assets for each reportable segment. An entity discloses certain information on each reportable segment if the amounts (a) are included in the measure of segment profit or loss reviewed by the chief operating decision maker or (b) are otherwise regularly provided to the chief operating decision maker, even if not included in that measure of segment profit or loss.

Summary of Valuation Allowance

Allowance Accounts (Tables)

12 Months Ended

Dec. 31, 2012

Allowance Accounts [Abstract]


		Allowance		Deferred
		for		Tax Asset
		Uncollectible		Valuation
		Accounts		Allowance

Balance at December 31, 2009	$	5,105	$	-
Additions ⁽¹⁾		4,108		8,497
Deductions ⁽²⁾		(4,753)		-
Balance at December 31, 2010		4,460		8,497
Additions ⁽³⁾		61		5,813
Deductions		(521)		-
Balance at December 31, 2011		4,000		14,310
Additions ⁽⁴⁾		1,257		2,081
Deductions		(105)		-
Balance at December 31, 2012	$	5,152	$	16,391

(2) Includes the $3.7 million of bad debt expense related to settlement of third party claims related to a terminated international construction contract in Australia (Note 13).

(3) The increase in valuation allowance includes $4.9 million related to our WOSEA and $0.9 million to our oil and gas operations in the United Kingdom.

Tabular disclosure of valuation allowances to reduce deferred tax assets to net realizable value, including identification of the deferred tax asset more likely than not will not be fully realized and the corresponding amount of the valuation allowance.

Supplemental Oil and Gas Disclosures [Abstract]

Supplemental Oil And Gas Disclosures (Tables)

12 Months Ended

Dec. 31, 2012

Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure


		2012		2011

Unproved oil and gas properties	$	51,513	$	50,389
Proved oil and gas properties		2,453,667		2,516,363
Total oil and gas properties		2,505,180		2,566,752
Accumulated depletion, depreciation and amortization		(1,717,314)		(1,695,105)
Net capitalized costs	$	787,866	$	871,647

Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure


		Year Ended December 31,
		2012		2011		2010

Property acquisition costs:
Proved properties	$	-	$	-	$	-
Unproved properties		-		41		364
Total property acquisition costs		-		41		364
Exploration costs		135,311		2,513		1,362
Development costs ⁽¹⁾		17,344		126,196		53,002
Asset retirement costs ⁽²⁾		59,715		46,446		25,356
Total costs incurred	$	212,370	$	175,196	$	80,084

(1) Development costs include costs incurred to obtain access to proved reserves to drill and equip development wells.

Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities


			Total
	Oil	Gas	(MBOE)

Total proved reserves at December 31, 2009 ⁽¹⁾	29,727	399,315	96,280
Revision of previous estimates ^{(1), (2)}	(1,555)	(144,954)	(25,714)
Production	(3,354)	(27,097)	(7,870)
Purchases of reserves in place	-	-	-
Sales of reserves in place	-	-	-
Extensions and discoveries	-	-	-
Total proved reserves at December 31, 2010	24,818	227,264	62,696
Revision of previous estimates ⁽³⁾	3,475	(108,947)	(14,683)
Production	(5,785)	(17,458)	(8,694)
Purchases of reserves in place	-	-	-
Sales of reserves in place	(205)	(4,109)	(890)
Extensions and discoveries	386	271	431
Total proved reserves at December 31, 2011	22,689	97,021	38,860
Revision of previous estimates ⁽⁴⁾	647	(12,926)	(1,508)
Production	(4,725)	(11,361)	(6,619)
Purchases of reserves in place	-	-	-
Sales of reserves in place	(75)	(3,473)	(654)
Extensions and discoveries	1,434	4,026	2,105
Total proved reserves at December 31, 2012	19,970	73,287	32,184

Total proved developed reserves as of:
December 31, 2009	14,850	124,763	35,644
December 31, 2010	11,796	75,664	24,407
December 31, 2011	12,754	59,859	22,731
December 31, 2012	12,431	43,475	19,677

(4) Decrease primarily represents revisions at several gas fields due to well performance and future capital investment plans.

Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure


		United		United
		States		Kingdom		Total
As of December 31, 2012 —
Future cash inflows	$	2,341,354	$	-	$	2,341,354
Future costs:
Production		509,408		-		509,408
Development and abandonment		507,074		2,897		509,971
Total future costs		1,016,482		2,897		1,019,379
Future net cash flows before income taxes		1,324,872		(2,897)		1,321,975
Future income tax expense		330,630		-		330,630
Future net cash flows		994,242		(2,897)		991,345
Discount at 10% annual rate		153,032		-		153,032
Standardized measure of discounted future net cash flows	$	841,210	$	(2,897)	$	838,313


As of December 31, 2011 —
Future cash inflows	$	2,811,956	$	-	$	2,811,956
Future costs:
Production		419,617		-		419,617
Development and abandonment		557,323		27,300		584,623
Total future costs		976,940		27,300		1,004,240
Future net cash flows before income taxes		1,835,016		(27,300)		1,807,716
Future income tax expense		477,630		-		477,630
Future net cash flows		1,357,386		(27,300)		1,330,086
Discount at 10% annual rate		266,954		-		266,954
Standardized measure of discounted future net cash flows	$	1,090,432	$	(27,300)	$	1,063,132


As of December 31, 2010 —
Future cash inflows	$	2,925,744	$	-	$	2,925,744
Future costs:
Production		583,050		-		583,050
Development and abandonment		590,870		12,200		603,070
Total future costs		1,173,920		12,200		1,186,120
Future net cash flows before income taxes		1,751,824		(12,200)		1,739,624
Future income tax expense		430,153		-		430,153
Future net cash flows		1,321,671		(12,200)		1,309,471
Discount at 10% annual rate		318,404		-		318,404
Standardized measure of discounted future net cash flows	$	1,003,267	$	(12,200)	$	991,067

Schedule Of Average Price Used To Estimate Proved Oil And Gas Reserves


		Year Ended December 31,
		2012		2011		2010

Oil price per Bbl	$	104.85	$	105.35	$	77.55
Natural gas price per Mcf	$	3.38	$	4.34	$	4.40

Changes In Standardized Measure Of Discounted Future Net Cash Flows


		Year Ended December 31,
		2012		2011		2010

Standardized measure, beginning of year	$	1,063,132	$	991,067	$	991,060
Changes during the year:
Sales, net of production costs		(379,910)		(516,895)		(294,212)
Net change in prices and production costs		(242,037)		414,426		577,687
Changes in future development costs		(65,854)		(108,007)		84,907
Development costs incurred ⁽¹⁾		149,702		168,005		55,646
Accretion of discount		147,157		131,464		129,083
Net change in income taxes		101,720		(54,613)		(41,115)
Purchases of reserves in place		-		-		-
Extensions and discoveries		110,655		29,479		-
Sales of reserves in place		(6,096)		(14,324)		-
Net change due to revision in quantity estimates		28,627		(186,197)		(422,987)
Changes in production rates (timing) and other		(68,783)		208,727		(89,002)
Total		(224,819)		72,065		7
Standardized measure, end of year	$	838,313	$	1,063,132	$	991,067

Tabular disclosure of the aggregate of costs (whether the costs are capitalized or charged to expense at the time they are incurred ) incurred for the year in oil and gas property acquisition, exploration and development activities.

Tabular disclosure of the net quantities of an enterprise's interests in proved developed and undeveloped reserves of (a) crude oil (including condensate and natural gas liquids), (b) natural gas (including coal bed methane), (c) synthetic oil, (d) synthetic gas, and (e) other nonrenewable natural resources that are intended to be upgraded during the period as of the beginning of the period, changes in quantities during the period, and as of the end of the period.

Tabular disclosure of the future net cash flows relating to proved oil and gas reserves and oil and gas subject to purchase under long-term agreements in which the enterprise participates in the operation of the properties on which the oil and gas is located or otherwise serves as the producer. This information is presented in aggregate and for each geographic area for which reserve quantities are disclosed.

Derivative Instruments And Hedging Activities [Abstract]

Derivative Instruments And Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2012

Derivatives Designated As Hedging Instruments


	As of December 31, 2012			As of December 31, 2011
	Balance Sheet		Fair	Balance Sheet		Fair
	Location		Value	Location		Value
Asset Derivatives:
Natural gas contracts	Other current assets	$	-	Other current assets	$	12,957
Oil contracts	Other current assets		-	Other current assets		8,567
Natural gas contracts	Other assets, net		-	Other assets, net		857
Interest rate swaps	Other assets, net		-	Other assets, net		327
		$	-		$	22,708

Liability Derivatives:
Oil contracts	Accrued liabilities	$	-	Accrued liabilities	$	886
Interest rate swaps	Accrued liabilities		-	Accrued liabilities		202
Oil contracts	Other long-term liabilities		-	Other long-term liabilities		1,712
		$	-		$	2,800

Derivatives Not Designated As Hedging Instruments


	As of December 31, 2012			As of December 31, 2011
	Balance Sheet		Fair	Balance Sheet		Fair
	Location		Value	Location		Value
Asset Derivatives:
Oil contracts	Other current assets	$	5,800	Other current assets	$	-
Foreign exchange forwards	Other current assets		146	Other current assets		55
		$	5,946		$	55

Liability Derivatives:
Oil contracts	Accrued liabilities	$	15,777	Accrued liabilities	$	-
Interest rate swaps	Accrued liabilities		489	Accrued liabilities		-
Foreign exchange forwards	Accrued liabilities		-	Accrued liabilities		159
Interest rate swaps	Other long-term liabilities		32	Other long-term liabilities		-
		$	16,298		$	159

Impact Of Derivative Instruments On Accumulated Comprehensive Income (Loss)


		Gain (Loss) Recognized in OCI on Derivatives
		(Effective Portion)
		Year Ended December 31,
		2012		2011		2010

Oil and natural gas commodity contracts	$	(12,860)	$	28,749	$	(6,486)
Interest rate swaps		(81)		1,294		(1,213)
	$	(12,941)	$	30,043	$	(7,699)

Gain (Loss) Reclassified From Accumulated OCI Into Income


			Gain (Loss) Reclassified from
	Reclassified from		Accumulated OCI into Income
	Location of Gain (Loss)		(Effective Portion)
	Accumulated OCI into Income		Year Ended December 31,
	(Effective Portion)		2012		2011		2010

Oil and natural gas commodity contracts	Income (loss) from discontinued operations, net of tax	$	3,184	$	(21,659)	$	25,575
Interest rate swaps	Net interest expense		(523)		(2,010)		(1,849)
		$	2,661	$	(23,669)	$	23,726

Impact Of Non Designated Derivative Instruments On Income Statement


			Gain (Loss) Recognized in Income
	Location of Gain (Loss)		on Derivatives
	Recognized in Income		Year Ended December 31,
	on Derivatives		2012		2011		2010

Oil and natural gas commodity contracts	Income (loss) from discontinued operations, net of tax	$	5,550	$	-	$	1,088
Oil and natural gas commodity contracts	Non-hedge loss on commodity derivative contracts		(10,507)		-		-
Interest rate swaps	Other income (expense), net		(567)		-		-
Foreign exchange forwards	Other income (expense), net		411		249		(2,560)
		$	(5,113)	$	249	$	(1,472)

Quarterly Financial Information (Tables)

12 Months Ended

Dec. 31, 2012

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information


		Quarter Ended
		March 31,		June 30,		September 30,		December 31,
2012
Net revenues ⁽¹⁾	$	229,842	$	197,461	$	217,110	$	201,696
Gross profit (loss) ⁽²⁾		72,483		28,438		57,919		(108,925)
Net income (loss)		65,737		44,651		14,875		(171,560)
Net income (loss) applicable to common shareholders:
Income (loss) from continuing operations	$	16,874	$	2,425	$	10,362	$	(99,679)
Income (loss) from discontinued operations ⁽³⁾		48,853		42,216		4,503		(71,888)
Net income (loss) applicable to common shareholders	$	65,727	$	44,641	$	14,865	$	(171,567)
Basic earnings (loss) per common share:
Income (loss) from continuing operations	$	0.16	$	0.02	$	0.10	$	(0.95)
Income (loss) from discontinued operations		0.46		0.40		0.04		(0.69)
Basic earnings (loss) per common share	$	0.62	$	0.42	$	0.14	$	(1.64)
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	0.16	$	0.02	$	0.10	$	(0.95)
Income (loss) from discontinued operations		0.46		0.40		0.04		(0.69)
Diluted earnings (loss) per common share	$	0.62	$	0.42	$	0.14	$	(1.64)


		Quarter Ended
		March 31,		June 30,		September 30,		December 31,
2011
Net revenues ⁽⁴⁾	$	122,748	$	165,861	$	213,278	$	200,113
Gross profit ⁽⁵⁾		14,395		44,043		64,972		26,273
Net income ⁽⁶⁾		25,867		41,323		46,026		16,763
Net income applicable to common shareholders:
Income (loss) from continuing operations	$	(9,315)	$	10,547	$	15,999	$	17,487
Income (loss) from discontinued operations		35,172		30,766		30,017		(734)
Net income applicable to common shareholders	$	25,857	$	41,313	$	46,016	$	16,753
Basic earnings per common share:
Income (loss) from continuing operations	$	(0.09)	$	0.10	$	0.15	$	0.17
Income (loss) from discontinued operations		0.33		0.29		0.28		(0.01)
Basic earnings per common share	$	0.24	$	0.39	$	0.43	$	0.16
Diluted earnings per common share:
Income (loss) from continuing operations	$	(0.09)	$	0.10	$	0.15	$	0.17
Income (loss) from discontinued operations		0.33		0.29		0.29		(0.01)
Diluted earnings per common share	$	0.24	$	0.39	$	0.44	$	0.16

(1) Excludes revenues from discontinued operations of $178.1 million, $149.9 million, $119.1 million and $110.1 million for the quarters ended March 31, June 30, September 30 and December 31, 2012.

(3) Our net loss in the fourth quarter of 2012 includes a $138.6 million impairment charge associated with the sale of ERT (Note 3).

(4) Excludes revenues from discontinued operations of $168.9 million, $172.5 million, $159.2 million and $196.1 million for the quarters ended March 31, June 30, September 30 and December 31, 2011.

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

12 Months Ended

Dec. 31, 2012

Condensed Consolidated Guarantor And Non-Guarantor Financial Information [Abstract]

Schedule of Condensed Balance Sheet

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(in thousands)


		As of December 31, 2012
						Non-		Consolidating
		Helix		Guarantors		Guarantors		Entries		Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	381,599	$	4,436	$	51,065	$	-	$	437,100
Accounts receivable, net		39,203		37,378		75,652		-		152,233
Unbilled revenue		13,959		875		19,006		-		33,840
Income taxes receivable		24,611		-		306		(10,716)		14,201
Other current assets		54,588		16,418		11,696		31		82,733
Current assets of discontinued operations		-		84,000		-		-		84,000
Total current assets		513,960		143,107		157,725		(10,685)		804,107
Intercompany		(154,756)		352,210		(125,889)		(71,565)		-
Property and equipment, net		208,190		351,746		930,556		(4,617)		1,485,875
Other assets:
Equity investments in unconsolidated affiliates		-		-		167,599		-		167,599
Equity investments in affiliates		1,762,359		53,461		-		(1,815,820)		-
Goodwill		-		45,107		17,828		-		62,935
Other assets, net		47,355		130		34,848		(32,496)		49,837
Due from subsidiaries/parent		294,461		485,096		-		(779,557)		-
Non-current assets of discontinued operations		-		816,227		-		-		816,227
Total assets	$	2,671,569	$	2,247,084	$	1,182,667	$	(2,714,740)	$	3,386,580

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	45,784	$	17,229	$	29,385	$	-	$	92,398
Accrued liabilities		117,902		26,019		17,593		-		161,514
Income taxes payable		-		26,618		-		(26,618)		-
Current maturities of long-term debt		11,487		-		5,120		-		16,607
Current liabilities of discontinued operations		-		182,527		-		-		182,527
Total current liabilities		175,173		252,393		52,098		(26,618)		453,046
Long-term debt		902,453		-		100,168		-		1,002,621
Deferred tax liabilities		168,688		86,925		109,171		(5,547)		359,237
Other long-term liabilities		1,453		3,086		486		-		5,025
Due to parent		-		-		323,049		(323,049)		-
Non-current liabilities of discontinued operations		-		147,237		-		-		147,237
Total liabilities		1,247,767		489,641		584,972		(355,214)		1,967,166
Convertible preferred stock		-		-		-		-		-
Total equity		1,423,802		1,757,443		597,695		(2,359,526)		1,419,414
Total liabilities and shareholders' equity	$	2,671,569	$	2,247,084	$	1,182,667	$	(2,714,740)	$	3,386,580

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(in thousands)


		As of December 31, 2011
						Non-		Consolidating
		Helix		Guarantors		Guarantors		Entries		Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	495,484	$	2,432	$	48,547	$	-	$	546,463
Accounts receivable, net		79,290		26,885		41,724		-		147,899
Unbilled revenue		10,530		155		26,690		-		37,375
Income taxes receivable		80,388		-		-		(80,388)		-
Other current assets		68,627		20,624		10,159		(5,826)		93,584
Current assets of discontinued operations		-		118,921		-		-		118,921
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		550,668		682,899		(4,844)		1,459,669
Other assets:
Equity investments in unconsolidated affiliates		-		-		175,656		-		175,656
Equity investments in affiliates		1,952,392		37,239		-		(1,989,631)		-
Goodwill		-		45,107		17,108		-		62,215
Other assets, net		53,425		2,712		16,809		(37,780)		35,166
Due from subsidiaries/parent		64,655		430,496		-		(495,151)		-
Non-current assets of discontinued operations		-		905,399		-		-		905,399
Total assets	$	2,888,550	$	2,456,459	$	916,766	$	(2,679,428)	$	3,582,347

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	39,280	$	9,626	$	25,013	$	-	$	73,919
Accrued liabilities		115,921		3,841		26,350		-		146,112
Income taxes payable		-		97,692		217		(96,616)		1,293
Current maturities of long-term debt		3,000		-		10,377		(5,500)		7,877
Current liabilities of discontinued operations		-		166,975		-		-		166,975
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 tax liabilities		231,255		88,625		103,552		(5,822)		417,610
Other long-term liabilities		4,150		4,647		571		-		9,368
Due to parent		-		-		98,285		(98,285)		-
Non-current liabilities of discontinued operations		-		161,208		-		-		161,208
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
Total liabilities and shareholders' equity	$	2,888,550	$	2,456,459	$	916,766	$	(2,679,428)	$	3,582,347

Schedule of Condensed Income Statement

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

AND COMPREHENSIVE INCOME (LOSS)

(in thousands)


		Year Ended December 31, 2012
						Non-		Consolidating
		Helix		Guarantors		Guarantors		Entries		Consolidated

Net revenues	$	90,552	$	404,628	$	464,331	$	(113,402)	$	846,109
Cost of sales		111,531		444,956		351,283		(111,576)		796,194
Gross profit (loss)		(20,979)		(40,328)		113,048		(1,826)		49,915
Loss on sale of assets, net		-		(13,475)		(1)		-		(13,476)
Non-hedge loss on commodity derivative contracts		-		(10,507)		-		-		(10,507)
Selling, general and administrative expenses		(53,539)		(22,782)		(20,018)		1,924		(94,415)
Income (loss) from operations		(74,518)		(87,092)		93,029		98		(68,483)
Equity in earnings of investments		(12,264)		16,222		8,434		(3,958)		8,434
Net interest expense and other		(59,759)		392		(6,517)		(28)		(65,912)
Income (loss) before income taxes		(146,541)		(70,478)		94,946		(3,888)		(125,961)
Income tax provision (benefit)		(96,328)		24,186		12,951		33		(59,158)
Income (loss) from continuing operations		(50,213)		(94,664)		81,995		(3,921)		(66,803)
Income (loss) from discontinued operations, net of tax		(1,621)		25,305		-		-		23,684
Net income (loss) applicable to Helix		(51,834)		(69,359)		81,995		(3,921)		(43,119)
Net income applicable to noncontrolling interests		-		-		-		(3,178)		(3,178)
Preferred stock dividends		(37)		-		-		-		(37)
Net income (loss) applicable to Helix common shareholders	$	(51,871)	$	(69,359)	$	81,995	$	(7,099)	$	(46,334)

Total comprehensive income (loss) applicable to Helix common shareholders	$	(51,952)	$	(82,219)	$	89,260	$	(7,073)	$	(51,984)


		Year Ended December 31, 2011
						Non-		Consolidating
		Helix		Guarantors		Guarantors		Entries		Consolidated

Net revenues	$	84,748	$	362,648	$	367,114	$	(112,510)	$	702,000
Cost of sales		72,902		281,267		309,429		(111,281)		552,317
Gross profit		11,846		81,381		57,685		(1,229)		149,683
Loss on sale of assets, net		(6)		-		-		-		(6)
Selling, general and administrative expenses		(74,205)		(25,963)		12,101		1,430		(86,637)
Income (loss) from operations		(62,365)		55,418		69,786		201		63,040
Equity in earnings of investments		262,990		7,340		22,215		(270,330)		22,215
Other than temporary loss on equity investments		-		-		(10,563)		-		(10,563)
Net interest expense and other		(157,546)		(6,787)		67,181		23,510		(73,642)
Income (loss) before income taxes		43,079		55,971		148,619		(246,619)		1,050
Income tax provision (benefit)		(63,242)		18,181		8,186		69		(36,806)
Income (loss) from continuing operations		106,321		37,790		140,433		(246,688)		37,856
Income from discontinued operations, net of tax		-		95,221		-		-		95,221
Net income (loss) applicable to Helix		106,321		133,011		140,433		(246,688)		133,077
Net income applicable to noncontrolling interests		-		-		-		(3,098)		(3,098)
Preferred stock dividends		(40)		-		-		-		(40)
Net income (loss) applicable to Helix common shareholders	$	106,281	$	133,011	$	140,433	$	(249,786)	$	129,939

Total comprehensive income (loss) applicable to Helix common shareholders	$	107,575	$	161,760	$	140,214	$	(250,569)	$	158,980

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

AND COMPREHENSIVE INCOME (LOSS)

(in thousands)


		Year Ended December 31, 2010
						Non-		Consolidating
		Helix		Guarantors		Guarantors		Entries		Consolidated

Net revenues	$	183,147	$	376,134	$	334,726	$	(119,538)	$	774,469
Cost of sales		124,722		287,709		302,051		(104,830)		609,652
Gross profit		58,425		88,425		32,675		(14,708)		164,817
Goodwill impairment		-		-		(16,743)		-		(16,743)
Gain on sale of assets, net		3,159		-		5,959		-		9,118
Selling, general and administrative expenses		(67,165)		(18,268)		(22,482)		1,802		(106,113)
Loss from operations		(5,581)		70,157		(591)		(12,906)		51,079
Equity in earnings of investments		(60,443)		8,473		19,469		51,970		19,469
Other than temporary loss on equity investments		(2,240)		-		-		-		(2,240)
Net interest expense and other		(59,522)		(1,991)		(5,125)		-		(66,638)
Income (loss) before income taxes		(127,786)		76,639		13,753		39,064		1,670
Income tax provision (benefit)		(9,175)		23,465		9,405		(4,529)		19,166
Income (loss) from continuing operations		(118,611)		53,174		4,348		43,593		(17,496)
Loss from discontinued operations, net of tax		-		(106,657)		-		-		(106,657)
Net income (loss) applicable to Helix		(118,611)		(53,483)		4,348		43,593		(124,153)
Net income applicable to noncontrolling interests		-		-		-		(2,835)		(2,835)
Preferred stock dividends		(114)		-		-		-		(114)
Net income (loss) applicable to Helix common shareholders	$	(118,725)	$	(53,483)	$	4,348	$	40,758	$	(127,102)

Total comprehensive income (loss) applicable to Helix common shareholders	$	(119,051)	$	(59,969)	$	(5,653)	$	40,754	$	(143,919)

Schedule of Condensed Cash Flow Statement

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(in thousands)


		Year Ended December 31, 2012
						Non-		Consolidating
		Helix		Guarantors		Guarantors		Entries		Consolidated
Cash flows from operating activities:
Net income (loss), including noncontrolling interests	$	(51,834)	$	(69,359)	$	81,995	$	(3,921)	$	(43,119)
Adjustments to reconcile net income (loss), including noncontrolling interests to net cash provided by (used in) operating activities:
Equity in earnings of affiliates		12,264		(16,222)		-		3,958		-
Other adjustments		106,022		126,672		6,349		(19,856)		219,187
Cash provided by (used in) operating activities		66,452		41,091		88,344		(19,819)		176,068
Cash provided by discontinued operations		1,621		274,809		-		-		276,430
Net cash provided by (used in) operating activities		68,073		315,900		88,344		(19,819)		452,498

Cash flows from investing activities:
Capital expenditures		(2,422)		(38,197)		(282,420)		-		(323,039)
Distributions from equity investments, net		-		-		7,797		-		7,797
Proceeds from sale of assets		-		19,530		-		-		19,530
Cash used in investing activities		(2,422)		(18,667)		(274,623)		-		(295,712)
Cash used in discontinued operations		-		(120,057)		-		-		(120,057)
Net cash used in investing activities		(2,422)		(138,724)		(274,623)		-		(415,769)

Cash flows from financing activities:
Borrowings of debt		400,000		-		-		-		400,000
Repayments of debt		(520,357)		-		(4,877)		-		(525,234)
Deferred financing costs		(7,580)		-		-		-		(7,580)
Distributions to noncontrolling interests		-		-		(5,287)		-		(5,287)
Repurchases of common stock		(7,197)		-		-		-		(7,197)
Excess tax from stock-based compensation		(1,186)		-		-		-		(1,186)
Exercise of stock options, net and other		1,252		-		-		-		1,252
Intercompany financing		(44,468)		(175,172)		199,821		19,819		-
Net cash provided by (used in) financing activities		(179,536)		(175,172)		189,657		19,819		(145,232)

Effect of exchange rate changes on cash and cash equivalents		-		-		(860)		-		(860)
Net increase (decrease) in cash and cash equivalents		(113,885)		2,004		2,518		-		(109,363)
Cash and cash equivalents:
Balance, beginning of year		495,484		2,434		48,547		-		546,465
Balance, end of year		381,599		4,438		51,065		-		437,102
Less cash from discontinued operations, end of year		-		2		-		-		2
Cash from continuing operations, end of year	$	381,599	$	4,436	$	51,065	$	-	$	437,100

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(in thousands)


		Year Ended December 31, 2011
						Non-		Consolidating
		Helix		Guarantors		Guarantors		Entries		Consolidated
Cash flows from operating activities:
Net income (loss), including noncontrolling interests	$	106,321	$	133,011	$	140,433	$	(246,688)	$	133,077
Adjustments to reconcile net income (loss), including noncontrolling interests to net cash provided by (used in) operating activities:
Equity in earnings of affiliates		(262,990)		(7,340)		-		270,330		-
Other adjustments		39,860		(30,770)		40,293		198		49,581
Cash provided by (used in) operating activities		(116,809)		94,901		180,726		23,840		182,658
Cash provided by discontinued operations		-		384,498		-		-		384,498
Net cash provided by (used in) operating activities		(116,809)		479,399		180,726		23,840		567,156

Cash flows from investing activities:
Capital expenditures		(32,417)		(55,124)		(12,613)		-		(100,154)
Distributions from equity investments, net		-		-		1,266		-		1,266
Proceeds from sale of Cal Dive common stock		3,588		-		-		-		3,588
Cash used in investing activities		(28,829)		(55,124)		(11,347)		-		(95,300)
Cash used in discontinued operations		-		(87,017)		-		-		(87,017)
Net cash used in investing activities		(28,829)		(142,141)		(11,347)		-		(182,317)

Cash flows from financing activities:
Borrowings of debt		109,400		-		-		-		109,400
Repayments of debt		(317,485)		-		(4,645)		-		(322,130)
Deferred financing costs		(9,311)		-		-		-		(9,311)
Repurchases of common stock		(7,604)		-		-		-		(7,604)
Excess tax from stock-based compensation		(1,013)		-		-		-		(1,013)
Exercise of stock options, net and other		1,978		-		(1,215)		-		763
Intercompany financing		488,723		(338,118)		(126,765)		(23,840)		-
Net cash provided by (used in) financing activities		264,688		(338,118)		(132,625)		(23,840)		(229,895)

Effect of exchange rate changes on cash and cash equivalents		-		-		436		-		436
Net increase (decrease) in cash and cash equivalents		119,050		(860)		37,190		-		155,380
Cash and cash equivalents:
Balance, beginning of year		376,434		3,294		11,357		-		391,085
Balance, end of year		495,484		2,434		48,547		-		546,465
Less cash from discontinued operations, end of year		-		2		-		-		2
Cash from continuing operations, end of year	$	495,484	$	2,432	$	48,547	$	-	$	546,463

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(in thousands)


		Year Ended December 31, 2010
						Non-		Consolidating
		Helix		Guarantors		Guarantors		Entries		Consolidated
Cash flows from operating activities:
Net income (loss), including noncontrolling interests	$	(118,611)	$	(53,483)	$	4,348	$	43,593	$	(124,153)
Adjustments to reconcile net income (loss), including noncontrolling interests to net cash provided by (used in) operating activities:
Equity in earnings of affiliates		60,443		(8,473)		-		(51,970)		-
Other adjustments		94,376		45,567		76,865		(21,283)		195,525
Cash provided by (used in) operating activities		36,208		(16,389)		81,213		(29,660)		71,372
Cash provided by discontinued operations		-		260,082		-		-		260,082
Net cash provided by (used in) operating activities		36,208		243,693		81,213		(29,660)		331,454

Cash flows from investing activities:
Capital expenditures		(56,650)		(37,155)		(28,413)		-		(122,218)
Distributions from equity investments, net		-		-		2,286		-		2,286
Proceeds from insurance reimbursement		7,020		-		-		-		7,020
Proceeds from sale of assets		6,042		-		-		-		6,042
Cash used in investing activities		(43,588)		(37,155)		(26,127)		-		(106,870)
Cash used in discontinued operations		-		(74,686)		-		-		(74,686)
Net cash used in investing activities		(43,588)		(111,841)		(26,127)		-		(181,556)

Cash flows from financing activities:
Repayments of debt		(4,326)		-		(4,424)		-		(8,750)
Deferred financing costs		(2,947)		-		-		-		(2,947)
Repurchases of common stock		(11,680)		-		-		-		(11,680)
Excess tax from stock-based compensation		(3,945)		-		-		-		(3,945)
Exercise of stock options, net and other		560		-		(2,517)		-		(1,957)
Intercompany financing		147,410		(131,080)		(45,990)		29,660		-
Net cash provided by (used in) financing activities		125,072		(131,080)		(52,931)		29,660		(29,279)

Effect of exchange rate changes on cash and cash equivalents		-		-		(207)		-		(207)
Net increase in cash and cash equivalents		117,692		772		1,948		-		120,412
Cash and cash equivalents:
Balance, beginning of year		258,742		2,522		9,409		-		270,673
Balance, end of year		376,434		3,294		11,357		-		391,085
Less cash from discontinued operations, end of year		-		1		-		-		1
Cash from continuing operations, end of year	$	376,434	$	3,293	$	11,357	$	-	$	391,084

Organization (Details) $ in Millions	Feb. 06, 2013 USD ($)
Organization [Abstract]
Proceeds from Divestiture of Businesses	$ 620

Summary Of Significant Accounting Policies (Narrative) (Details)
$ / shares in Units, $ in Thousands, kr in Millions

1 Months Ended

3 Months Ended

12 Months Ended

36 Months Ended

Dec. 31, 2012

USD ($)

Mar. 31, 2011

USD ($)

May 31, 2010

USD ($)

Dec. 31, 2012

USD ($)

Sep. 30, 2012

USD ($)

Jun. 30, 2012

USD ($)

Dec. 31, 2012

USD ($)

customer

$ / shares

Dec. 31, 2011

USD ($)

Dec. 31, 2010

USD ($)

Dec. 31, 2009

USD ($)

Dec. 31, 2012

USD ($)

Jan. 31, 2013

NOK (kr)

Jan. 31, 2013

USD ($)

Jan. 31, 2009

USD ($)

Summary Of Significant Accounting Policies [Line Items]

Accruals for capital expenditures

$ 51,100

$ 26,100

$ 21,900

Cost of Property Repairs and Maintenance

38,700

32,300

29,300

Capitalized Computer Software, Gross

$ 18,500

18,500

18,100

$ 18,500

Capitalized Computer Software, Amortization

(2,600)

Asset impairment

158,000

$ 4,600

$ 14,600

Deposit Liability, Current

^[1]

50,000

Capitalized interest

(4,893)

(1,277)

(12,474)

10,563

2,240

16,743

Intangible assets with finite lives, net

62,935

62,215

62,494

^[2]

62,935

Intangible asset, gross

1,700

491

531

491

Finite-Lived Intangible Assets, Accumulated Amortization

1,200

Amortization of intangible assets

100

Finite-Lived Intangible Assets, Next Twelve Months

100

Finite-Lived Intangible Assets, Amortization Expense, Year Two

100

Finite-Lived Intangible Assets, Amortization Expense, Year Three

100

Finite-Lived Intangible Assets, Amortization Expense, Year Four

100

Deferred dry dock expenses, net

^[3]

22,704

5,381

$ 22,704

Drydock amortization expense

8,600

7,600

6,900

Value of convertible preferred stock

$ 1,000

$ 5,000

Stock Issued During Period, Shares, Conversion of Convertible Securities | shares

361,402

1,807,011

Preferred Stock, Dividend Rate, Percentage

4.00%

Foreign currency translation gain, net of tax

7,291

(1,002)

(10,005)

Foreign Currency Transaction Gain (Loss), before Tax

(500)

(2,100)

1,900

Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, before Tax

(2,661)

23,669

$ (23,726)

Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax

6,800

Notional Amount of Interest Rate Cash Flow Hedge Derivatives

$ 200,000

200,000

$ 200,000

Notional Amount of Foreign Currency Derivatives

kr 591.3

$ 104,600

Subsea services to customers | customer

Remaining ownership interest

31,688

^[4]

31,688

^[4]

$ 31,688

^[4]

9,555

31,688

^[4]

1.00%

Remaining shares of Cal Dive common stock, shares | shares

500,000

Gain (loss) on investment in Cal Dive common stock

$ 800

753

Proceeds from sale of Cal Dive common stock

$ 3,600

3,588

$ 418,200

Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value

5,946

Derivative Instruments Not Designated as Hedging Instruments, Liability, at Fair Value

16,298

159

16,298

Debt Instrument, Convertible, Remaining Discount Amortization Period

31,688

^[4]

31,688

^[4]

$ 31,688

^[4]

9,555

31,688

^[4]

6 years

Express, Caesar And Other Pipelay Equipment [Member]

Summary Of Significant Accounting Policies [Line Items]

Asset impairment

$ 157,800

Sales price

238,300

Deposit Liability, Current

50,000

Equipment In Australia [Member]

Summary Of Significant Accounting Policies [Line Items]

Asset impairment

4,600

$ 6,600

Sales price

5,000

Intrepid Vessel [Member]

Summary Of Significant Accounting Policies [Line Items]

Sales price

14,500

Gain (Loss) on Sale of Assets and Asset Impairment Charges

28,100

Segment, Discontinued Operations [Member]

Summary Of Significant Accounting Policies [Line Items]

Gas and oil imbalance

4,000

Gas Balancing Payable, Current

3,000

$ 3,000

3,000

JP Morgan Ventures [Member] | Segment, Discontinued Operations [Member]

Summary Of Significant Accounting Policies [Line Items]

Shell [Member] | Segment, Continuing Operations [Member]

26.00%

Summary Of Significant Accounting Policies [Line Items]

Shell [Member] | Segment, Discontinued Operations [Member]

12.00%

10.00%

Summary Of Significant Accounting Policies [Line Items]

BP Plc [Member] | Segment, Continuing Operations [Member]

64.00%

89.00%

67.00%

Summary Of Significant Accounting Policies [Line Items]

Louis Dreyfus Energy Services [Member] | Segment, Discontinued Operations [Member]

26.00%

Summary Of Significant Accounting Policies [Line Items]

Interest Rate Swaps [Member]

19.00%

Summary Of Significant Accounting Policies [Line Items]

Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, before Tax

$ 600

Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax

400

Foreign Exchange Forward [Member]

Summary Of Significant Accounting Policies [Line Items]

Derivative Instruments, Loss Recognized in Income

400

$ 200

$ (2,600)

Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value

$ 100

Derivative Instruments Not Designated as Hedging Instruments, Liability, at Fair Value

$ 100

Summary Of Significant Accounting Policies [Line Items]

Convertible debt stock price trigger | $ / shares

$ 38.57

Summary Of Significant Accounting Policies [Line Items]

Convertible debt stock price trigger | $ / shares

$ 32.53

Summary Of Significant Accounting Policies [Line Items]

$ 60,200

Goodwill, Beginning Balance

$ 60,200

[1]	Reflects the cash deposit we received in association with the expected sales of our two remaining pipelay vessels, the Express and the Caesar, and other related pipelay equipment (Note 2), which is refundable in very limited circumstances. The sales of these vessels are scheduled to close and fund in two stages in 2013 following the completion of each vessel’s existing backlog of work.
[2]	In 2010, we fully impaired $16.7 million of goodwill associated with our Australian well intervention subsidiary (“WOSEA”) (see below).
[3]	The increase subsequent to December 31, 2011 reflects the costs associated with the regulatory dry docks for our Q4000, Seawell and Well Enhancer vessels during 2012.
[4]	The notes will increase to their principal amount through accretion of non-cash interest charges through March 2018 for the Convertible Senior Notes due 2032.

Summary Of Significant Accounting Policies (Supplemental Cash Flow Information) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Accounting Policies [Abstract]
Interest paid, net of capitalized interest	$ 68,735	$ 81,000	$ 68,534
Income taxes paid	$ 43,111	$ 11,216	$ 10,071

Summary Of Significant Accounting Policies (Summary Of Gross Components Of Property And Equipment) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Property, Plant and Equipment [Line Items]
Property and equipment	$ 2,051,796	$ 1,815,012
ROVs/Vessels [Member]
Property, Plant and Equipment [Line Items]
Property and equipment	1,822,642	1,616,772
Machinery, Equipment, Buildings And Leasehold Improvements [Member]
Property, Plant and Equipment [Line Items]
Property and equipment	$ 229,154	$ 198,240
Maximum [Member] \| ROVs/Vessels [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	30 years
Maximum [Member] \| Machinery, Equipment, Buildings And Leasehold Improvements [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	30 years
Minimum [Member] \| ROVs/Vessels [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	10 years
Minimum [Member] \| Machinery, Equipment, Buildings And Leasehold Improvements [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	5 years

Summary Of Significant Accounting Policies (Summary Of Changes In The Carrying Amount Of Goodwill) (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Goodwill [Line Items]

$ 62,215

$ 62,494

^[1]

Contracting Services [Member]

$ (16,743)

Goodwill, Other Changes

^[2]

720

(279)

Goodwill, Ending Balance

$ 62,935

$ 62,215

62,494

^[1]

Goodwill [Line Items]

$ 16,700

[1]	In 2010, we fully impaired $16.7 million of goodwill associated with our Australian well intervention subsidiary (“WOSEA”) (see below).
[2]	Reflects foreign currency adjustment for certain amounts of our goodwill.

Carrying amount as of the balance sheet date, which is the cumulative amount paid and (if applicable) the fair value of any noncontrolling interest in the acquiree, adjusted for any amortization recognized prior to the adoption of any changes in generally accepted accounting principles (as applicable) and for any impairment charges, in excess of the fair value of net assets acquired in one or more business combination transactions.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=14024403&loc=d3e13816-109267

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 45
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6388280&loc=d3e13770-109266

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 45
-Subparagraph e
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 43
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 72
-Subparagraph d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 45
-Subparagraph e
-Clause 1
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 68
-Subparagraph l
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 34
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Loss recognized during the period that results from the write-down of goodwill after comparing the implied fair value of reporting unit goodwill with the carrying amount of that goodwill. Goodwill is assessed at least annually for impairment.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 2
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=14024403&loc=d3e13854-109267

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6388280&loc=d3e13777-109266

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 230
-SubTopic 10
-Section 45
-Paragraph 28
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=6943989&loc=d3e3602-108585

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (e)
-URI http://asc.fasb.org/extlink&oid=14024403&loc=d3e13816-109267

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 72
-Subparagraph d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 43
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 20
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 45
-Subparagraph e
-Clause 5
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 47
-Subparagraph b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Net income applicable to common shareholders

Summary Of Significant Accounting Policies (Computations Of Basic And Diluted EPS) (Details) - USD ($)
shares in Thousands, $ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Earnings Per Share [Abstract]

$ (171,567)

$ 14,865

$ 44,641

$ 65,727

$ 16,753

$ 46,016

$ 41,313

$ 25,857

$ (46,334)

$ 129,939

$ (127,102)

Less: Undistributed net income allocable to participating securities

(1,599)

Net income (loss) applicable to common shareholders

(46,334)

128,340

(127,102)

Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent

(23,684)

(95,221)

106,657

Add: Undistributed net income from discontinued operations allocable to participating securities

1,172

Income (Loss) from Continuing Operations Attributable to Parent, Total

(99,679)

10,362

2,425

16,874

17,487

15,999

10,547

(9,315)

$ (70,018)

$ 34,291

$ (20,445)

Weighted average number of shares outstanding - basic

104,449

104,528

103,857

Stock options, Shares

Undistributed earnings reallocated to participating securities, value

$ 2

Convertible preferred stock, Shares

$ 40

361

Income (loss) from continuing operations applicable to Helix common shareholders - Diluted

$ (70,018)

$ 34,333

$ (20,445)

Income (loss) from discontinued operations, net of tax

$ (71,888)

^[1]

$ 4,503

^[1]

$ 42,216

^[1]

$ 48,853

^[1]

$ (734)

$ 30,017

$ 30,766

$ 35,172

23,684

95,221

(106,657)

Net income per common share - Diluted

$ (46,334)

$ 129,554

$ (127,102)

Weighted average number of shares outstanding, diluted, total

104,449

104,953

103,857

[1]	Our net loss in the fourth quarter of 2012 includes a $138.6 million impairment charge associated with the sale of ERT (Note 3).

Summary Of Significant Accounting Policies (Summary Of Shares Excluded In Diluted Per Share Calculations) (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Diluted (in shares)	104,449	104,953	103,857
Total	105,165		105,338
Share-based Awards [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive securities	382		466
Convertible Preferred Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive securities	334		1,015

Securities (including those issuable pursuant to contingent stock agreements) that could potentially dilute basic earnings per share (EPS) or earnings per unit (EPU) in the future that were not included in the computation of diluted EPS or EPU because to do so would increase EPS or EPU amounts or decrease loss per share or unit amounts for the period presented.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Antidilution
-URI http://asc.fasb.org/extlink&oid=6505113

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Diluted Earnings Per Share
-URI http://asc.fasb.org/extlink&oid=6510752

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Contingent Stock Agreement
-URI http://asc.fasb.org/extlink&oid=6508534

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 260
-SubTopic 10
-Section 50
-Paragraph 1
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=6371337&loc=d3e3550-109257

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 128
-Paragraph 40
-Subparagraph c
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 128
-Paragraph 13, 14
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 07-4
-Paragraph 4
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 128
-Paragraph 171
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

The average number of shares or units issued and outstanding that are used in calculating diluted EPS or earnings per unit (EPU), determined based on the timing of issuance of shares or units in the period.

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Summary Of Significant Accounting Policies (Assets And Liabilities Measured At Fair Value On A Recurring Basis) (Details)
$ in Thousands

Dec. 31, 2012

USD ($)

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

$ (1,127,850)

Level 1 [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

(994,311)

Level 2 [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

(133,539)

^[1]

Level 3 [Member]

Foreign Currency Forwards [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Foreign Currency Forwards [Member] | Level 1 [Member]

146

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Foreign Currency Forwards [Member] | Level 2 [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Foreign Currency Forwards [Member] | Level 3 [Member]

146

^[1]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Oil Contracts [Member]

Oil Contracts [Member] | Level 1 [Member]

5,800

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Oil Contracts [Member] | Level 2 [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Oil Contracts [Member] | Level 3 [Member]

5,800

^[1]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Oil Contracts [Member]

Oil Contracts [Member] | Level 1 [Member]

15,777

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Oil Contracts [Member] | Level 2 [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Oil Contracts [Member] | Level 3 [Member]

15,777

^[1]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair Value Of Long Term Debt [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair Value Of Long Term Debt [Member] | Level 1 [Member]

1,117,498

^[2]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair Value Of Long Term Debt [Member] | Level 2 [Member]

994,311

^[2]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair Value Of Long Term Debt [Member] | Level 3 [Member]

123,187

^[1],[2]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Interest Rate Swaps [Member]

^[2]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Interest Rate Swaps [Member] | Level 1 [Member]

521

^[2]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Interest Rate Swaps [Member] | Level 2 [Member]

^[2]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Interest Rate Swaps [Member] | Level 3 [Member]

521

^[1],[2]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

^[2]

[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 based on market data. 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 December 31, 2012 and 2011 is as follows: 20122011Carrying ValueFair ValueCarrying ValueFair ValueTerm Loans (mature July 2015) (a)$ 367,181$ 368,295$ 279,750$ 279,750Revolving Credit Facility (matures July 2015) (a) 100,000 100,000 - -2025 Notes (mature December 2025) (b) 3,487 3,487 300,000 300,5432032 Notes (mature March 2032) (c) 200,000 239,320 - -Senior Unsecured Notes (mature January 2016) 274,960 283,209 474,960 501,083MARAD Debt (matures February 2027) (d) 105,288 123,187 110,166 124,488Total debt$ 1,050,916$ 1,117,498$ 1,164,876$ 1,205,864(a) In February 2013, we repaid $293.9 million of our Term Loans and $24.5 million under our Revolving Credit Facility with the after-tax proceeds from the sale of ERT. (b) Carrying value excludes the related unamortized debt discount of $9.6 million at December 31, 2011. This remaining amount was repurchased by us in February 2013. (c) Carrying value excludes the related unamortized debt discount of $31.7 million at December 31, 2012. (d ) 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.

Summary Of Significant Accounting Policies (Fair Value Of Long Term Debt) (Details) - USD ($)
$ in Thousands

1 Months Ended

12 Months Ended

Feb. 28, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Feb. 19, 2013

Mar. 31, 2012

Mar. 31, 2005

Repayment of Helix Term Notes

$ 31,688

^[1]

$ 31,688

^[1]

$ 9,555

12,569

130,691

$ 4,326

Term Loan [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

^[2]

367,181

279,750

Revolving Credit Facility [Member]

^[2]

368,295

279,750

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

100,000

^[2]

100,000

^[2]

$ 78,100

^[2]

100,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

3,487

^[3]

3,487

^[3]

300,000

^[3]

$ 300,000

^[3]

3,487

300,543

Repayment of Helix Term Notes

9,600

$ 3,500

154,300

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

274,960

474,960

283,209

501,083

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

^[4]

105,288

110,166

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

^[4]

123,187

124,488

Loan Notes [Member]

1,050,916

1,164,876

1,117,498

$ 1,205,864

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

200,000

^[5]

200,000

^[5]

$ 200,000

^[5]

239,320

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

$ 31,688

^[1],[6]

$ 31,688

^[1],[6]

$ 35,400

[1]	The notes will increase to their principal amount through accretion of non-cash interest charges through March 2018 for the Convertible Senior Notes due 2032.
[2]	In February 2013, we repaid $293.9 million of our Term Loans and $24.5 million under our Revolving Credit Facility with the after-tax proceeds from the sale of ERT.
[3]	Carrying value excludes the related unamortized debt discount of $9.6 million at December 31, 2011.
[4]	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.
[5]	Carrying value excludes the related unamortized debt discount of $31.7 million at December 31, 2012.
[6]	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 notes. These notes will mature in March 2032.

Oil And Gas Properties (Narrative) (Details) $ in Thousands		1 Months Ended	12 Months Ended
Oil And Gas Properties (Narrative) (Details) $ in Thousands	Feb. 06, 2013 USD ($)	Dec. 31, 2011 USD ($)	Dec. 31, 2012 USD ($)	Dec. 31, 2011 USD ($) item	Dec. 31, 2010 USD ($) item
Oil And Gas Properties [Line Items]
Supplies		$ 1,677	$ 2,480	$ 1,677
Inventory Write-down				2,100
Pipe Inventory Sold		4,600		$ 4,600
Non-hedge loss on commodity derivative contracts			(10,507)
Number of oil and gas properties impaired \| item				11	21
Proceeds from Divestiture of Businesses	$ 620,000
Gas Balancing Asset (Liability)			1,000
Dry hole expense			(55)	$ (70)	$ (424)
Oil and gas property impairments			138,600	90,900	176,700
Impairment of unproved properties			833	8,334	6,394
Capitalized exploration cost			8,200
Royalty Payments To US Government			78,100	85,400	37,200
Asset retirement obligation		227,090	200,978	227,090	$ 222,653
AssetRetirementObligationRevisionOfEstimate			62,834	$ 22,345
Number Of Oil And Gas Properties Impaired \| item				11	21
Net interest expense			48,160	$ 70,181	$ 65,589
Proceeds from Sale of Other Assets		2,500
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax			6,800
Energy Resource Technology GOM, Inc [Member]
Oil And Gas Properties [Line Items]
Net interest expense			27,700	25,200	19,700
Camelot Field [Member]
Oil And Gas Properties [Line Items]
Oil and gas property impairments					4,100
Asset retirement obligation		27,300		27,300
Abandonment Expense			15,500
Non Producing Oil And Gas Properties [Member]
Oil And Gas Properties [Line Items]
AssetRetirementObligationRevisionOfEstimate			12,400	22,500
Gulf Of Mexico Oil And Gas Properties [Member]
Oil And Gas Properties [Line Items]
Oil and gas property impairments					172,600
Non-Domestic Oil And Gas Property [Member]
Oil And Gas Properties [Line Items]
Oil and gas property impairments					$ 4,100
Segment, Discontinued Operations [Member]
Oil And Gas Properties [Line Items]
Supplies		16,400	11,900	16,400
Restricted cash		$ 33,700	28,400	$ 33,700
Other Assets Current Gas Imbalances			4,000
Gas Balancing Payable, Current			$ 3,000

Oil And Gas Properties (Changes In Asset Retirement Obligations) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Asset Retirement Obligation [Abstract]
Asset retirement obligations at January 1,	$ 227,090	$ 222,653
Liability incurred during the period	3,664	4,982
Liability settled during the period	(105,160)	(37,769)
Other revisions in estimated cash flows	62,834	22,345
Accretion expense (included in depreciation and amortization)	12,550	14,879
Asset retirement obligations at December 31,	$ 200,978	$ 227,090

Oil and Gas Properties (Income (Loss) From Discontinued Operations) (Details) - USD ($)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2012

^[1]

Sep. 30, 2012

^[1]

Jun. 30, 2012

^[1]

Mar. 31, 2012

^[1]

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Exploration expense

$ 3,295

$ 10,914

$ 8,276

Income (loss) from discontinued operations, net of tax

$ (71,888)

$ 4,503

$ 42,216

$ 48,853

$ (734)

$ 30,017

$ 30,766

$ 35,172

23,684

95,221

(106,657)

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Income (loss) from discontinued operations, net of tax

(1,621)

Energy Resource Technology GOM, Inc [Member]

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Production (lifting) costs

557,231

696,607

425,369

164,663

176,269

131,156

Hurricane repair expense

662

(4,838)

4,699

Exploration expense

^[2]

3,295

10,914

8,276

Depreciation, depletion, amortization and accretion

158,284

219,915

235,243

Proved property impairment charges and other

^[3]

151,045

113,439

177,138

(Gain) loss on sale of oil and gas properties

1,714

(4,531)

(287)

(Gain) loss on oil and gas derivative contracts

(5,550)

(1,088)

Selling and administrative expense

17,823

12,951

15,966

Interest expense, net and other

^[4]

28,191

25,558

19,687

Total costs

520,127

549,677

590,790

Pretax income (loss) from discontinued operations

37,104

146,930

(165,421)

DiscontinuedOperationTaxEffectOfDiscontinuedOperation

13,420

51,709

(58,764)

Income (loss) from discontinued operations, net of tax

$ 23,684

$ 95,221

$ (106,657)

[1]	Our net loss in the fourth quarter of 2012 includes a $138.6 million impairment charge associated with the sale of ERT (Note 3).
[2]	See “Exploration and Other” below for additional information related to the components of our exploration costs, including impairment charges for expiring unproved leases.
[3]	Includes $138.6 million recorded to reduce our carrying value of ERT to its estimated fair value less costs to sell.
[4]	Net interest expense of $27.7 million, $25.2 million and $19.7 million for the years ended December 31, 2012, 2011 and 2010, respectively, was allocated to ERT primarily based on interest associated with indebtedness directly attributed to the substantial acquisition made by our oil and gas subsidiary in 2006. This includes interest related to debt required to be paid upon the disposition of ERT.

Oil And Gas Properties (Major Classes Of Assets And Liabilities) (Details) - USD ($)
$ in Thousands

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

$ 2

$ 1

84,000

118,921

Current asset retirement obligations

816,227

905,399

^[1]

2,898

27,300

182,527

166,975

Energy Resource Technology GOM, Inc [Member]

147,237

161,208

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Accounts receivable

63,762

90,882

20,236

28,037

84,000

118,921

787,852

871,658

28,375

33,741

816,227

905,399

110,569

73,124

Current asset retirement obligations

18,217

27,968

53,741

65,883

Asset retirement obligations

182,527

166,975

147,237

161,208

Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]

$ 147,237

$ 161,208

[1]	Reflects the substantial completion of the abandonment of the Camelot field (Note 3).

Oil And Gas Properties (Capitalized Exploratory Project Costs) (Details) - USD ($)
$ in Thousands

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]

$ 8,247

$ 5,840

$ 3,252

$ 3,059

T-6 [Member]

Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]

^[1]

8,122

Wang [Member]

Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]

^[1]

3,096

Danny 2 [Member]

Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]

2,619

Other [Member]

$ 125

[1]	Both of these wells are located within the Phoenix field at Green Canyon Block 237.

Oil And Gas Properties (Changes In Suspended Exploratory Well Costs) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Oil And Gas Properties [Abstract]
Capitalized Exploratory Well Costs, Beginning Balance	$ 5,840	$ 3,252	$ 3,059
Capitalized Exploratory Well Cost, Additions Pending Determination of Proved Reserves	135,311	2,513	(944)
Reclassification to Well, Facilities, and Equipment Based on Determination of Proved Reserves	(132,959)	5	713
Capitalized Exploratory Well Cost, Charged to Expense	55	70	424
Capitalized Exploratory Well Costs, Ending Balance	$ 8,247	$ 5,840	$ 3,252

Oil And Gas Properties (Components Of Exploration Expenses) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Oil And Gas Properties [Abstract]
Delay rental and geological and geophysical costs	$ 2,517	$ 2,650	$ 2,306
Impairment of unproved properties	833	8,334	6,394
Dry hole expense	(55)	(70)	(424)
Total exploration expense	$ 3,295	$ 10,914	$ 8,276

Exploration expenses (including prospecting) related to oil and gas producing entities and would be included in operating expenses of that entity. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are: (i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs. (ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records. (iii) Dry hole contributions and bottom hole contributions. (iv) Costs of drilling and equipping exploratory wells. (v) Costs of drilling exploratory-type stratigraphic test wells.

Details Of Certain Accounts (Other Current Assets) (Details) - USD ($)
$ in Thousands

Dec. 31, 2012

Dec. 31, 2011

Current deferred tax assets

Other receivables

$ 1,086

$ 618

Prepaid insurance

11,999

12,608

Other prepaids

11,751

11,328

Spare parts inventory

2,480

1,677

Income tax receivable

^[1]

14,201

43,942

41,449

Hedging assets

5,946

21,579

Other

5,529

4,325

Total other current assets

$ 96,934

$ 93,584

[1]	Reflects the total amount of estimated tax receivable in excess of the estimated current income tax liability.

Details Of Certain Accounts (Other Assets, Net) (Details) - USD ($)
$ in Thousands

Dec. 31, 2012

Dec. 31, 2011

Deferred dry dock expenses, net

^[1]

$ 22,704

$ 5,381

Deferred financing costs, net

24,338

26,483

Intangible assets with finite lives, net

491

531

Other

2,304

2,771

Total other assets, net

$ 49,837

$ 35,166

[1]	The increase subsequent to December 31, 2011 reflects the costs associated with the regulatory dry docks for our Q4000, Seawell and Well Enhancer vessels during 2012.

Details Of Certain Accounts (Accrued Liabilities) (Details) - USD ($)
$ in Thousands

Dec. 31, 2012

Dec. 31, 2011

Accrued payroll and related benefits

$ 51,561

$ 45,217

Current asset retirement obligations (Note 4)

^[1]

2,898

27,300

Unearned revenue

6,137

7,654

Billing in excess of cost

^[2]

6,445

28,839

Accrued interest

17,451

24,028

Hedging liability

^[3]

16,266

1,247

Taxes payable excluding income tax payable

5,164

3,748

Pipelay assets sale deposit (Note 2)

^[4]

50,000

Other

5,592

8,079

Total accrued liabilities

$ 161,514

$ 146,112

[1]	Reflects the substantial completion of the abandonment of the Camelot field (Note 3).
[2]	Decrease reflects fewer ongoing subsea construction projects using the percentage-of-completion method of accounting as a result of the expected sales of our remaining pipelay vessels.
[3]	Primarily reflects the fair value of oil commodity derivative contracts of $15.8 million at December 31, 2012 (Note 17). These contracts were settled in February 2013.
[4]	Reflects the cash deposit we received in association with the expected sales of our two remaining pipelay vessels, the Express and the Caesar, and other related pipelay equipment (Note 2), which is refundable in very limited circumstances. The sales of these vessels are scheduled to close and fund in two stages in 2013 following the completion of each vessel’s existing backlog of work.

Equity Investments (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended		12 Months Ended
Equity Investments (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Equity investments in unconsolidated affiliates	$ 175,656			$ 167,599	$ 175,656
Equity in earnings of investments				$ 8,434	22,215	$ 19,469
Other than temporary loss on equity investments					10,563	2,240
Deepwater Gateway, L.L.C. [Member]
Equity method investment, ownership percentage				50.00%
Equity investments in unconsolidated affiliates	96,000			$ 91,400	96,000
Capitalized interest	1,400			$ 1,300	1,400
Independence Hub, LLC [Member]
Equity method investment, ownership percentage				20.00%
Equity investments in unconsolidated affiliates	79,700			$ 76,200	79,700
Capitalized interest	$ 4,900			$ 4,600	$ 4,900
Clough Helix JV [Member]
Equity method investment, ownership percentage	50.00%	50.00%			50.00%
Equity in earnings of investments		$ 3,700	$ (3,800)		$ 2,100	$ (3,600)
Exit Fee			$ 3,000
Other than temporary loss on equity investments	$ 10,600

The charge against earnings in the period, comprised of costs incurred associated with an exit or disposal activity other than for a discontinued operations as defined under generally accepted accounting principles. Costs of such activities include those for one-time termination benefits, termination of an operating lease or other contract, consolidating or closing facilities, and relocating employees, and costs associated with an ongoing benefit arrangement, but excludes costs associated with the retirement of a long-lived asset.

This item represents the entity's proportionate share for the period of the net income (loss) of its investee (such as unconsolidated subsidiaries and joint ventures) to which the equity method of accounting is applied. This item includes income or expense related to stock-based compensation based on the investor's grant of stock to employees of an equity method investee.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 323
-SubTopic 10
-Section 45
-Paragraph 1
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 230
-SubTopic 10
-Section 45
-Paragraph 28
-Subparagraph (b)
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 225
-SubTopic 10
-Section S99
-Paragraph 2
-Subparagraph (SX 210.5-03.12)
-URI http://asc.fasb.org/extlink&oid=6880815&loc=d3e20235-122688

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 03
-Paragraph 9
-Article 5

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 18
-Paragraph 19
-Subparagraph c
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 18
-Paragraph 6
-Subparagraph b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 04
-Paragraph 11
-Article 7

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 95
-Paragraph 28
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Equity Investments (Contributions To Equity Investments) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Schedule of Equity Method Investments [Line Items]
Contributions to equity investments	$ 2,699	$ 8,253
Clough Helix JV [Member]
Schedule of Equity Method Investments [Line Items]
Contributions to equity investments	$ 2,699	$ 8,253

Equity Investments (Distributions From Equity Investments) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Schedule of Equity Method Investments [Line Items]
Distributions from equity investments	$ 16,230	$ 26,180	$ 30,008
Deepwater Gateway, L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Distributions from equity investments	8,157	7,600	8,125
Independence Hub, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Distributions from equity investments	$ 8,073	$ 18,580	21,615
Other [Member]
Schedule of Equity Method Investments [Line Items]
Distributions from equity investments			$ 268

Equity Investments (Schedule Of Summarized Aggregated Financial Information Related To The Subsidiaries) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Equity Investments [Abstract]
Revenues	$ 53,159	$ 193,521	$ 141,705
Operating income	30,463	97,954	93,324
Net income	30,463	93,215	93,005
Current assets	16,682	39,754	25,352
Total assets	537,251	591,761	594,645
Current liabilities	706	11,012	6,434
Total liabilities	$ 5,320	$ 27,163	$ 19,695

The amount of assets reported by an equity method investment of the entity.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 323
-SubTopic 10
-Section 50
-Paragraph 3
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=6382943&loc=d3e33918-111571

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=6382943&loc=d3e33912-111571

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph w
-Article 1

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 18
-Paragraph 20
-Subparagraph d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph bb
-Article 1

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
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-Subparagraph f
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph g
-Subparagraph 1, 2
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The amount of current assets reported by an equity method investment of the entity.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 323
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-Section 50
-Paragraph 3
-Subparagraph (c)
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-Name Accounting Standards Codification
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 18
-Paragraph 20
-Subparagraph d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph bb
-Article 1

Reference 7: http://www.xbrl.org/2003/role/presentationRef
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-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph w
-Article 1

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph g
-Subparagraph 1, 2
-Article 4

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 18
-Subparagraph f
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

The amount of current liabilities reported by an equity method investment of the entity.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 323
-SubTopic 10
-Section 50
-Paragraph 3
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=6382943&loc=d3e33918-111571

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 323
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6382943&loc=d3e33912-111571

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(g))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
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-Section 50
-Paragraph 28
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-URI http://asc.fasb.org/extlink&oid=6957238&loc=d3e14064-108612

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 18
-Subparagraph f
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 18
-Paragraph 20
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph g
-Subparagraph 1, 2
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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-Name Regulation S-X (SX)
-Number 210
-Section 02
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-Article 1

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
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-Article 1

The amount of liabilities reported by an equity method investment of the entity.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 323
-SubTopic 10
-Section 50
-Paragraph 3
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-URI http://asc.fasb.org/extlink&oid=6382943&loc=d3e33918-111571

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 323
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-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6382943&loc=d3e33912-111571

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 28
-Subparagraph (f)
-URI http://asc.fasb.org/extlink&oid=6957238&loc=d3e14064-108612

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
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-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(g))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 18
-Paragraph 20
-Subparagraph d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph g
-Subparagraph 1, 2
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph w
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 18
-Subparagraph f
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

The amount of net income (loss) reported by an equity method investment of the entity.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 323
-SubTopic 10
-Section 50
-Paragraph 3
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=6382943&loc=d3e33918-111571

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 28
-Subparagraph (f)
-URI http://asc.fasb.org/extlink&oid=6957238&loc=d3e14064-108612

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(g))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 323
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6382943&loc=d3e33912-111571

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph bb
-Article 1

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 18
-Subparagraph f
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 18
-Paragraph 20
-Subparagraph d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph w
-Article 1

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph g
-Subparagraph 1, 2
-Article 4

Kommandor LLC (Details) - USD ($) $ in Thousands	12 Months Ended
Kommandor LLC (Details) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Noncontrolling Interest [Line Items]
Oil and gas processing equipment, percentage of cost	100.00%
Property and equipment	$ 2,051,796	$ 1,815,012
Noncontrolling Interest, Ownership Percentage by Parent	81.00%
Working interest	70.00%
Estimated cash outlay	$ 19,000
Conversion Of The Vessel [Member]
Noncontrolling Interest [Line Items]
Property and equipment	148,700
Topside Oil And Gas Processing Facilities [Member]
Noncontrolling Interest [Line Items]
Property and equipment	$ 196,300

Long-Term Debt (Narrative) (Details) - USD ($)

1 Months Ended

3 Months Ended

12 Months Ended

Feb. 28, 2013

Dec. 31, 2012

Mar. 31, 2012

Mar. 31, 2005

Mar. 31, 2012

Sep. 30, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Feb. 19, 2013

Aug. 31, 2012

Mar. 06, 2012

Feb. 21, 2012

Dec. 31, 2007

Jul. 31, 2006

Sep. 30, 2005

Indebtedness Of Foreign Subsidiaries

$ 400,000,000

$ 200,000,000

Aggregate amount of debt payment

1,002,621,000

$ 1,147,444,000

209,500,000

77,394,000

Accelerated amortization of debt discount

9,729,000

8,973,000

$ 8,409,000

Loss on early extinguishment of debt

17,127,000

2,354,000

Interest rate swap

200,000,000

Deferred financing costs, net

24,338,000

26,483,000

Amortization of deferred financing costs

9,086,000

8,910,000

7,703,000

Repayment of revolving credit facility

109,400,000

Notional Amount of Interest Rate Cash Flow Hedge Derivatives

200,000,000

Expected life used to estimate fair value

31,688,000

^[1]

$ 31,688,000

^[1]

9,555,000

6 years

Deferred financing costs

$ 7,580,000

9,311,000

2,947,000

Line of Credit Facility, Commitment Fee Percentage

$ 12,569,000

$ 130,691,000

4,326,000

0.50%

Debt Instrument Convertible Conversion Premium Percentage

Base Principal Amount

1,000

$ 1,000

35.00%

Issuance Of Notes Percentage

100.00%

Convertible Senior Notes, shares of common stock

39.9752

^[2]

168,312,000

$ 168,312,000

$ 200,000,000

^[3]

$ 200,000,000

^[3]

Per share conversion price

3.25%

Effective interest rate

6.90%

$ 25.02

Proceeds from Issuance of Debt

$ 195,000,000

Closing price per share

$ 18.53

$ 31,688,000

^[1],[2]

35,400,000

$ 35,400,000

$ 31,688,000

^[1],[2]

Helix Term Loan [Member]

Mandatory Prepayments Percentage

60.00%

^[4]

$ 359,181,000

Revolving credit facility, outstanding

$ 73,300,000

$ 100,000,000

$ 835,000,000

Average interest rate

3.70%

3.80%

Term Loan, annual amortization of principal balance

$ 5,000,000

Revolving Credit Facility [Member]

$ 293,900,000

Unsecured letters of credit

$ 12,400,000

Original borrowing capacity

100,000,000

^[5]

100,000,000

^[5]

$ 78,100,000

600,000,000

$ 300,000,000

Revolving credit facility, outstanding

$ 100,000,000

100,000,000

$ 100,000,000

Average interest rate

3.00%

Revolving credit facility available

$ 487,600,000

Helix Revolving Loans [Member]

^[4]

100,000,000

24,500,000

Senior Unsecured Notes amount issued

$ 550,000,000

274,960,000

$ 475,000,000

$ 550,000,000

Percentage Of Principal To Be Paid Due To Change Of Control

274,960,000

$ 274,960,000

474,960,000

101.00%

Aggregate amount of debt payment

9.50%

213,500,000

$ 77,400,000

Payment on senior notes

200,000,000

75,000,000

Premium on debt extinguishment

9,500,000

2,400,000

Accrued interest on notes

4,000,000

800,000

Loss on early extinguishment of debt

$ 11,500,000

Amortization of deferred financing costs

2,000,000

$ 900,000

$ 3,487,000

^[6]

$ 300,000,000

3,487,000

^[6]

300,000,000

^[6]

Premium on debt extinguishment

3.25%

Payment on senior notes

145,100,000

1,800,000

Accrued interest on notes

1,100,000

Accelerated amortization of debt discount

3,500,000

Loss on early extinguishment of debt

$ 5,600,000

Debt instrument issued percentage

100.00%

Effective interest rate

6.60%

Per share conversion price

$ 32.14

Amortization of deferred financing costs

$ 300,000

Debt Instrument, Repurchase Amount

$ 142,200,000

9,600,000

$ 3,500,000

$ 154,300,000

100,168,000

^[7]

$ 105,288,000

$ 110,166,000

4.93%

Debt percentage guaranteed

0.20%

50.00%

Minimum [Member]

Cash and cash equivalents plus available capacity under revolving credit facility

$ 400,000,000

Commitment fee percentage

2.00%

Minimum [Member] | Helix Term Loan [Member]

Minimum [Member] | Helix Revolving Loans [Member]

2.25%

1.50%

Maximum [Member]

Commitment fee percentage

3.00%

Maximum [Member] | Helix Term Loan [Member]

Maximum [Member] | Helix Revolving Loans [Member]

3.50%

3.50%

[1]	The notes will increase to their principal amount through accretion of non-cash interest charges through March 2018 for the Convertible Senior Notes due 2032.
[2]	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 notes. These notes will mature in March 2032.
[3]	Carrying value excludes the related unamortized debt discount of $31.7 million at December 31, 2012.
[4]	Term Loan amounts reflect both our Term Loan A and Term Loan B. In February 2013, we repaid $293.9 million of our Term Loans and $24.5 million under our Revolving Credit Facility with the after-tax proceeds from the sale of ERT.
[5]	In February 2013, we repaid $293.9 million of our Term Loans and $24.5 million under our Revolving Credit Facility with the after-tax proceeds from the sale of ERT.
[6]	Carrying value excludes the related unamortized debt discount of $9.6 million at December 31, 2011.
[7]	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.

Long-Term Debt (Schedule of Long-Term Debt) (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2012

Mar. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

$ 1,019,228

$ 1,155,321

(16,607)

(7,877)

1,002,621

1,147,444

(31,688)

^[1]

(9,555)

902,453

1,042,155

^[2]

168,312

(31,688)

^[1],[2]

$ (35,400)

Helix Term Loan [Member]

367,181

279,750

^[3]

$ 359,181

Revolving Credit Facility [Member]

July 2015

$ 100,000

July 2015

2025 Notes [Member]

$ 3,487

300,000

December 2025

2032 Notes [Member]

$ 200,000

Helix Revolving Loans [Member]

March 2032

^[3]

$ 100,000

274,960

474,960

$ 274,960

475,000

$ 550,000

January 2016

(9,600)

$ 105,288

$ 110,166

$ 100,168

February 2027

[1]	The notes will increase to their principal amount through accretion of non-cash interest charges through March 2018 for the Convertible Senior Notes due 2032.
[2]	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 notes. These notes will mature in March 2032.
[3]	Term Loan amounts reflect both our Term Loan A and Term Loan B. In February 2013, we repaid $293.9 million of our Term Loans and $24.5 million under our Revolving Credit Facility with the after-tax proceeds from the sale of ERT.

Long-Term Debt (Schedule Of Redemption Price By Maturity) (Details)	12 Months Ended
	Dec. 31, 2012
Long-Term Debt [Abstract]
Redemption Price, 2012	104.75%
Redemption Price, 2013	102.375%
Redemption Price, 2014 and thereafter	100.00%

Long-Term Debt (Schedule of Deferred Financing Costs) (Details) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Helix Term Loan [Member]
Gross Carrying Amount	$ 15,318	$ 13,680
Accumulated Amortization	(11,595)	(10,257)
Net	3,723	3,423
2025 Notes [Member]
Gross Carrying Amount	8,189	8,189
Accumulated Amortization	(8,189)	(7,340)
Net		849
2032 Notes [Member]
Gross Carrying Amount	4,251	78
Accumulated Amortization	(534)
Net	3,717	78
Helix Revolving Loans [Member]
Gross Carrying Amount	20,021	19,236
Accumulated Amortization	(12,466)	(9,640)
Net	7,555	9,596
Senior Unsecured Notes [Member]
Gross Carrying Amount	10,643	10,643
Accumulated Amortization	(8,252)	(5,546)
Net	2,391	5,097
MARAD Debt [Member]
Gross Carrying Amount	12,200	12,200
Accumulated Amortization	(5,248)	(4,760)
Net	6,952	7,440
Debt [Member]
Gross Carrying Amount	70,622	64,026
Accumulated Amortization	(46,284)	(37,543)
Net	$ 24,338	$ 26,483

Long-Term Debt (Maturities Of Long-Term Debt) (Details) - USD ($)
$ in Thousands

Dec. 31, 2012

Mar. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

$ 16,607

13,376

456,825

280,886

6,222

277,000

1,050,916

(16,607)

$ (7,877)

1,034,309

(31,688)

^[1]

(9,555)

1,002,621

1,147,444

Helix Term Loan [Member]

Less than one year

^[2]

8,000

One to two years

^[2]

8,000

Two to three years

^[2]

351,181

^[2]

367,181

^[2]

(8,000)

^[2]

359,181

Helix Revolving Loans [Member]

^[2]

359,181

Two to three years

^[2]

100,000

^[2]

100,000

^[2]

100,000

^[2]

100,000

Three to four years

274,960

274,960

274,960

274,960

475,000

$ 550,000

Less than one year

^[3]

3,487

^[3]

3,487

^[3]

(3,487)

(9,600)

5,120

5,376

5,644

5,926

6,222

77,000

105,288

(5,120)

100,168

100,168

Over five years

^[4]

200,000

^[4]

200,000

^[4]

200,000

(31,688)

^[1],[4]

$ (35,400)

^[4]

168,312

(11,487)

(3,000)

$ 902,453

$ 1,042,155

[1]	The notes will increase to their principal amount through accretion of non-cash interest charges through March 2018 for the Convertible Senior Notes due 2032.
[2]	Term Loan amounts reflect both our Term Loan A and Term Loan B. In February 2013, we repaid $293.9 million of our Term Loans and $24.5 million under our Revolving Credit Facility with the after-tax proceeds from the sale of ERT.
[3]	We repurchased the remainder of the 2025 Notes in February 2013 (see “2025 Notes” above).
[4]	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 notes. These notes will mature in March 2032.

Long-Term Debt (Interest Expense And Capitalized Interest) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Long-Term Debt [Abstract]
Interest expense	$ 53,601	$ 72,824	$ 78,609
Interest income	(548)	(1,366)	(546)
Capitalized interest	(4,893)	(1,277)	(12,474)
Interest expense, net	$ 48,160	$ 70,181	$ 65,589

Income Taxes (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
Income Taxes (Narrative) (Details) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income Taxes [Line Items]
Statutory rate	35.00%	35.00%	35.00%
Operating Loss Carryforwards	$ 17,600
Tax Credit Carryforward, Amount	$ 6,700
Operating Loss Carryforwards, Expiration Dates	2030
Tax Credit Carryforward, Expiration Date	Sep. 15, 2020
Valuation allowance	$ 16,391	$ 14,310
Liability for Uncertain Tax Positions, Noncurrent	4,500
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	3,400	6,200	$ 3,400
Income tax benefit	59,158	36,806	(19,166)
Income Tax Examination, Penalties and Interest Expense	200	200	700
Undistributed Earnings of Foreign Subsidiaries	167,900	113,400
Income Tax Examination, Penalties and Interest Accrued	1,100	900
Helix [Member]
Income Taxes [Line Items]
Income tax benefit	96,328	63,242	$ 9,175
Unrecognized Tax Benefits, Decreases Resulting from Prior Period Tax Positions	$ (2,785)
Australian Subsidiary [Member]
Income Taxes [Line Items]
Income tax benefit		$ 31,300

Income Taxes (Schedule Of Components Of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income Taxes [Abstract]
Current	$ 6,572	$ (78,150)	$ (22,930)
Deferred	(65,730)	41,344	42,096
Income Tax Expense (Benefit), Total	(59,158)	(36,806)	19,166
Domestic	(78,211)	(51,590)	1,596
Foreign	$ 19,053	$ 14,784	$ 17,570

The component of income tax expense for the period representing amounts of income taxes paid or payable (or refundable) for the period for all income tax obligations as determined by applying the provisions of relevant enacted tax laws to relevant amounts of taxable Income or Loss from continuing operations.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 9
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32639-109319

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(h))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Current Tax Expense (or Benefit)
-URI http://asc.fasb.org/extlink&oid=6509736

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SAB TOPIC 6.I.7)
-URI http://asc.fasb.org/extlink&oid=6889476&loc=d3e330036-122817

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 45
-Subparagraph a
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 6
-Section I
-Subsection 7

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 289
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

The change during the period in the entity's deferred tax assets and liabilities attributable to continuing operations as determined by applying enacted tax laws other than federal, domestic, foreign, state or local. Items affecting deferred income taxes and required to be disclosed, but not included elsewhere, would also be designated as "Other"; for example, adjustments of a deferred tax liability or asset for enacted changes in tax laws or rates or a change in the tax status of the entity and adjustments to be beginning-of-year balance of a valuation allowance because of a change in circumstance that causes a change in judgment about the realizability of the related deferred tax asset in future periods.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 9
-Subparagraph (g),(h)
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32639-109319

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SAB TOPIC 6.I.7)
-URI http://asc.fasb.org/extlink&oid=6889476&loc=d3e330036-122817

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Deferred Tax Expense (or Benefit)
-URI http://asc.fasb.org/extlink&oid=6510177

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(h))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 8, 16, 17, 289
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 45
-Subparagraph g, h
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 6
-Section I
-Subsection 7

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number, Beginning Balance

Income Taxes (Schedule of Income Tax Rate Reconciliation) (Details)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Effective Income Tax Rate, Continuing Operations, Tax Rate Reconciliation [Abstract]
Statutory rate	35.00%	35.00%	35.00%
Foreign provision	11.20%	(291.00%)	418.20%
Effect of Australia reorganization		(2984.30%)
Nondeductible goodwill impairment (Note 2)			301.00%
Valuation allowance on certain deferred tax assets			427.80%
Other	0.80%	(265.00%)	(34.30%)
Effective tax rate	47.00%	(3505.30%)	1147.70%

Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Income Taxes [Abstract]
Depreciation and depletion	$ 336,471	$ 396,355
Original Issue Discount on 2025 and 2032 Notes	13,098	37,067
Equity investments in production facilities	81,082	76,911
Prepaid and other	10,548	14,779
Total deferred tax liabilities	441,199	525,112
Net operating loss carryforward	(36,981)	(34,987)
Asset retirement obligations	(70,085)	(88,279)
Reserves, accrued liabilities and other	(35,229)	(39,995)
Deferred Tax Assets, Gross	(142,295)	(163,261)
Valuation allowance	16,391	14,310
Current deferred tax assets	(43,942)	(41,449)
Deferred tax liabilities	359,237	417,610
Net deferred tax liabilities	$ 315,295	$ 376,161

Income Taxes (Reconciliation Of Beginning And Ending Amount Of Unrecognized Tax Benefits) (Details) - Helix [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Balance at January 1,	$ 7,085	$ 4,085	$ 3,417
Additions based on tax positions related to current year		2,785
Additions for tax positions of prior years	206	215	668
Reductions for tax positions of prior years	(2,785)
Balance at December 31,	$ 4,506	$ 7,085	$ 4,085

Employee Benefit Plans (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Jan. 04, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Based Compensation Arrangement By Share Based Payment Award Maximum Employer Subscription Rate		50.00%
Percentage Of Share Of Non Vested Stock Considered As Call Option		85.00%
Percentage of share of non-vested stock considered as put-option		15.00%
Stock Authorized Shares Employee Stock Purchase Plans		1,500,000
Performance Share Units Granted	89,329
Forfeitures On Restricted Stock Percentage		12.00%
Shares available for grant		6,600,000
Compensation cost related to restricted shares		$ 7.7	$ 8.4	$ 9.0
Share-based Compensation Arrangement by Share-based Payment Award, Number of Additional Shares Authorized		4,300,000
Allocated Share-based Compensation Expense		$ 0.3
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized		13.2	12.0	16.8
401k plan cost		$ 1.6	1.4	1.6
Maximum percetage of total shares of common stock issued and outstanding eligible to be granted to executives, selected management employees, and non employee members of board of directors		10.00%
Maximum excercise life		10 years
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Total Intrinsic Value		$ 1.3	1.1	0.1
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value		$ 0.4	$ 1.0	$ 0.6
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term		1 year 4 months 24 days
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Terms		2 years 2 months 12 days
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	89,329	482,340	571,163	599,996
Share-based Compensation Arrangement by Share-based Payment Award, Per Share Weighted Average Price of Shares Purchased	$ 20.64
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Share-based Awards Other than Options	$ 1.8
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Employee Subscription Rate		5.00%
Deferred Compensation Arrangement with Individual, Distributions Paid		$ 5.5	$ 5.9	$ 4.4	$ 7.1
Deferred Compensation Arrangement with Individual, Cash Awards Granted, Amount	$ 5.9	4.2	5.2	10.2
Deferred Compensation Arrangement with Individual, Compensation Expense		8.7	7.9	8.6
Deferred Compensation Cash-based Arrangements, Liability, Current		13.0	9.9
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value		$ 6.7	$ 6.7	5.6
2005 Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted share grants, vesting percentage		33.00%	20.00%
Vesting percentage		33.00%	20.00%
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted share grants, vesting percentage		100.00%
Vesting percentage		100.00%
Long-Term Incentive Cash Plan 2009 Grants [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Minimum percentage of average price during measurement period		75.00%
Long-Term Incentive Cash Plan 2010 Grants [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Minimum percentage of average price during measurement period		50.00%
Non Executive [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period		139,243
Deferred Compensation Arrangement with Individual, Cash Awards Granted, Amount				4.3
Executive Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period		132,910
Deferred Compensation Arrangement with Individual, Compensation Expense		$ 7.3	$ 6.5	$ 6.9
Deferred Compensation Cash-based Arrangements, Liability, Current		$ 11.7	$ 8.5
Maximum Shares As Incentive Options Member
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for grant		2,000,000
Grant Share Amount B [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Share Unit Market Value		$ 23.68
Performance Share Units Granted		132,910
Restricted share grants, vesting percentage		100.00%
Vesting percentage		100.00%
Maximum [Member] \| Grant Share Amount B [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum award percentage		200.00%

Employee Benefit Plans (Schedule Of Stock Options Activity) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Employee Benefit Plans [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number, Beginning Balance	192,800	432,918	501,318
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period	(140,000)	(181,670)	(68,400)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period		(58,448)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number, Ending Balance	52,800	192,800	432,918
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Number	52,800	192,800	432,918
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price, Beginning Balance	$ 10.52	$ 10.78	$ 10.74
Share-based Compensation Arrangements by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price	9.24	10.92	10.52
Share-based Compensation Arrangements by Share-based Payment Award, Options, Forfeitures in Period, Weighted Average Exercise Price		11.20
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price, Ending Balance	13.91	10.52	10.78
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price	$ 13.91	$ 10.52	$ 10.78

Employee Benefit Plans (Schedule Of Restricted Stock And Restricted Stock Units Activity) (Details) - $ / shares

1 Months Ended

12 Months Ended

Jan. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Employee Benefit Plans [Abstract]

1,324,312

1,263,218

1,463,298

1,443,265

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period

89,329

482,340

571,163

599,996

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period

^[1]

(400,180)

(504,813)

(444,905)

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period

(21,066)

(266,430)

(135,058)

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number, Ending Balance

1,324,312

1,263,218

1,463,298

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Beginning Balance

^[2]

$ 15.09

$ 14.80

$ 16.93

$ 21.55

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value

^[2]

18.33

12.77

12.01

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value

^[1],[2]

18.07

19.87

25.10

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value

^[2]

15.00

12.55

17.48

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Ending Balance

^[2]

$ 15.09

$ 14.80

$ 16.93

[1]	Total fair value of share-based awards that vested during the years ended December 31, 2012, 2011 and 2010 was $6.7 million, $6.7 million and $5.6 million, respectively.
[2]	Represents the weighted average grant date fair value, which is based on the quoted market price of the common stock on the business day prior to the date of grant.

The weighted average fair value of nonvested awards on equity-based plans excluding option plans (for example, phantom stock or unit plan, stock or unit appreciation rights plan, revenue or profit achievement stock award plan) for which the employer is contingently obligated to issue equity instruments or transfer assets to an employee who has not yet satisfied service or performance criteria necessary to gain title to proceeds from the sale of the award or underlying shares or units.

Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]

Employee Benefit Plans (Restricted Shares Granted) (Details) - $ / shares

1 Months Ended

12 Months Ended

Jan. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

89,329

482,340

571,163

599,996

Performance Share Units Granted

$ 20.64

89,329

Executive Officer [Member]

Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]

Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]

132,910

Non Executive [Member]

Grant Share Amount A [Member]

139,243

Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]

^[1]

Jan. 03, 2012

272,153

$ 15.80

Restricted share grants Vesting Period, in years

33.00%

3 years

Grant Share Amount B [Member]

Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]

^[2]

Jan. 03, 2012

100.00%

Performance Share Units Granted

January 1, 2015

132,910

Performance Share Unit Market Value

$ 23.68

Grant Share Amount C [Member]

Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]

^[3]

Jan. 03, 2012

1,958

$ 15.80

100.00%

Grant Share Amount D [Member]

January 1, 2014

Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]

^[3]

Apr. 01, 2012

1,879

$ 17.80

100.00%

Grant Share Amount E [Member]

January 1, 2014

Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]

^[3]

Jul. 02, 2012

1,885

$ 16.41

100.00%

Grant Share Amount F [Member]

January 1, 2014

Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]

^[3]

Aug. 23, 2012

3,539

$ 18.84

Restricted share grants Vesting Period, in years

20.00%

5 years

Grant Share Amount G [Member]

Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]

^[3]

Oct. 01, 2012

1,830

$ 18.27

100.00%

Grant Share Amount H [Member]

January 1, 2014

Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]

^[3]

Dec. 06, 2012

66,186

$ 18.13

Restricted share grants Vesting Period, in years

33.00%

3 years

[1]	Reflects the grant of 132,910 restricted shares to our executive officers and 139,243 RSUs to selected management employees that are convertible into 139,243 shares of our common stock upon vesting. These RSUs may be settled in cash or common stock at the Company’s option.
[2]	Reflects the grant of PSUs to 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.
[3]	Reflects grants to our directors.

Shareholders' Equity (Narrative) (Details) - $ / shares	Dec. 31, 2012	Dec. 31, 2011
Stockholders' Equity Note [Abstract]
Common stock, authorized (in shares)	240,000,000	240,000,000
Preferred Stock, Shares Authorized	5,000,000
Preferred Stock, Par or Stated Value Per Share	$ 0.01

Shareholders' Equity (Components Of Accumulated Other Comprehensive Loss) (Details) - USD ($)
$ in Thousands

Dec. 31, 2012

Dec. 31, 2011

Stockholders' Equity Note [Abstract]

Cumulative foreign currency translation adjustment

$ (15,667)

$ (22,958)

Unrealized gain (loss) on hedges, net

^[1]

12,941

Accumulated other comprehensive loss

$ (15,667)

(10,017)

Deferred Tax Assets, Other Comprehensive Loss

$ 7,000

[1]	Amount at December 31, 2011 is net of deferred income tax liabilities totaling $7.0 million. In December 2012, all of our oil and natural gas commodity derivative contracts no longer qualified for hedge accounting following the announcement of the sale of ERT (Note 2).

Accumulated change, net of tax, in accumulated gains and losses from derivative instruments designated and qualifying as the effective portion of cash flow hedges. Includes an entity's share of an equity investee's Increase or Decrease in deferred hedging gains or losses.

Accumulated adjustment, net of tax, that results from the process of translating subsidiary financial statements and foreign equity investments into the reporting currency from the functional currency of the reporting entity, net of reclassification of realized foreign currency translation gains or losses.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 14
-URI http://asc.fasb.org/extlink&oid=20435746&loc=d3e681-108580

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 52
-Paragraph 12, 13
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 45
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 52
-Paragraph 31
-Subparagraph a
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 12
-Paragraph 10
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 130
-Paragraph 17, 18, 19, 22, 23, 24, 25, 26
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Accumulated change in equity from transactions and other events and circumstances from non-owner sources, net of tax effect, at period end. Excludes Net Income (Loss), and accumulated changes in equity from transactions resulting from investments by owners and distributions to owners. Includes foreign currency translation items, certain pension adjustments, unrealized gains and losses on certain investments in debt and equity securities, other than temporary impairment (OTTI) losses related to factors other than credit losses on available-for-sale and held-to-maturity debt securities that an entity does not intend to sell and it is not more likely than not that the entity will be required to sell before recovery of the amortized cost basis, as well as changes in the fair value of derivatives related to the effective portion of a designated cash flow hedge.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=20435746&loc=SL7669686-108580

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 31
-Article 5

Reference 5: http://www.xbrl.org/2003/role/presentationRef
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-Name FASB Staff Position (FSP)
-Number FAS115-1/124-1
-Paragraph 15D
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 12
-Paragraph 10
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 130
-Paragraph 14, 17, 26
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 04
-Article 3

Amount before allocation of valuation allowances of deferred tax asset attributable to deductible temporary differences from unrealized losses in other comprehensive income.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 20
-Section 45
-Paragraph 11
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=18498875&loc=d3e39076-109324

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32632-109319

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 25
-Paragraph 20
-URI http://asc.fasb.org/extlink&oid=6969291&loc=d3e28680-109314

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32621-109319

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 36
-Subparagraph b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 11
-Subparagraph b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 43
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Stock Buyback Program (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended
	Jun. 30, 2012	Dec. 31, 2012	Jun. 30, 2009
Stock Buyback Program [Abstract]
Stock Repurchase Program, Number of Shares Authorized to be Repurchased			1,500,000
Total stock repurchase, shares		2,878,793
Stock Repurchased and Retired During Period, Shares	405,063
Stock Repurchased and Retired During Period, Value	$ 6.4
Total stock repurchase, value		$ 36.9
Repurchase of common stock, value per share		$ 12.83
Average stock repurchase, value per share	$ 15.82

Related Party Transactions (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Apr. 30, 2000	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Percentage of working interests acquired	20.00%
Financing exploratory costs		$ 8,247	$ 5,840	$ 3,252	$ 3,059
Royalty interest	25.00%
Partnership interests		81.00%
OKCD [Member]
Financing exploratory costs	$ 20,000
Related party payment		$ 6,900	8,300	11,200
Weatherford [Member]
Related party payment			$ 3,600	$ 6,900

Commitments And Contingencies (Narrative) (Details) - USD ($)

1 Months Ended

3 Months Ended

9 Months Ended

12 Months Ended

Aug. 31, 2012

Mar. 31, 2011

Sep. 30, 2010

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Self-insured retention for employees

$ 2,051,796,000

$ 1,815,012,000

250,000

Insurance liability limits

500,000,000

Trade receivables collected

303,000,000

Value added tax assessment

28,000,000

Operating Leases, Rent Expense, Net

85,000,000

62,200,000

$ 66,200,000

Loss Contingency, Loss in Period

$ 200,000

$ 12,000,000

30,000,000

Purchaser [Member]

Guarantor Obligations, Maximum Exposure, Undiscounted

100,000,000

Guarantor Obligations, Maximum Exposure, Undiscounted

50,000,000

Annual Aggregate [Member]

Q4000 Helix Producer I And Well Enhancer [Member]

5,000,000

Payments to Acquire Property, Plant, and Equipment

1,000,000

Helix 534 [Member]

$ 85,000,000

113,500,000

Q5000 [Member]

Long-term Purchase Commitment, Amount

386,500,000

Payments to Acquire Property, Plant, and Equipment

115,900,000

Seawell, Express And H534 [Member]

139,600,000

500,000

Caesar Vessel [Member]

General Liability [Member] | Per Occurance [Member]

750,000

Maritime Employers Liability [Member] | Per Occurance [Member]

100,000

Maritime Employers Liability [Member] | Annual Aggregate [Member]

100,000

Allowance for Doubtful Accounts [Member]

1,000,000

Remaining trade receivable write off

4,000,000

Allowance for Doubtful Accounts [Member] | Helix [Member]

4,000,000

Valuation Allowance of Deferred Tax Assets [Member] | Helix [Member]

1,257,000

^[1]

61,000

^[2]

4,108,000

^[3]

$ 2,081,000

^[1]

$ 5,813,000

^[2]

$ 8,497,000

^[3]

[1]	The increase in valuation allowance includes $2.0 million related to our WOSEA operations and $0.1 million to our oil and gas operations in the United Kingdom. WOSEA has a full valuation allowance against its deferred tax asset balance.
[2]	The increase in valuation allowance includes $4.9 million related to our WOSEA and $0.9 million to our oil and gas operations in the United Kingdom.
[3]	Amounts include a $4.0 million bad debt allowance related to a large international construction contract and a $7.3 million increase in valuation allowance related to our WOSEA operations with the remaining allowance being related to our acquisition of the remaining 50% of the Camelot field in the United Kingdom.

Commitments And Contingencies (Lease Commitments) (Details) $ in Thousands	Dec. 31, 2012 USD ($)
Total lease commitments	$ 399,483
2013	86,357
2014	91,019
2015	89,775
2016	63,308
2017	41,341
Thereafter	27,683
ROVs And Vessels [Member]
Total lease commitments	361,618
2013	84,409
2014	87,942
2015	86,155
2016	60,019
2017	38,188
Thereafter	4,905
Facilities And Other [Member]
Total lease commitments	37,865
2013	1,948
2014	3,077
2015	3,620
2016	3,289
2017	3,153
Thereafter	$ 22,778

Business Segment Information (Summary Of Financial Data By Segment) (Details) - USD ($)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2012

Sep. 30, 2012

^[1]

Jun. 30, 2012

^[1]

Mar. 31, 2012

^[1]

Dec. 31, 2011

Sep. 30, 2011

^[2]

Jun. 30, 2011

^[2]

Mar. 31, 2011

^[2]

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

$ 201,696

^[1]

$ 217,110

$ 197,461

$ 229,842

$ 200,113

^[2]

$ 213,278

$ 165,861

$ 122,748

$ 846,109

$ 702,000

$ 774,469

(68,483)

63,040

51,079

65,912

73,642

66,638

8,434

22,215

19,469

(125,961)

1,050

1,670

(59,158)

(36,806)

19,166

3,386,580

3,582,347

3,386,580

3,582,347

3,592,020

Capital expenditures

323,039

100,154

122,218

Contracting Services [Member]

97,201

91,188

81,878

899,793

738,235

780,339

(7,702)

107,013

77,391

702

765

1,299

(8,529)

97,798

72,459

(15,707)

29,235

42,828

1,982,822

2,023,251

1,982,822

2,023,251

1,872,141

Capital expenditures

322,216

69,259

65,949

Production Facilities [Member]

77,442

73,291

66,333

80,091

75,460

117,300

40,082

38,404

63,863

365

442

865

48,276

58,064

86,100

15,784

19,233

29,049

503,531

534,776

503,531

534,776

512,990

Capital expenditures

823

30,896

56,269

Intercompany Elimination [Member]

16,828

14,935

9,907

(133,775)

(111,695)

(123,170)

Corporate And Eliminations [Member]

(7,878)

(19,095)

64,845

72,435

64,474

(165,708)

(154,812)

(156,889)

(59,235)

(85,274)

(52,711)

Discontinued Operations [Member]

2,931

2,962

5,638

$ 900,227

$ 1,024,320

900,227

1,024,320

1,206,889

Corporate [Member]

$ (92,985)

$ (82,470)

$ (71,080)

[1]	Excludes revenues from discontinued operations of $178.1 million, $149.9 million, $119.1 million and $110.1 million for the quarters ended March 31, June 30, September 30 and December 31, 2012.
[2]	Excludes revenues from discontinued operations of $168.9 million, $172.5 million, $159.2 million and $196.1 million for the quarters ended March 31, June 30, September 30 and December 31, 2011.

Business Segment Information (Summary Of Intercompany Segment Revenues) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Segment Reporting Information [Line Items]
Intercompany segment revenues	$ 133,775	$ 111,695	$ 123,170
Contracting Services [Member]
Segment Reporting Information [Line Items]
Intercompany segment revenues	87,718	65,638	109,012
Production Facilities [Member]
Segment Reporting Information [Line Items]
Intercompany segment revenues	$ 46,057	$ 46,057	$ 14,158

Business Segment Information (Intercompany Segment Gross Profit (Loss)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Segment Reporting Information [Line Items]
Gross profit (loss) with other operating segments of same entity	$ 7,878	$ (93)	$ 19,112
Contracting Services [Member]
Segment Reporting Information [Line Items]
Gross profit (loss) with other operating segments of same entity	8,053	104	15,655
Production Facilities [Member]
Segment Reporting Information [Line Items]
Gross profit (loss) with other operating segments of same entity	$ (175)	$ (197)	$ 3,457

Business Segment Information (Revenue By Geographical Region) (Details) - USD ($)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2012

^[1]

Sep. 30, 2012

^[1]

Jun. 30, 2012

^[1]

Mar. 31, 2012

^[1]

Dec. 31, 2011

^[2]

Sep. 30, 2011

^[2]

Jun. 30, 2011

^[2]

Mar. 31, 2011

^[2]

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

$ 201,696

$ 217,110

$ 197,461

$ 229,842

$ 200,113

$ 213,278

$ 165,861

$ 122,748

$ 846,109

$ 702,000

$ 774,469

United States [Member]

281,308

316,869

402,228

United Kingdom [Member]

345,074

275,499

198,011

Other [Member]

Valuation and Qualifying Accounts Disclosure [Line Items]

$ 219,727

$ 109,632

$ 174,230

[1]	Excludes revenues from discontinued operations of $178.1 million, $149.9 million, $119.1 million and $110.1 million for the quarters ended March 31, June 30, September 30 and December 31, 2012.
[2]	Excludes revenues from discontinued operations of $168.9 million, $172.5 million, $159.2 million and $196.1 million for the quarters ended March 31, June 30, September 30 and December 31, 2011.

Business Segment Information (Property Plant And Equipment Net Of Depreciation By Geographic Region) (Details) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Segment Reporting Information [Line Items]
Property and equipment, net	$ 1,485,875	$ 1,459,669	$ 1,452,842
United States [Member]
Segment Reporting Information [Line Items]
Property and equipment, net	1,180,586	1,163,320	1,162,217
United Kingdom [Member]
Segment Reporting Information [Line Items]
Property and equipment, net	304,062	281,430	275,012
Other [Member]
Segment Reporting Information [Line Items]
Property and equipment, net	$ 1,227	$ 14,919	$ 15,613

Allowance Accounts (Schedule Of Allowance Accounts) (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Accounts receivable - Trade, net of allowance for uncollectible accounts of $4,445 and $4,527, respectively

$ 5,152

$ 4,000

Allowance for Doubtful Accounts [Member]

Valuation and Qualifying Accounts Disclosure [Line Items]

Remaining trade receivable write off

$ 4,000

4,000

Allowance for Doubtful Accounts [Member] | Helix [Member]

Valuation and Qualifying Accounts Disclosure [Line Items]

Valuation Allowances and Reserves, Balance, Beginning Balance

4,000

4,460

5,105

Valuation Allowances and Reserves, Recoveries

1,257

^[1]

^[2]

4,108

^[3]

(105)

(521)

(4,753)

^[4]

Valuation Allowances and Reserves, Balance, Ending Balance

5,152

4,000

4,460

Valuation Allowance of Deferred Tax Assets [Member] | Helix [Member]

Valuation and Qualifying Accounts Disclosure [Line Items]

Valuation Allowances and Reserves, Balance, Beginning Balance

14,310

8,497

Valuation Allowances and Reserves, Balance, Ending Balance

2,081

^[1]

5,813

^[2]

8,497

^[3]

16,391

14,310

8,497

WOSEA [Member] | Allowance for Doubtful Accounts [Member]

Valuation and Qualifying Accounts Disclosure [Line Items]

Remaining trade receivable write off

3,700

WOSEA [Member] | Valuation Allowance of Deferred Tax Assets [Member]

Valuation and Qualifying Accounts Disclosure [Line Items]

Oil And Gas Operations In United Kingdom [Member] | Valuation Allowance of Deferred Tax Assets [Member]

2,000

4,900

$ 7,300

Valuation and Qualifying Accounts Disclosure [Line Items]

Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]

$ 100

$ 900

[1]	The increase in valuation allowance includes $2.0 million related to our WOSEA operations and $0.1 million to our oil and gas operations in the United Kingdom. WOSEA has a full valuation allowance against its deferred tax asset balance.
[2]	The increase in valuation allowance includes $4.9 million related to our WOSEA and $0.9 million to our oil and gas operations in the United Kingdom.
[3]	Amounts include a $4.0 million bad debt allowance related to a large international construction contract and a $7.3 million increase in valuation allowance related to our WOSEA operations with the remaining allowance being related to our acquisition of the remaining 50% of the Camelot field in the United Kingdom.
[4]	Includes the $3.7 million of bad debt expense related to settlement of third party claims related to a terminated international construction contract in Australia (Note 13).

Supplemental Oil And Gas Disclosures (Capitalized Costs) (Details) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Asset retirement obligation	$ 200,978	$ 227,090	$ 222,653
Oil and Gas Properties [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Asset retirement obligation	203,900	254,400
Helix [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and gas properties	51,513	50,389
Proved oil and gas properties	2,453,667	2,516,363
Total oil and gas properties	2,505,180	2,566,752
Accumulated depletion, depreciation and amortization	(1,717,314)	(1,695,105)
Net capitalized costs	$ 787,866	$ 871,647

Supplemental Oil And Gas Disclosures (Costs Incurred In Oil And Gas Producing Activities) (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Unproved properties

$ 41

$ 364

Total property acquisition costs

364

Exploration costs

$ 135,311

2,513

1,362

Development costs

^[1]

17,344

126,196

53,002

Asset retirement cost

^[2]

59,715

46,446

25,356

Total costs incurred

212,370

175,196

80,084

Camelot Field [Member]

Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]

Asset retirement cost

$ 15,500

$ 20,000

$ 900

[1]	Development costs include costs incurred to obtain access to proved reserves to drill and equip development wells.
[2]	Asset retirement costs include $15.5 million, $20.0 million, $0.9 million, respectively, associated with the Camelot field in the United Kingdom during the years ended December 31, 2012, 2011 and 2010.

Costs incurred, including capitalized costs and costs charged to expense, associated with the acquisition of oil and gas properties that have unproved reserves.

Supplemental Oil And Gas Disclosures (Estimated Quantities Of Proved Oil And Gas Reserves) (Details) bbl in Thousands, MMcf in Millions	12 Months Ended
	Dec. 31, 2012 item MMcf bbl	Dec. 31, 2011 MMcf bbl	Dec. 31, 2010 MMcf bbl	Dec. 31, 2009 MMcf bbl
Reserve Quantities [Line Items]
Total proved reserves, beginning balance	38,860	62,696	96,280
Revision of previous estimates	(1,508)	(14,683)	(25,714)
Production	(6,619)	(8,694)	(7,870)
Sales of reserves in place	(654)	(890)
Extensions and discoveries	2,105	431
Total proved reserves, ending balance	32,184	38,860	62,696
Total proved developed reserves	19,677	22,731	24,407	35,644
Percentage of dosmetic significant oil and gas fields analyzed	100.00%
Number of dosmetic significant oil and gas fields analyzed \| item	40
Percentage benchmark discounted future net revenues	1.00%
Oil [Member]
Reserve Quantities [Line Items]
Total proved reserves, beginning balance	22,689	24,818	29,727
Revision of previous estimates	647	3,475	(1,555)
Production	(4,725)	(5,785)	(3,354)
Sales of reserves in place	(75)	(205)
Extensions and discoveries	1,434	386
Total proved reserves, ending balance	19,970	22,689	24,818
Total proved developed reserves	12,431	12,754	11,796	14,850
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Total proved reserves, beginning balance \| MMcf	97,021	227,264	399,315
Revision of previous estimates \| MMcf	(12,926)	(108,947)	(144,954)
Production \| MMcf	(11,361)	(17,458)	(27,097)
Sales of reserves in place \| MMcf	(3,473)	(4,109)
Extensions and discoveries \| MMcf	4,026	271
Total proved reserves, ending balance \| MMcf	73,287	97,021	227,264
Total proved developed reserves \| MMcf	43,475	59,859	75,664	124,763
Camelot Field [Member]
Reserve Quantities [Line Items]
Total proved reserves, beginning balance \| MMcf			12,000
Bushwood Field [Member] \| Oil [Member]
Reserve Quantities [Line Items]
Revision of previous estimates			1,800
Bushwood Field [Member] \| Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Revision of previous estimates \| MMcf		87,000	131,000

Supplemental Oil And Gas Disclosures (Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	$ 2,341,354	$ 2,811,956	$ 2,925,744
Production	509,408	419,617	583,050
Development and abandonment	509,971	584,623	603,070
Total future costs	1,019,379	1,004,240	1,186,120
Future net cash flows before income taxes	1,321,975	1,807,716	1,739,624
Future income tax expense	330,630	477,630	430,153
Future net cash flows	991,345	1,330,086	1,309,471
Discount at 10% annual rate	153,032	266,954	318,404
Standardized measure of discounted future net cash flows	838,313	1,063,132	991,067
United States [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	2,341,354	2,811,956	2,925,744
Production	509,408	419,617	583,050
Development and abandonment	507,074	557,323	590,870
Total future costs	1,016,482	976,940	1,173,920
Future net cash flows before income taxes	1,324,872	1,835,016	1,751,824
Future income tax expense	330,630	477,630	430,153
Future net cash flows	994,242	1,357,386	1,321,671
Discount at 10% annual rate	153,032	266,954	318,404
Standardized measure of discounted future net cash flows	841,210	1,090,432	1,003,267
United Kingdom [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Development and abandonment	2,897	27,300	12,200
Total future costs	2,897	27,300	12,200
Future net cash flows before income taxes	(2,897)	(27,300)	(12,200)
Future net cash flows	(2,897)	(27,300)	(12,200)
Standardized measure of discounted future net cash flows	$ (2,897)	$ (27,300)	$ (12,200)

Supplemental Oil And Gas Disclosures (Schedule Of Base Prices Used In Determining The Standardized Measure) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Supplemental Oil and Gas Disclosures [Abstract]
Base prices, Barrel	104.85	105.35	77.55
Base prices, Mcf	3.38	4.34	4.40

Supplemental Oil And Gas Disclosures (Changes In Standardized Measure Of Discounted Future Net Cash Flows) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Supplemental Oil and Gas Disclosures [Abstract]
Standardized measure, beginning of year	$ 1,063,132	$ 991,067	$ 991,060
Sales, net of production costs	(379,910)	(516,895)	(294,212)
Net change in prices and production costs	(242,037)	414,426	577,687
Changes in future development costs	(65,854)	(108,007)	84,907
Development costs incurred	149,702	168,005	55,646
Accretion of Discount	147,157	131,464	129,083
Net change in income taxes	101,720	(54,613)	(41,115)
Extensions and discoveries	110,655	29,479
Sales of reserves in place	(6,096)	(14,324)
Net change due to revision in quantity estimates	28,627	(186,197)	(422,987)
Changes in production rates (timing) and other	(68,783)	208,727	(89,002)
Total	(224,819)	72,065	7
Standardized measure, end of year	$ 838,313	$ 1,063,132	$ 991,067

Derivative Instruments And Hedging Activities (Narrative) (Details) $ in Millions	1 Months Ended
	Feb. 20, 2013 USD ($)
Oil And Natural Gas Commodity Contracts [Member]
Derivative Cash Settlement	$ 22.5
Interest Rate Swaps [Member]
Derivative Cash Settlement	$ 0.6

Derivative Instruments And Hedging Activities (Derivatives Designated As Hedging Instruments) (Details) $ in Thousands	Dec. 31, 2011 USD ($)
Derivatives, Fair Value [Line Items]
Asset derivatives designated as hedging instruments	$ 22,708
Liability derivatives designated as hedging instruments	2,800
Other Current Assets [Member] \| Oil Contract [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives designated as hedging instruments	8,567
Other Current Assets [Member] \| Natural Gas Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives designated as hedging instruments	12,957
Other Assets, Net [Member] \| Natural Gas Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives designated as hedging instruments	857
Other Assets, Net [Member] \| Interest Rate Swaps [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives designated as hedging instruments	327
Other Liabilities [Member] \| Oil Contract [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives designated as hedging instruments	1,712
Accrued Liabilities [Member] \| Oil Contract [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives designated as hedging instruments	886
Accrued Liabilities [Member] \| Interest Rate Swaps [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives designated as hedging instruments	$ 202

Derivative Instruments And Hedging Activities (Derivatives Not Designated As Hedging Instruments) (Details) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Asset derivatives not designated as hedging instruments	$ 5,946	$ 55
Liability derivatives not designated as hedging instruments	16,298	159
Accrued Liabilities [Member] \| Foreign Exchange Forward [Member]
Liability derivatives not designated as hedging instruments		159
Accrued Liabilities [Member] \| Oil Contract [Member]
Liability derivatives not designated as hedging instruments	15,777
Accrued Liabilities [Member] \| Interest Rate Swaps [Member]
Liability derivatives not designated as hedging instruments	489
Other Liabilities [Member] \| Interest Rate Swaps [Member]
Liability derivatives not designated as hedging instruments	32
Other Current Assets [Member] \| Foreign Exchange Forward [Member]
Asset derivatives not designated as hedging instruments	146	$ 55
Other Current Assets [Member] \| Oil Contract [Member]
Asset derivatives not designated as hedging instruments	$ 5,800

Derivative Instruments And Hedging Activities (Impact Of Derivative Instruments On Accumulated Comprehensive Income (Loss)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	$ (12,941)	$ 30,043	$ (7,699)
Oil And Natural Gas Commodity Contracts [Member]
Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	(12,860)	28,749	(6,486)
Interest Rate Swaps [Member]
Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	$ (81)	$ 1,294	$ (1,213)

Derivative Instruments And Hedging Activities (Gain (Loss) Reclassified From Accumulated OCI Into Income) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	$ 2,661	$ (23,669)	$ 23,726
Oil And Natural Gas Commodity Contracts [Member] \| Income From Discontinued Operations Net Of Tax [Member]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	3,184	(21,659)	25,575
Interest Rate Swaps [Member] \| Net Interest Expense [Member]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	$ (523)	$ (2,010)	$ (1,849)

Derivative Instruments And Hedging Activities (Impact Of Non Designated Derivative Instruments On Income Statement) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Gain (Loss) Recognized in Income on Derivatives	$ (5,113)	$ 249	$ (1,472)
Foreign Exchange Contracts [Member] \| Other Expense [Member]
Gain (Loss) Recognized in Income on Derivatives	411	$ 249	(2,560)
Oil And Natural Gas Commodity Contracts [Member] \| Non Hedge Loss On Commodity Derivative Contracts [Member]
Gain (Loss) Recognized in Income on Derivatives	(10,507)
Oil And Natural Gas Commodity Contracts [Member] \| Income From Discontinued Operations Net Of Tax [Member]
Gain (Loss) Recognized in Income on Derivatives	5,550		$ 1,088
Interest Rate Swaps [Member] \| Other Expense [Member]
Gain (Loss) Recognized in Income on Derivatives	$ (567)

The amount of net gains and losses recognized in income during the period on derivative instruments designated and qualifying as hedging instruments in fair value hedges and related hedged items designated and qualifying in fair value hedges, on derivative instruments designated and qualifying as hedging instruments in cash flow hedges, and on derivative instruments not designated as hedging instruments.

Quarterly Financial Information (Summary Of Consolidated Quarterly Financial Information) (Details) - USD ($)
$ / shares in Units, $ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Impairment of Long-Lived Assets Held-for-use

$ 201,696

^[1]

$ 217,110

^[1]

$ 197,461

^[1]

$ 229,842

^[1]

$ 200,113

^[2]

$ 213,278

^[2]

$ 165,861

^[2]

$ 122,748

^[2]

$ 846,109

$ 702,000

$ 774,469

Gross profit (loss)

(108,925)

^[3]

57,919

^[3]

28,438

^[3]

72,483

^[3]

26,273

^[4]

64,972

^[4]

44,043

^[4]

14,395

^[4]

49,915

149,683

164,817

Net income

(171,560)

14,875

44,651

65,737

16,763

^[5]

46,026

^[5]

41,323

^[5]

25,867

^[5]

(46,297)

129,979

(126,988)

158,000

4,600

14,600

Net income (loss) applicable to common shareholders:

10,563

2,240

Income (loss) from continuing operations

(99,679)

10,362

2,425

16,874

17,487

15,999

10,547

(9,315)

(70,018)

34,291

(20,445)

Income (loss) from discontinued operations

(71,888)

^[6]

4,503

^[6]

42,216

^[6]

48,853

^[6]

(734)

30,017

30,766

35,172

23,684

95,221

(106,657)

Net income applicable to common shareholders

$ (171,567)

$ 14,865

$ 44,641

$ 65,727

$ 16,753

$ 46,016

$ 41,313

$ 25,857

$ (46,334)

$ 129,939

$ (127,102)

Basic earnings (loss) per common share:

Continuing operations

$ (0.95)

$ 0.10

$ 0.02

$ 0.16

$ 0.17

$ 0.15

$ 0.10

$ (0.09)

$ (0.67)

$ 0.33

$ (0.19)

Discontinued operations

(0.69)

0.04

0.40

0.46

(0.01)

0.28

0.29

0.33

0.23

0.90

(1.03)

Basic earnings per common share

(1.64)

0.14

0.42

0.62

0.16

0.43

0.39

0.24

(0.44)

1.23

(1.22)

Diluted earnings (loss) per common share:

Continuing operations

(0.95)

0.10

0.02

0.16

0.17

0.15

0.10

(0.09)

(0.67)

0.33

(0.19)

Discontinued operations

(0.69)

0.04

0.40

0.46

(0.01)

0.29

0.33

0.23

0.90

(1.03)

Diluted earnings per common share

$ (1.64)

$ 0.14

$ 0.42

$ 0.62

$ 0.16

$ 0.44

$ 0.39

$ 0.24

$ (0.44)

$ 1.23

$ (1.22)

Segment, Discontinued Operations [Member]

Australian Well Invention Equipment [Member]

$ 110,100

$ 119,100

$ 149,900

$ 178,100

$ 196,100

$ 159,200

$ 172,500

$ 168,900

Gross profit (loss)

$ (102,600)

$ 27,800

$ 64,800

$ 89,200

4,800

$ 57,300

$ 56,200

$ 62,700

Impairment of Long-Lived Assets Held-for-use

6,600

Tax benefit related to reorganization

31,300

United Kingdom [Member]

$ 345,074

$ 275,499

$ 198,011

Sapura [Member]

$ 10,600

[1]	Excludes revenues from discontinued operations of $178.1 million, $149.9 million, $119.1 million and $110.1 million for the quarters ended March 31, June 30, September 30 and December 31, 2012.
[2]	Excludes revenues from discontinued operations of $168.9 million, $172.5 million, $159.2 million and $196.1 million for the quarters ended March 31, June 30, September 30 and December 31, 2011.
[3]	Excludes gross profit (loss) from discontinued operations of $89.2 million, $64.8 million, $27.8 million and $(102.6) million for the quarters ended March 31, June 30, September 30 and December 31, 2012. Includes impairment charges totaling $14.6 million in the second quarter of 2012, $4.6 million in the third quarter of 2012 and $158.0 million in the fourth quarter of 2012 (Note 2).
[4]	Excludes gross profit from discontinued operations of $62.7 million, $56.2 million, $57.3 million and $4.8 million for the quarters ended March 31, June 30, September 30 and December 31, 2011. The fourth quarter includes a $6.6 million impairment charge to reduce our Australian well intervention equipment to its estimated fair value at December 31, 2011.
[5]	Our net income in the fourth quarter of 2011 includes a $10.6 million other than temporary impairment loss on our equity investment in our Australian joint venture (Note 5). The fourth quarter also includes a $31.3 million tax benefit related to reorganization of our Australian well intervention operations.
[6]	Our net loss in the fourth quarter of 2012 includes a $138.6 million impairment charge associated with the sale of ERT (Note 3).

Condensed Consolidated Guarantor And Non-Guarantor Financial Information (Schedule Of Condensed Consolidating Balance Sheets) (Details) - USD ($)
$ in Thousands

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

$ 437,100

$ 546,463

$ 391,084

152,233

147,899

33,840

37,375

^[1]

14,201

82,733

93,584

84,000

118,921

804,107

944,242

Equity investments in unconsolidated affiliates

1,485,875

1,459,669

1,452,842

167,599

175,656

62,935

62,215

62,494

^[2]

49,837

35,166

816,227

905,399

3,386,580

3,582,347

3,592,020

92,398

73,919

161,514

146,112

1,293

16,607

7,877

182,527

166,975

453,046

396,176

1,002,621

1,147,444

359,237

417,610

5,025

9,368

147,237

161,208

1,967,166

2,131,806

1,000

1,419,414

1,449,541

1,285,644

$ 1,427,462

3,386,580

3,582,347

381,599

495,484

376,434

39,203

79,290

13,959

10,530

24,611

80,388

54,588

68,627

513,960

734,319

(154,756)

(147,187)

Equity investments in affiliates

208,190

230,946

1,762,359

1,952,392

Due from subsidiaries/parent

47,355

53,425

294,461

64,655

2,671,569

2,888,550

45,784

39,280

117,902

115,921

11,487

3,000

175,173

158,201

902,453

1,042,155

168,688

231,255

1,453

4,150

1,247,767

1,435,761

1,000

1,423,802

1,451,789

2,671,569

2,888,550

Guarantors [Member]

4,436

2,432

3,293

37,378

26,885

875

155

16,418

20,624

84,000

118,921

143,107

169,017

352,210

315,821

Equity investments in affiliates

351,746

550,668

53,461

37,239

45,107

Due from subsidiaries/parent

130

2,712

485,096

430,496

816,227

905,399

2,247,084

2,456,459

17,229

9,626

26,019

3,841

26,618

97,692

182,527

166,975

252,393

278,134

86,925

88,625

3,086

4,647

147,237

161,208

489,641

532,614

1,757,443

1,923,845

2,247,084

2,456,459

Non-Guarantors [Member]

51,065

48,547

$ 11,357

75,652

41,724

19,006

26,690

306

11,696

10,159

157,725

127,120

(125,889)

(102,826)

Equity investments in unconsolidated affiliates

930,556

682,899

167,599

175,656

17,828

17,108

34,848

16,809

1,182,667

916,766

29,385

25,013

17,593

26,350

217

5,120

10,377

52,098

61,957

100,168

105,289

109,171

103,552

486

571

Due to parent

323,049

98,285

584,972

369,654

597,695

547,112

Consolidating Entries [Member]

1,182,667

916,766

(10,716)

(80,388)

(5,826)

(10,685)

(86,214)

(71,565)

(65,808)

Equity investments in affiliates

(4,617)

(4,844)

(1,815,820)

(1,989,631)

Due from subsidiaries/parent

(32,496)

(37,780)

(779,557)

(495,151)

(2,714,740)

(2,679,428)

(26,618)

(96,616)

(5,500)

(26,618)

(102,116)

(5,547)

(5,822)

Due to parent

(323,049)

(98,285)

(355,214)

(206,223)

(2,359,526)

(2,473,205)

$ (2,714,740)

$ (2,679,428)

[1]	Reflects the total amount of estimated tax receivable in excess of the estimated current income tax liability.
[2]	In 2010, we fully impaired $16.7 million of goodwill associated with our Australian well intervention subsidiary (“WOSEA”) (see below).

Condensed Consolidated Guarantor And Non-Guarantor Financial Information (Schedule Of Condensed Consolidating Statements Of Operations) (Details) - USD ($)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

$ 201,696

^[1]

$ 217,110

^[1]

$ 197,461

^[1]

$ 229,842

^[1]

$ 200,113

^[2]

$ 213,278

^[2]

$ 165,861

^[2]

$ 122,748

^[2]

$ 846,109

$ 702,000

$ 774,469

796,194

552,317

609,652

(108,925)

^[3]

57,919

^[3]

28,438

^[3]

72,483

^[3]

26,273

^[4]

64,972

^[4]

44,043

^[4]

14,395

^[4]

49,915

149,683

164,817

(16,743)

Non-hedge loss on commodity derivative contracts

(13,476)

(6)

9,118

(10,507)

(94,415)

(86,637)

(106,113)

(68,483)

63,040

51,079

8,434

22,215

19,469

(10,563)

(2,240)

(65,912)

(73,642)

(66,638)

(125,961)

1,050

1,670

Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest, Total

(59,158)

(36,806)

19,166

(66,803)

37,856

(17,496)

Income (loss) from discontinued operations, net of tax

(71,888)

^[5]

4,503

^[5]

42,216

^[5]

48,853

^[5]

(734)

30,017

30,766

35,172

23,684

95,221

(106,657)

Net income (loss), including noncontrolling interests

(43,119)

133,077

(124,153)

Less net income applicable to noncontrolling interests

(3,178)

(3,098)

(2,835)

Preferred stock dividends

(37)

(40)

(114)

Net income (loss) applicable to Helix common shareholders

$ (171,567)

$ 14,865

$ 44,641

$ 65,727

$ 16,753

$ 46,016

$ 41,313

$ 25,857

(46,334)

129,939

(127,102)

Total comprehensive income (loss) applicable to Helix common shareholders

(51,984)

158,980

(143,919)

90,552

84,748

183,147

111,531

72,902

124,722

(20,979)

11,846

58,425

(6)

3,159

(53,539)

(74,205)

(67,165)

(74,518)

(62,365)

(5,581)

(12,264)

262,990

(60,443)

(2,240)

(59,759)

(157,546)

(59,522)

(146,541)

43,079

(127,786)

Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest, Total

(96,328)

(63,242)

(9,175)

(50,213)

106,321

(118,611)

Income (loss) from discontinued operations, net of tax

(1,621)

Net income (loss), including noncontrolling interests

(51,834)

106,321

(118,611)

Preferred stock dividends

(37)

(40)

(114)

Net income (loss) applicable to Helix common shareholders

(51,871)

106,281

(118,725)

Total comprehensive income (loss) applicable to Helix common shareholders

(51,952)

107,575

(119,051)

Guarantors [Member]

404,628

362,648

376,134

444,956

281,267

287,709

(40,328)

81,381

88,425

Non-hedge loss on commodity derivative contracts

(13,475)

(10,507)

(22,782)

(25,963)

(18,268)

(87,092)

55,418

70,157

16,222

7,340

8,473

392

(6,787)

(1,991)

(70,478)

55,971

76,639

Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest, Total

24,186

18,181

23,465

(94,664)

37,790

53,174

Income (loss) from discontinued operations, net of tax

25,305

95,221

(106,657)

Net income (loss), including noncontrolling interests

(69,359)

133,011

(53,483)

Net income (loss) applicable to Helix common shareholders

(69,359)

133,011

(53,483)

Total comprehensive income (loss) applicable to Helix common shareholders

(82,219)

161,760

(59,969)

Non-Guarantors [Member]

464,331

367,114

334,726

351,283

309,429

302,051

113,048

57,685

32,675

(16,743)

(1)

5,959

(20,018)

12,101

(22,482)

93,029

69,786

(591)

8,434

22,215

19,469

(10,563)

(6,517)

67,181

(5,125)

94,946

148,619

13,753

Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest, Total

12,951

8,186

9,405

81,995

140,433

4,348

Net income (loss), including noncontrolling interests

81,995

140,433

4,348

Net income (loss) applicable to Helix common shareholders

81,995

140,433

4,348

Total comprehensive income (loss) applicable to Helix common shareholders

89,260

140,214

(5,653)

Consolidating Entries [Member]

(113,402)

(112,510)

(119,538)

(111,576)

(111,281)

(104,830)

(1,826)

(1,229)

(14,708)

1,924

1,430

1,802

201

(12,906)

(3,958)

(270,330)

51,970

(28)

23,510

(3,888)

(246,619)

39,064