View Filing Data

132,603

181,083

120,550

Exploration expense

^[1]

10,914

8,276

24,383

Total cost of sales

1,068,015

1,166,166

1,218,525

Gross profit

330,592

33,672

243,162

Gain on oil and gas derivative commodity contracts

(16,743)

^[2]

1,088

89,485

4,525

9,405

2,019

(99,589)

(122,078)

(130,851)

Equity in earnings of investments

^[3]

235,528

(94,656)

203,815

22,215

19,469

32,329

(10,563)

(2,240)

753

77,343

Net interest expense

(95,796)

(85,303)

(56,733)

Other income (expense)

(4,157)

(1,021)

5,238

147,980

(163,751)

261,992

14,903

(39,598)

95,822

Income from discontinued operations, net of tax

133,077

(124,153)

166,170

9,581

Net income (loss), including noncontrolling interests

133,077

(124,153)

175,751

Net income applicable to noncontrolling interests

(3,098)

(2,835)

(19,697)

Preferred stock dividends

129,979

(126,988)

156,054

(40)

(114)

(748)

Preferred stock beneficial conversion charges

(53,439)

Net income (loss) applicable to Helix common shareholders

$ 129,939

$ (127,102)

$ 101,867

Basic earnings (loss) per share of common stock:

Continuing operations

$ 1.23

$ (1.22)

$ 0.92

Discontinued operations

0.09

Net income (loss) per common share

1.23

(1.22)

1.01

Diluted earnings (loss) per share of common stock:

Continuing operations

1.22

(1.22)

0.87

Discontinued operations

0.09

Net income (loss) per common share

$ 1.22

$ (1.22)

$ 0.96

Weighted average common shares outstanding:

Basic

104,528

103,857

99,136

Diluted

104,953

103,857

105,720

[1]	See Note 5 for additional information related to the components of our exploration costs, including impairment charges for expiring unproved leases.
[2]	Amount reflects full write off of goodwill associated with our WOSEA operations.
[3]	Includes $16.7 million of goodwill impairment charge for year ending December 31, 2010 related to our contracting services segment. Also includes approximately $132.6 million, $181.1 million and $120.6 million of asset impairment charges for certain oil and gas properties for the years ended December 31, 2011, 2010 and 2009 respectively.

Consolidated Statements Of Shareholders' Equity - USD ($) shares in Thousands, $ in Thousands	Common Stock [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Total Controlling Interest Shareholders' Equity [Member]	Non-Controlling Interest [Member]	Total
Balance at Dec. 31, 2008	$ 806,905	$ 417,940	$ (33,696)	$ 1,191,149	$ 322,627	$ 1,513,776
Balance (in shares) at Dec. 31, 2008	91,972
Comprehensive income (loss)
Net income		156,054		156,054	19,697	175,751
Effect of deconsolidation of Cal Dive (Note 3)					(320,119)	(320,119)
Foreign currency translations adjustments			30,617	30,617		30,617
Unrealized loss (gain) on hedges, net			(18,275)	(18,275)		(18,275)
Unrealized loss (gain) on investment held for sale (Note 2)			(887)	(887)		(887)
Comprehensive income (loss)				167,509	(300,422)	(132,913)
Convertible preferred stock dividends and preferred stock beneficial charges		(54,187)		(54,187)		(54,187)
Convertible preferred stock conversion (Note 11)	$ 102,502			102,502		102,502
Convertible preferred stock conversion (Note 11) (in shares)	12,805
Other	$ (319)			(319)		(319)
Stock compensation expense	9,530			9,530		9,530
Stock repurchase	$ (13,995)			(13,995)		(13,995)
Stock repurchase (in shares)	(1,116)
Activity in company stock plans, net and other	$ 2,173			2,173		2,173
Activity in company stock plans, net and other (in shares)	620
Excess tax from stock- based compensation	$ 895			895		895
Balance at Dec. 31, 2009	$ 907,691	519,807	(22,241)	1,405,257	22,205	1,427,462
Balance (in shares) at Dec. 31, 2009	104,281
Comprehensive income (loss)
Net income		(126,988)		(126,988)	2,835	(124,153)
Foreign currency translations adjustments			(10,005)	(10,005)		(10,005)
Unrealized loss (gain) on hedges, net			(7,699)	(7,699)		(7,699)
Unrealized loss (gain) on investment held for sale (Note 2)			887	887		887
Comprehensive income (loss)				(143,805)	2,835	(140,970)
Convertible preferred stock dividends and preferred stock beneficial charges		(114)		(114)		(114)
Convertible preferred stock conversion (Note 11)	$ 5,000			5,000		5,000
Convertible preferred stock conversion (Note 11) (in shares)	1,807
Stock compensation expense	$ 9,217			9,217		9,217
Stock repurchase	$ (11,680)			(11,680)		(11,680)
Stock repurchase (in shares)	(1,016)
Activity in company stock plans, net and other	$ 674			674		674
Activity in company stock plans, net and other (in 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
Balance (in shares) at Dec. 31, 2010	105,592
Comprehensive income (loss)
Net income		129,979		129,979	3,098	133,077
Foreign currency translations adjustments			(1,002)	(1,002)		(1,002)
Unrealized loss (gain) on hedges, net			30,043	30,043		30,043
Comprehensive income (loss)				159,020	3,098	162,118
Convertible preferred stock dividends and preferred stock beneficial charges		(40)		(40)		(40)
Stock compensation expense	$ 8,418			8,418		8,418
Stock repurchase	$ (6,502)			(6,502)		(6,502)
Stock repurchase (in shares)	(497)
Activity in company stock plans, net and other	$ 916			916		916
Activity in company stock plans, net and other (in 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
Balance (in shares) at Dec. 31, 2011	105,530

Consolidated Statements Of Cash Flows - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Cash flows from operating activities:

Net income (loss), including noncontrolling interests

$ 133,077

$ (124,153)

$ 175,751

Adjustments to reconcile net income (loss), including noncontrolling interests to net cash provided by operating activities -

Goodwill and other indefinite-lived intangible impairments

311,103

317,116

262,617

Asset impairment charges

139,167

181,083

121,855

16,743

^[1]

Exploratory drilling and related expenditures

8,264

5,969

21,367

Equity in earnings of investments, net of distributions

(6,321)

Amortization of deferred financing costs

8,910

7,703

6,693

Income from discontinued operations

(9,581)

Stock compensation expense

8,365

8,996

11,992

Amortization of debt discount

8,973

8,409

7,880

Excess tax benefit from stock-based compensation

(4,188)

(46,836)

(64,926)

1,013

3,945

(895)

Unrealized loss (gain) on derivative contracts

382

1,568

(5,237)

Loss on early extinguishment of Senior Unsecured Notes

2,354

10,563

2,240

Changes in operating assets and liabilities:

(753)

(77,343)

Gain on sale of assets

(4,525)

(9,405)

(2,019)

(47,998)

(46,191)

52,245

Accounts payable and accrued liabilities

560

21,894

51,158

Income tax payable

6,472

214

48,831

28,230

48,411

(62,341)

Oil and gas asset retirement costs

(41,980)

(61,763)

(45,038)

Other noncurrent, net

(833)

(4,489)

(62,750)

Cash provided by operating activities

567,156

331,454

423,938

Cash used in discontinued operations

(6,261)

Net cash provided by operating activities

567,156

331,454

417,677

Cash flows from investing activities:

Investments in equity investments

(219,769)

(206,772)

(423,373)

(2,699)

(8,253)

(1,657)

Distributions from equity investments, net

3,965

10,539

6,742

Proceeds from insurance reimbursement

16,106

Proceeds from sale of Cal Dive common stock

3,588

418,168

Reduction in cash from deconsolidation of Cal Dive

(112,995)

Proceeds from sales of property

31,000

6,894

23,717

Decrease (increase) in restricted cash

1,598

(70)

(6)

Cash used in investing activities

(182,317)

(181,556)

(89,404)

Cash provided by discontinued operations

20,872

Net cash used in investing activities

(182,317)

(181,556)

(68,532)

Cash flows from financing activities:

Repayment of Helix term loan

(130,691)

(4,326)

Borrowings on Helix Revolver

109,400

Repayments on Helix Revolver

(109,400)

(349,500)

Early extinguishment of Senior Unsecured Notes

(77,394)

Repayment of MARAD borrowings

(4,645)

(4,424)

(4,214)

Borrowings on CDI Revolver

100,000

Repayments on CDI term loan

(20,000)

Loan notes repayment

(1,215)

(2,517)

(2,130)

Deferred financing costs

(9,311)

(2,947)

(6,970)

Preferred stock dividends paid

(40)

(114)

(645)

Repurchase of common stock

(7,604)

(11,680)

(13,995)

Excess tax benefit from stock-based compensation

(1,013)

(3,945)

895

Exercise of stock options, net

2,018

674

176

Net cash used in financing activities

(229,895)

(29,279)

(300,709)

Effect of exchange rate changes on cash and cash equivalents

436

(207)

(1,376)

Net increase in cash and cash equivalents

155,380

120,412

47,060

Cash and cash equivalents:

Balance, beginning of year

391,085

270,673

223,613

Balance, end of year

$ 546,465

$ 391,085

$ 270,673

[1]	Amount reflects full write off of goodwill associated with our WOSEA operations.

Organization	12 Months Ended
Organization	Dec. 31, 2011
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 3). We are an international offshore energy company that provides development solutions and other contracting services to the energy market as well as to our own oil and gas properties. Our Contracting Services segment utilizes our vessels, offshore equipment and proprietary technologies to deliver services that may reduce finding and development costs and cover the complete lifecycle of an offshore oil and gas field. Our Contracting Services are located primarily in the Gulf of Mexico, North Sea, Asia Pacific, and West Africa regions. Our Oil and Gas segment engages in prospect generation, exploration, development and production activities. Our oil and gas operations are located in the Gulf of Mexico. 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 operations, robotics, subsea construction and production facilities. We have disaggregated our contracting services operations into two continuing reportable business segments: Contracting Services and Production Facilities. Our Contracting Services business primarily consists of well operations, robotics and subsea construction activities. Formerly, we had a third Contracting Services business segment, Shelf Contracting, which represented the assets of CDI. We sold substantially all of our ownership of CDI through various transactions in 2009 (Note 3). Our Production Facilities business includes our equity investments in Deepwater Gateway, L.L.C. ("Deepwater Gateway") and Independence Hub, LLC ("Independence Hub") (Note 7), as well as our majority ownership of the Helix Producer I ("HP I") vessel. Oil and Gas Operations We began our oil and gas operations to achieve incremental returns, to expand our off-season asset utilization of our contracting services assets, and to provide a more efficient solution to offshore abandonment. We have evolved this business model to include not only mature oil and gas properties but also unproved and proved reserves yet to be explored and developed. This has led to the assembly of services that allows us to create value at key points in the life of a reservoir from exploration through development, life of field management and operating through abandonment. Discontinued Operations In April 2009, we sold Helix Energy Limited ("HEL"), our former reservoir technology consulting business, to a subsidiary of Baker Hughes Incorporated for $25 million. As a result of the sale of HEL, which entity's operations were conducted by its wholly owned subsidiary, Helix RDS Limited ("Helix RDS"), we have presented the results of Helix RDS as discontinued operations in the accompanying consolidated financial statements. HEL and Helix RDS were previously components of our Contracting Services segment. In 2009, we recognized an $8.3 million gain on the sale of HEL. Events in Gulf of Mexico In April 2010, an explosion occurred on the Deepwater Horizon drilling rig located on the site of the Macondo well at Mississippi Canyon Block 252. The resulting events included loss of life, the complete destruction of the drilling rig, and an oil spill the magnitude of which was unprecedented in U.S. territorial waters. In May 2010, the U.S. Department of Interior ("DOI") announced a total moratorium on new drilling in the Gulf of Mexico. In October 2010, the DOI lifted the deepwater drilling moratorium and instructed the Bureau of Ocean Energy Management, Regulation and Enforcement ("BOEMRE") that it could resume issuing drilling permits conditioned on the requesting company's compliance with all revised drilling, safety and environmental requirements. No post moratorium deepwater drilling permits were issued by BOEMRE until late February 2011. In October 2011, the BOEMRE separated into two new federal agencies, the Bureau of Ocean Energy Management ("BOEM") and Bureau of Safety and Environmental Management ("BSEE"). We developed the Helix Fast Response System ("HFRS") as a culmination of our experience as a responder in the Gulf oil spill response and containment efforts. The HFRS centers on two vessels, the HP I and the Q4000, both of which played a key role in the Gulf well control and containment efforts and are presently operating in the Gulf of Mexico. In 2011, we signed an agreement with Clean Gulf Associates ("CGA"), a non-profit industry group, allowing, in exchange for a retainer fee, the HFRS to be named as a response resource in permit applications to federal and state agencies, and making the HFRS available for a two-year term to certain CGA participants who have executed utilization agreements with us. In addition to the agreement with CGA, we currently have signed separate utilization agreements with 24 CGA participant member companies specifying the day rates to be charged should the HFRS be deployed in connection with a well control incident. The retainer fee for the HFRS became effective April 1, 2011 and is a component of our Production Facilities business segment. A total of 55 permits have been granted to CGA participants for deepwater drilling operations identifying the HFRS to fulfill the BOERME (BOEM/BSEE) requirement to have a spill response and containment resource included in the submitted permit applications.

Summary Of Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

Summary Of Significant Accounting Policies [Abstract]

Summary Of Significant Accounting Policies

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 consolidated our former subsidiary CDI until June 10, 2009, at which time our ownership in CDI was reduced to less than 50%. We recorded our proportional share of CDI's results under the equity method of accounting until we sold substantially all of our ownership interest in CDI on September 23, 2009. We sold our remaining ownership interest in CDI in 2011. We also account for our Deepwater Gateway, Independence Hub and Australian joint venture investments under the equity method of accounting. Noncontrolling interests represent the minority shareholders' proportionate share of the equity in CDI until we deconsolidated its results in June 2009 and 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.

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

As of December 31, 2011 and 2010, we had $33.7 million and $35.3 million, respectively, of restricted cash included in other assets (Note 6), all of which related to funds required to be escrowed to cover the future asset retirement obligations associated with our South Marsh Island Block 130 field. We have fully satisfied the requirements under the escrow agreement. We have used a small portion of these escrowed funds to pay for the initial reclamation activities at the South Marsh Island Block 130 field. Reclamation activities at the field will occur over many years and will be funded with these escrowed amounts. These amounts are reflected in other assets, net in the accompanying consolidated balance sheets.

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


		Year Ended December 31,
		2011		2010		2009

Interest paid, net of interest capitalized	$	81,000	$	68,534	$	48,313
Income taxes paid	$	11,216	$	10,071	$	106,480

Non-cash investing activities for the years ended December 31, 2011, 2010 and 2009 included $26.1 million, $21.9 million and $48.9 million, respectively, related to accruals of capital expenditures. The accruals have been reflected in the accompanying consolidated balance sheets as an increase in property and equipment and accounts payable.

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 18).

Inventories

We had inventory totaling $18.1 million at December 31, 2011 and $25.3 million at December 31, 2010. Our 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. These costs will be partially reimbursed by third party participants in the wells supplied with these materials. Our inventories are stated at the lower of cost or market value and we utilize the average cost method of maintaining our inventory. 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. This sale transaction closed in early January 2012. There were no charges to reduce inventory to its lower cost or market value in 2010. For the year ended December 31, 2009, we recorded an aggregate of $1.8 million of charges to cost of sales to reduce our inventory to its lower of cost or market value at various times throughout the year.

Property and Equipment

Overview. Property and equipment is recorded at cost. The following is a summary of the gross components of property and equipment (dollars in thousands):

	Estimated Useful Life		2011		2010

ROVs/Vessels	10to 30 years	$	1,616,772	$	1,573,471
Oil and gas leases and related equipment	Units-of-Production		2,574,693		2,747,895
Machinery, equipment, buildings and leasehold improvements	5to 30 years		199,599		164,711
Total property and equipment		$	4,391,064	$	4,486,077

The cost of repairs and maintenance is charged to expense as incurred, while the cost of improvements is capitalized. Total repair and maintenance expenses totaled $40.1 million, $35.0 million and $35.6 million for the years ended December 31, 2011, 2010 and 2009, respectively. Included in machinery, equipment, buildings and leasehold improvements were $18.1 million and $17.8 million of capitalized software costs at December 31, 2011 and 2010, 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, 2011, 2010 and 2009.

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 (a component of cost of sales) 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 flow 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 2011, in an acknowledgment of our declining operating results in Australia and in association with the reorganization of our Australian well operations business, 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. During 2009, we recorded an aggregate $1.3 million charge to reduce the carrying value of certain specific ROV equipment to its fair value of $6.1 million. There were no such impairments related to our vessels during 2011, 2010 and 2009. See Note 5 for disclosure related to the impairment of our 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, 2011 and 2010.

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. We depreciate our other property and equipment over its estimated useful life on a straight-line basis.

Oil and Gas Properties. All of our oil and gas properties are in the United States located offshore in the Gulf of Mexico. We follow 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 flow in the accompanying consolidated statements of cash flows. Costs incurred relating to unsuccessful exploratory wells are expensed in the period when the drilling is determined to be unsuccessful and are included as a reconciling item to net income (loss) in operating activities in the accompanying consolidated statements of cash flows.

Proved Properties. We assess proved oil and gas properties for possible impairment at least annually or when events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. We recognize an impairment loss 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 an impairment is indicated, the cash flows are discounted at an approximate rate that market participants would be willing to pay for similar types of assets and compared to the carrying value for determining the amount of the impairment loss to record. 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 Note 5 for additional information regarding our oil and gas property impairments.

Unproved Properties. We also periodically assess unproved properties for impairment based on exploration and drilling efforts to date on the individual prospects and lease expiration dates. 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 also impact the amounts and timing of impairment provisions. We recorded impairments to unproved oil and gas properties totaling $8.3 million in 2011, $6.4 million in 2010 and $20.1 million in 2009. Such impairments were included in exploration expenses for our Oil and Gas business segment.

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 expense. At times, it may be determined that an exploratory well may have found hydrocarbons at the time drilling is completed, but it may not be possible to classify the reserves at that time. In this case, we may continue to capitalize the drilling costs as an uncompleted, or "suspended," well beyond one year if we can justify its completion as a producing well and we are making sufficient progress assessing the reserves and the economic and operating viability of the project. If reserves are not ultimately deemed proved or economically viable, the well is considered impaired and its costs, net of any salvage value, are charged to expense. See Note 5 for additional information regarding our exploration costs.

Properties Acquired from Business Combinations. Properties acquired through business combinations are recorded at their fair value. In determining the fair value of the proved and unproved properties, we prepare estimates of oil and gas reserves. We estimate future prices to apply to the estimated reserve quantities acquired and the estimated future operating and development costs to arrive at our estimates of future net revenues. For the fair value assigned to proved reserves, the future net revenues are discounted using a market-based weighted average cost of capital rate determined to be appropriate at the time of the acquisition. To compensate for inherent risks of estimating and valuing unproved reserves, probable and possible reserves are reduced by additional risk weighting factors.

Capitalized Interest. 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, 2011, 2010 and 2009 was $1.3 million, $12.5 million and $48.1 million, respectively.

Equity Investments

We periodically review our equity investments in Deepwater Gateway, Independence Hub and our Australian joint venture 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. See Notes 3 and 9 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, 2011 we had two reporting units with goodwill and our impairment analysis.

In 2011, we adopted the new accounting standards intended 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. 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. Early adoption is permitted, including for annual and interim goodwill impairment tests performed, if an entity's financial statements for the most recent annual or interim period have not yet been issued. The Company early adopted this standard for its annual goodwill impairment tests in 2011.

All of our remaining goodwill at December 31, 2011 ($62.2 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 newly enacted accounting guidance to forego the historically mandated quantitative step 1 impairment analysis. We will continue to monitor the current and future operations of these two reporting units to determine whether or not the mandated 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.

Historically, 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 had been 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.

We did not record any impairment of goodwill in 2009 based on our evaluations conducted throughout the year. We primarily focused our goodwill evaluations on our Well Ops SEA Pty Ltd ("WOSEA") reporting unit's goodwill as its results were adversely affected by damage to its main revenue generating asset. The asset repairs were substantially complete at December 31, 2009 and based on WOSEA's then forecasted business activity no impairment of its goodwill was necessary during 2009. WOSEA placed its revenue generating asset back in service in 2010 and also entered into the an Australian joint venture in February 2010 (Note 7). 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 1 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 2 requirements. This impairment charge is reflected as a separate line item in the accompanying consolidated statement of operations titled "Goodwill impairments." WOSEA is part of our Contracting Services business segment.

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


	Contracting Services

Balance at December 31, 2009 (1)	$	78,643
Impairments (2)		(16,743	)
Other adjustments(3)		594
Balance at December 31, 2010		62,494
Impairments		—
Other adjustments(3)		(279	)
Balance at December 31, 2011	$	62,215

(1)	Prior to 2009, we fully impaired our oil and gas related goodwill ($704.3 million) as well as the $8.3 million of goodwill associated with our former reservoir consulting business.

(2)	Amount reflects full write off of goodwill associated with our WOSEA operations.

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

At December 31, 2011, our only remaining intangible asset, other than goodwill, was $1.6 million ($0.5 million, net of accumulated amortization) for intellectual property related to our well operations business in the North Sea. Total amortization expenses for intangible assets for the years ended December 31, 2011, 2010, and 2009 was $0.1 million, $0.1 million and $2.4 million, respectively. We expect to record a total of $0.1 million of amortization expense related to our remaining unamortized intellectual property for each of the next five years.

Recertification Costs and Deferred Drydock 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 drydock. 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 drydock and related recertification costs over the length of time for which we expect to receive benefits from the drydock 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 drydock and related recertification processes. A drydock 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, 2011 and 2010, capitalized deferred drydock charges included within Other Assets in the accompanying consolidated balance sheets (Note 6) totaled $5.4 million and $11.1 million, respectively. During the years ended December 31, 2011, 2010 and 2009, drydock amortization expense was $7.6 million, $6.9 million and $16.4 million, respectively. Amounts attributed to Cal Dive's operations totaled $9.3 million for the period prior to its deconsolidation in June 2009.

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 consist of estimated costs for dismantlement, removal, site reclamation and similar activities associated with our 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 (both long term and current) for the years ended December 31, 2011 and 2010 (in thousands):

		2011			2010

Asset retirement obligations at January 1,	$	234,936		$	248,128
Liability incurred during the period		4,982			18,056
Liability settled during the period		(42,675	)		(55,114	)
Other revisions in estimated cash flows		42,268	(1)		8,349
Accretion expense (included in depreciation and amortization)		14,880			15,517
Asset retirement obligations at December 31,	$	254,391		$	234,936

(1)	Includes impairment charges totaling $41.7 million, including $20.0 million associated with our only United Kingdom oil and gas property, to increase the estimated asset retirement obligation related to properties that are no longer producing oil or natural gas.

Revenue Recognition

Contracting Services Revenues

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 or other 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, 2011 and 2010 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 the 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 16 for information regarding our more significant loss contracts during the three years ended December 31, 2011.

Oil and Gas Revenues

We record revenues from the sales of crude oil and natural gas 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, we use the entitlements method to account for sales of production. Under the entitlements method, we may receive more or less than our entitled share of production. If we receive more than our entitled share of production, the imbalance is treated as a liability. If we receive less than our entitled share, the imbalance is recorded as an asset. As of December 31, 2011, the net imbalance was a $0.9 million asset and was included in Other Current Assets ($5.1 million) and Accrued Liabilities ($4.2 million) in the accompanying consolidated balance sheet.

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, 2011, 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

The functional currency for our foreign subsidiary, Helix Well Ops (U.K.) Limited is the applicable local currency (British Pound), and the functional currency of WOSEA is the applicable local currency (Australian Dollar). 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, 2011 and 2010 and the resulting translation adjustment, which was an unrealized losses of $1.0 million and $10.0 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 $(1.6) million in 2011, $1.7 million in 2010 and $2.2 million in 2009. These realized amounts are exclusive of any unrealized gains or losses from our foreign currency exchange derivative contracts.

Derivative Instruments and Hedging Activities

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

We engage solely in cash flow hedges. Hedges of cash flow exposure are entered into to hedge a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability. Changes in the derivative fair values that are designated as cash flow hedges are deferred to the extent that they are effective and are recorded as a component of accumulated other comprehensive income, 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.

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, the 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 are amortized to earnings over the remaining period of the original forecasted transaction.

Commodity Price Risks

The fair value of derivative instruments reflects our best estimate and is based upon exchange or over-the-counter quotations whenever they are available. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, we utilize other valuation techniques or models to estimate market values. These modeling techniques require us to make estimations of future prices, price correlation and market volatility and liquidity. Our actual results may differ from our estimates, and these differences can be positive or negative.

Historically, we have entered into various financial derivative contracts, including costless collar and swap contracts, to stabilize cash flows relating to a portion of our expected oil and gas production. At December 31, 2008, our commodity derivative contracts continue to qualify for hedge accounting. However, the effects of the hurricane damage sustained in the third quarter of 2008 continued to disrupt our production causing most of our 2009 natural gas financial contracts to no longer qualified for hedge accounting as of March 31, 2009. At their inception, our forward sales contracts qualified for the normal purchases and sales scope exception but due to disruptions in our production as a result of damage caused by the 2008 hurricanes these contracts ceased to qualify for the scope exception at March 31, 2009. As previously noted, contracts that fail to qualify for hedge accounting must be marked-to-market each reporting period.

At December 31, 2009, all the then existing commodity derivative contracts qualified for hedge accounting. In June 2010, oil contracts for 480 MBbl of our anticipated production during the third quarter of 2010 ceased to qualify for hedge accounting as a result of our decision to contract the HP I to assist in the Gulf oil spill response and containment efforts rather than commencing production from our Phoenix field. In September 2010, we concluded that oil contracts covering 480 MBbls of the fourth quarter 2010 anticipated production ceased to qualify for hedge accounting because of uncertainty as to when the Phoenix field would be ready to commence initial production following extensions of the HP I contract to assist BP in the oil spill response and containment efforts. The HP I returned to the Phoenix field in October and initial production from the field commenced on October 19, 2010. At December 31, 2011, all of our existing commodity derivative contracts qualified for hedge accounting treatment.

The aggregate fair value of our commodity derivative instruments represented a net asset of $19.8 million at December 31, 2011 and a net liability of $24.4 million at December 31, 2010. For the years ended December 31, 2011, 2010 and 2009, we recorded unrealized gains (losses) of approximately $28.7 million, $(6.5) million and $(19.1) million, respectively, net of taxes (benefit) of $15.5 million, $(3.5) million and $(10.3) million, respectively, in accumulated other comprehensive income (loss). During 2011, 2010 and 2009, we reclassified approximately $(21.7) million, $25.6 million and $17.0 million, respectively, of gains (losses) from accumulated other comprehensive income (loss) to oil and gas revenues upon the sale of the related oil and gas production. In addition, during 2010 and 2009 we recorded gains of approximately $1.1 million and $89.5 million, respectively, to reflect mark-to-market adjustments for changes in the fair values of our contracts that no longer qualified for hedge accounting. These gains are reported in the accompanying consolidated statements of operations in the line titled "Gain on oil and gas derivative commodity contracts". There were no mark-to-market adjustments during 2011 associated with our commodity derivative contracts. The amount of ineffectiveness related to our oil and gas commodity contracts was immaterial for all periods presented in this Annual Report on Form10-K. See Note 20 for more disclosure regarding our hedge contracts.

As of December 31, 2011, we had derivatives contracts related to our oil and gas production totaling approximately 3.8 million barrels of oil and 17 Bcf of natural gas. At December 31, 2011 our derivative commodity contracts were as follows:

Production Period	Instrument Type	Average Monthly Volumes	Weighted Average Price a
Crude Oil:			(per barrel)
January 2012 — December 2012	Collar	75.0 MBbl	$ 96.67 — $118.57b
January 2012 — December 2012	Collar	139.0 MBbl	$ 99.42 — $117.59
January 2012 — December 2012	Swap	16.0 MBbl	$103.20
January 2013 — December 2013	Swap	41.7 MBbl	$99.15
January 2013 — December 2013	Collar	41.7 MBbl	$ 95.00 — $102.60

Natural Gas:			(per Mcf)
January 2012 — December 2012	Swaps	750.0 Mmcf	$4.35
January 2012 — December 2012	Collar	166.7 Mmcf	$4.75 — $5.09
January 2013 — December 2013	Swaps	500.0 Mmcf	$4.09

a.	The prices quoted in the table above are NYMEX Henry Hub for natural gas. For oil most of the contracts are priced as Brent crude oil.

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

In February 2012, we entered into a costless collar financial derivative contract associated with a total of 0.1 MMBbls of our anticipated crude oil production in 2013, with a floor price of $100 per barrel and a ceiling price of $120 per barrel as indexed to Brent crude oil prices.

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

Variable Interest Rate Risks

As the interest rates for some of our long-term debt are subject to market influences and will vary over the term of the debt, we entered into various interest rate swaps to stabilize cash flows relating to a portion of our interest payments on our variable interest rate debt. Changes in the interest rate swap fair value are deferred to the extent the swap is effective and are recorded as a component of accumulated other comprehensive income until the anticipated interest payments occur and are recognized in interest expense. The ineffective portion of the interest rate swap, if any, will be recognized immediately in earnings. Ineffectiveness related to our interest swaps was immaterial for all periods presented in this Annual Report on Form 10-K.

In January 2010, we entered into $200 million two-year interest rate swaps to stabilize cash flows relating to a portion of our interest payments on our Term Loan, which extended through January 2012 (Note 9). 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 contracts settle monthly beginning in January 2012 and extend through January 2014. The fair value of our remaining interest swap contracts was a net asset of $0.1 million at December 31, 2011 and a net liability of $1.9 million at December 31, 2010 (Note 20).

Foreign Currency Exchange Risks

Because we operate in various regions in the world, we conduct a portion of our business in currencies other than the U.S. dollar. We entered into various foreign currency forwards to stabilize expected cash outflows relating to certain vessel charters that are denominated in British pounds. The aggregate fair value of the foreign currency forwards was a net liability of $0.1 million at December 31, 2011 and a net asset of $0.2 million at December 31, 2010. 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 $0.2 million in 2011, $(2.6) million in 2010 and $3.3 million in 2009 associated with foreign exchange contracts not qualifying for hedge accounting. See Note 20 for more information regarding our foreign currency contracts.

Earnings Per Share

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

The presentation of basic EPS amounts on the face of the accompanying consolidated statements of operations is computed by dividing the net income available to common shareholders by the weighted average shares of outstanding common stock. The calculation of diluted EPS is similar to basic EPS, except that the denominator includes dilutive common stock equivalents and the income included in the numerator excludes the effects of the impact of dilutive common stock equivalents, if any. The computations of the numerator (income) and denominator (shares) to derive the basic and diluted EPS amounts presented on the face of the accompanying consolidated statements of operations for the years ended December 31, 2011, 2010 and 2009 are as follows (in thousands):


		Year Ended December 31,
		2011				2010				2009
		Income		Shares		Income		Shares		Income		Shares
Basic:
Net income (loss) applicable to common shareholders	$	129,939			$	(127,102	)		$	101,867
Less: Undistributed net income allocable to participating securities		(1,599	)			—				(1,436	)
Undistributed net income (loss) applicable to common shareholders		128,340				(127,102	)			100,431
(Income) loss from discontinued operations		—				—				(9,581	)
Add: Undiscounted net income from discontinued operations allocable to participating securities		—				—				135
Income (loss) per common share – continuing operations	$	128,340		104,528	$	(127,102	)	103,857	$	90,985		99,136


		Year Ended December 31,
		2011			2010				2009
		Income	Shares		Income		Shares		Income	Shares
Diluted:
Net income (loss) per common share – continuing operations – Basic	$	128,340	104,528	$	(127,102	)	103,857	$	90,985	99,136
Effect of dilutive securities:
Stock options		—	64		—		—		—	28
Undistributed earnings reallocated to participating securities		7	—		—		—		80	—
Convertible Senior Notes		—	—		—		—		—	—
Convertible preferred stock		40	361		—		—		748	6,556
Income (loss) per common share — continuing operations		128,387			(127,102	)			91,813
Income (loss) per common share — discontinued operations		—			—				9,581
Net income (loss) per common share	$	128,387	104,953	$	(127,102	)	103,857	$	101,394	105,720

The cumulative $53.4 million of beneficial conversion charges that were realized and recorded during the first quarter of 2009 following the transactions affecting our convertible preferred stock (Note 11) are not included as an addition to adjust earnings applicable to common stock for our diluted EPS calculation.

We had a net loss applicable to common shareholders for the year ended December 31, 2010. Accordingly, our diluted EPS calculation for 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 each of the year ended December 31, 2010, assuming we had earnings from continuing operations, are as follows (in thousands):


	2010
Diluted shares (as reported)		103,857
Stock options		54
Convertible preferred stock		1,015
Total		104,926

The diluted EPS calculation during the year ended December 31, 2010 also excluded the consideration of adding back the $0.1 million of 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 diluted during the year.

There were no dilutive shares associated with our 3.25% Convertible Senior Notes as the conversion price of $32.14 was not met in any of the years ended December 31, 2011, 2010 and 2009 (Note 9).

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 of major customers, those whose total represented 10% or more of our consolidated revenues, was as follows: 2011 — Shell (49%); 2010 — Shell (29%) and BP Plc. (17%) and 2009 —Shell (19%). These customers were primarily purchasers of our oil and gas production. We estimate that in 2011 we provided subsea services to over 75 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 noted. The valuation techniques are 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 value 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 and our long-term debt. 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, 2011 (in thousands):

		Level 1		Level 2 (1)		Level 3		Total	Valuation Technique
Assets:
Oil and gas swaps and collars	$	–	$	22,381	$	–	$	22,381	(c)
Interest rate swaps		–		327		–		327	(c)
Foreign currency forwards		–		55		–		55	(c)

Liabilities:
Oil and gas swaps and collars		–		2,597		–		2,597	(c)
Interest rate swaps		–		202		–		202	(c)
Foreign currency forwards		–		159		–		159	(c)
Fair value of long term debt (2)		1,081,376		124,488		–		1,205,864	(a)
Total net liability	$	1,081,376	$	104,683	$	–	$	1,186,059

(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. Where quotes are not available, we utilize other valuation techniques or models to estimate market values. These modeling techniques require us to use published future market prices and estimate market volatility and liquidity based on market data. Our actual results may differ from our estimates, and these differences can be positive or negative.

(2)	See Note 9 for additional information regarding our long term debt.

The fair value of our debt at December 31, 2011 and December 31, 2010 is as follows:


	2011				2010
	Carrying Value		Fair Value		Carrying Value		Fair Value

Term Loan(1)	$	279,750	$	279,750	$	410,441	$	406,337
Revolving Credit Facility	—		—		—		—
Convertible Senior Notes(1) (2)		300,000		300,543		300,000		289,158
Senior Unsecured Notes(1)		474,960		501,083		550,000		567,875
MARAD Debt(3)		110,166		124,488		114,811		122,159
Loan Notes	—		—			1,208		1,208
Total	$	1,164,876	$	1,205,864	$	1,376,460	$	1,386,737

(1)	The fair values of these instruments were based on quoted market prices as of December 31, 2011 and 2010. The fair values were estimated using level 1 inputs using the market approach.
(2)	Carrying amounts exclude the $9.6 million and $18.5 million of unamortized discount on the Convertible Senior Notes at December 31, 2011 and 2010, respectively.
(3)	The fair value of the MARAD debt was determined by a third-party evaluation of the remaining average life and outstanding principal balance of the MARAD indebtedness as compared to other government guaranteed obligations in the market place with similar terms. The fair value of the MARAD debt was estimated using Level 2 fair value inputs using the 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 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

In 2011, we recorded impairment charges totaling $132.6 million, including $20.0 million related to our one U.K oil and gas property. These impairment charges affected the carrying value for 27 of our oil and gas fields in the Gulf of Mexico. These impairment charges reduced each field's carrying value to its then estimated fair value, which was $60.6 million following the respective impairment charges. In 2010, we recorded impairment charges totaling $181.1 million, including $5.0 million related to our one U.K oil and gas property. These impairment charges affected 28 of our Gulf of Mexico oil and gas properties. The estimated aggregate fair value of these 28 fields was $91.5 million following each field's respective impairment charge. In 2009, we recorded a total of $120.6 million of impairment charges, including the $51.5 million of hurricane-related impairments (Note 4). These impairment charges affected the carrying value of 47 of our Gulf of Mexico oil and gas fields. The aggregate fair value of these 47 fields was $36.2 million following each respective field's impairment charge. See Notes 5 and 21 for additional information regarding our oil and gas impairment charges, including impairment charges to increase the value of non-producing properties' estimated asset retirement obligations.

Debt Discount

On January 1, 2009, we recorded a discount of $60.2 million related to our Convertible Senior Notes as required under a newly-effective accounting pronouncement. To arrive at this discount amount we estimated the fair value of the liability component of the Convertible Senior 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. In selecting the expected life, we selected the earliest date that the holder could require us to repurchase all or a portion of the Convertible Senior Notes (December 15, 2012). The remaining unamortized amount of the discount of the Convertible Notes was $9.6 million at December 31, 2011 (Note 9).

Ownership Of Cal Dive International, Inc.	12 Months Ended
Ownership Of Cal Dive International, Inc.	Dec. 31, 2011
Ownership Of Cal Dive International, Inc. [Abstract]
Ownership Of Cal Dive International, Inc.	Note 3 — Ownership of Cal Dive International, Inc. Our ownership in CDI as of December 31, 2008 was approximately 57.2%. In January 2009, we sold approximately 13.6 million shares of Cal Dive common stock to Cal Dive for $86 million. This transaction constituted a single transaction and was not part of any planned set of transactions that would result in us having a noncontrolling interest in Cal Dive, and reduced our ownership in Cal Dive to approximately 51%. Because we retained control of CDI immediately after the transaction, the loss of approximately $2.9 million on this sale was treated as a reduction of our equity in the accompanying consolidated balance sheet. In June 2009, we sold 22.6 million shares of Cal Dive common stock held by us pursuant to a secondary public offering ("Offering"). Proceeds from the Offering totaled approximately $182.9 million, net of underwriting fees. Simultaneously with the closing of the Offering, pursuant to a Stock Repurchase Agreement with Cal Dive, Cal Dive repurchased from us approximately 1.6 million shares of its common stock for net proceeds of $14 million at $8.50 per share, the Offering price. Following the closing of these two transactions, our ownership of Cal Dive common stock was reduced to approximately 26%. Because these transactions reduced our ownership in Cal Dive to less than 50%, the $59.4 million gain resulting from the sale of these shares was reflected in "Gain on investment in Cal Dive common stock" in the accompanying consolidated statement of operations. The $59.4 million amount included an approximate $27.1 million gain associated with the re-measurement of our remaining 26% ownership interest in Cal Dive at its fair value on June 10, 2009, the date of the closing of the Offering, which represented the date of deconsolidation. Since we no longer held a controlling interest in Cal Dive, we ceased consolidating Cal Dive effective June 10, 2009, and subsequently accounted for our remaining ownership interest in Cal Dive under the equity method of accounting until September 23, 2009, as further discussed below. On September 23, 2009, we sold 20.6 million shares of Cal Dive common stock held by us pursuant to a second secondary public offering ("Second Offering"). On September 24, 2009, the underwriters sold an additional 2.6 million shares of Cal Dive common stock held by us pursuant to their overallotment option under the terms of the Second Offering. The price for the Second Offering was $10 per share, with resulting proceeds totaling approximately $221.5 million, net of underwriting fees. We recorded an approximate $17.9 million gain associated with the Second Offering transactions. Following the closing of the Second Offering 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 at December 31, 2010. 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 the closing of the Second Offering. Our investment in Cal Dive was $2.8 million at December 31, 2010. 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. Proceeds from our Cal Dive stock sale transactions were used for general corporate purposes.

The entire disclosure for restructuring and related activities. Description of restructuring activities such as exit and disposal activities, include facts and circumstances leading to the plan, the expected plan completion date, the major types of costs associated with the plan activities, total expected costs, the accrual balance at the end of the period, and the periods over which the remaining accrual will be settled.

Details Of Certain Accounts [Abstract]

Insurance Matters	12 Months Ended
Insurance Matters	Dec. 31, 2011
Insurance Matters [Abstract]
Insurance Matters	Note 4 – Insurance Matters In September 2008, we sustained damage to certain of our facilities resulting from Hurricane Ike. All of our business segments were affected by the hurricane; however, the oil and gas segment suffered the substantial majority of our damage. While we sustained damage to our own production facilities from Hurricane Ike, the larger issue in terms of our production recovery involved damage to third party pipelines and onshore processing facilities. The timing of the repairs of these facilities was not subject to our control. One significant third party pipeline was not repaired and placed back into service until January 2010. Our insurance policy, which covered all of our operated and non-operated producing and non-producing properties, was subject to an approximate $6 million aggregate deductible. We met our $6 million aggregate deductible in September 2008. We record our hurricane-related repair costs as incurred in cost of sales. We record insurance reimbursements when the realization of the claim for recovery of a loss is deemed probable. We did not have any material hurricane-related repair cost in the year ended December 31, 2011. For the years ending December 31, 2010 and 2009 we incurred $4.7 million and $25.8 million, respectively, of hurricane-related repair costs related to our oil and gas assets. In June 2009, we reached a settlement with the underwriters of our insurance policies related to damage from Hurricane Ike. Insurance proceeds received in the second quarter of 2009 totaled $102.6 million. In the second quarter of 2009, we recorded a $43.0 million net reduction in our cost of sales representing the amount by which our insurance recoveries exceeded our costs during the second quarter of 2009. The cost reduction reflected the net proceeds of $102.6 million partially offset by $8.1 million of hurricane-related expenses incurred in the second quarter of 2009 and $51.5 million of hurricane-related impairment charges, including $43.8 million of additional estimated asset retirement costs resulting from additional work performed and/or further evaluation of facilities on properties that were classified as a "total loss" following the storm. In 2011, we received $5.0 million of supplemental insurance reimbursements. Our insurance year runs from July 1 to June 30. Since 2009 our insurance renewals have not included wind storm coverage as the premium and deductibles have been relatively substantial for the coverage provided. In order to mitigate potential loss with respect to our most significant oil and gas properties from hurricanes in the Gulf of Mexico, we entered into a Catastrophic Bond instrument. The Catastrophic Bond provides for payments of negotiated amounts should an eye of a Category 2 or Category 3 or greater hurricane pass within specific pre-defined areas encompassing our more prominent oil and gas producing fields. The Catastrophic Bond is not considered a risk management instrument for accounting purposes. Accordingly, the payment associated with the Catastrophic Bond is not charged to expense on a straight line basis as is customary with insurance premiums, but rather it is charged to expense on a basis to reflect the Catastrophic Bond's intrinsic value at the end of the period. Because our Catastrophic Bond was underwritten to mitigate the risk of hurricanes in the Gulf of Mexico, substantially all of its intrinsic value is for the period associated with the "hurricane season" (typically June 1 to November 30) with a substantial majority of the intrinsic value associated with the period July 1 to September 30. The insurance expense associated with the Catastrophic Bond payment is recorded as lease operating expense a component of cost of sales for our oil and gas operations. In June 2011, 2010 and 2009 we made our hurricane catastrophic bond payment associated with each upcoming insurance period. The payments were $10.6 million in June 2011, $11.9 million in June 2010 and $13.1 million in June 2009. The insurance expense charges recorded in each of the respective third quarter periods to reduce the value of our hurricane catastrophic bond to its intrinsic value at September 30th totaled $8.4 million in 2011, $9.4 million in 2010 and $10.4 million in 2009. For each of the respective fourth quarter periods the respective insurance charges totaled $2.0 million in 2011, $2.3 million in 2010 and $2.4 million in 2009.

Oil And Gas Properties

12 Months Ended

Dec. 31, 2011

Oil And Gas Properties [Abstract]

Oil And Gas Properties

Note 5 — Oil and Gas Properties

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

At December 31, 2011, we had capitalized costs associated with ongoing exploration and/or appraisal activities totaling $5.8 million. These capitalized costs may be charged against earnings in future periods if management determines that commercial quantities of hydrocarbons have not been discovered or that future appraisal drilling or development activities are not likely to occur. The following table provides a detail of our capitalized exploratory project costs at December 31, 2011 and 2010 (in thousands):

		2011		2010
Wang (1)	$	3,096	$	3,095
Danny 2 (1)		2,619		32
Other		125		125
Total	$	5,840	$	3,252

(1)

Amounts primarily reflect pre-engineering costs. The Wang prospect is located in proximity of our Phoenix field that commenced production in October 2010. The Danny 2 (formerly Kathleen) prospect is located within our Bushwood field at Garden Banks Blocks 462, 463, 506 and 507. Both Wang and Danny 2 are budgeted exploration capital expenditures for 2012.

The following table reflects net changes in exploratory well costs during the years ended December 31, 2011, 2010 and 2009 (in thousands):

		2011		2010			2009

Beginning balance at January 1,	$	3,252	$	3,059		$	2,105
Additions pending the determination of proved reserves		2,513		(944	)		36,208
Reclassifications to proved properties		5		713			(34,622	)
Charged to dry hole expense		70		424			(632	)
Ending balance at December 31,	$	5,840	$	3,252		$	3,059

Further, the following table details the components of exploration expense for the years ended December 31, 2011, 2010 and 2009 (in thousands):


		Years Ended December 31,
		2011			2010			2009

Delay rental and geological and geophysical costs	$	2,650		$	2,306		$	3,016
Impairment of unproved properties		8,334			6,394			20,130
Dry hole expense		(70	)		(424	)		1,237
Total exploration expense	$	10,914		$	8,276		$	24,383

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 Revenues. Royalty fees paid totaled approximately $85.4 million, $37.2 million and $26.8 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Gulf of Mexico Acquisitions and Dispositions.

In August 2006, we acquired a 100% working interest in the Typhoon oil field (Green Canyon Blocks 236/237), the Boris oil field (Green Canyon Block 282) and the Little Burn oil field (Green Canyon Block 238) in exchange for the assumption of certain asset retirement obligations. We renamed this field "Phoenix". We sold a 30% working interest in these fields to a third party in 2007 for $40 million. Production was re-established from the Phoenix field on October 19, 2010. The Little Burn oil field commenced production in August 2011.

In the first quarter of 2009, we sold our interest in East Cameron Block 316 for gross proceeds of approximately $18 million. In the second quarter of 2009, we sold three fields for gross proceeds of $0.8 million resulting in an aggregate gain of $1.2 million, including the transfer of the fields' asset retirement obligations.

In 2009, we farmed-out our 100% leasehold interests in Green Canyon Block 490 located in the deepwater of the Gulf of Mexico. Our farm out agreement was structured such that the operator paid 100% of the drilling costs to evaluate the prospective reservoir. The operator drilled a successful exploration well and we subsequently elected to participate for a 25 percent working interest in the field. Well completion and development commenced in 2011. In December 2011, we sold our ownership interest in this field for gross proceeds of approximately $31 million and recorded a pre-tax gain of $4.5 million. The transaction is also subject to certain customary closing conditions, which will result in the receipt of additional proceeds for capital expenditures we paid subsequent to the sale transaction effective date.

Royalty Claims

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

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. The following table contains the fair value of the assets acquired and liabilities assumed in our acquisition of this third party and its 50% working interest in the Camelot field (in thousands):

Cash	$	10,156
Deferred tax asset		2,083
Accrued liabilities		(439	)
Asset retirement obligation		(5,841	)
Gain on acquisition of assets	$	5,959

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. We recorded $5.0 million of total impairment charges to fully impair the property in 2010.

Our plan is to fully abandon the field in 2012 in accordance with applicable regulations in the United Kingdom. Modifications to U.K regulations over 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 that needs to be performed in the abandoning of the wells in the field would be significantly expanded and as a result our cost estimates have significantly increased. Based on our abandonment plan for 2012, we increased the asset retirement obligation by $20.0 million in 2011, which is reflected as a component of our impairment of oil and gas properties in the accompanying consolidated statements of operations. At December 31, 2011, the recorded asset retirement obligation for the Camelot field was $27.3 million.

Impairments

Proved property impairment charges are reflected as reductions in cost of sales in the accompanying consolidated statements of operations. However, because of the materiality of our oil and gas property impairment charges we reflect these as a separate line item within cost of sales in the accompanying consolidated statements of operations.

In 2011, we recorded $132.6 million of oil and gas property impairment charges, including $20.0 million related to our one U.K oil and gas property (see "United Kingdom Property" above). The $112.6 million of impairment charges associated with 27 of our Gulf of Mexico oil and gas fields included $21.7 million related to increasing the estimated asset retirement obligation for fields that are no longer producing. The impairment charges associated with producing fields totaled $90.9 million and were primarily related to changes in the related 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 $181.1 million of oil and gas property impairment charges, including $5.0 million related to our one U.K. oil and gas property. A total of 28 of our Gulf of Mexico oil and gas properties were affected by impairments charges in 2010. The impairment charges associated with producing fields totaled $172.6 million, which primarily reflected reduction in our estimated proved reserves (Note 19). We also recorded $3.5 million of impairment charges to increase certain non-producing field's estimated asset retirement obligations.

In 2009, we recorded $120.6 million of oil and gas property impairment charges. We impaired a total of 47 of our Gulf of Mexico oil and gas properties. The impairment charges associated with producing fields totaled $72.4 million, which reflected decreases in estimated proved reserves associated with mechanical and production issues at certain fields. We also recorded $48.2 million of impairment charges to increase certain fields estimated asset retirement obligations, including $43.8 million of impairment related charges recorded to properties that were severely damaged by Hurricane Ike (Note 4).

Details Of Certain Accounts

12 Months Ended

Dec. 31, 2011

Details Of Certain Accounts

Note 6 — Details of Certain Accounts (in thousands)

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

		2011		2010

Other receivables	$	5,096	$	1,247
Prepaid insurance		12,701		12,375
Other prepaids		13,271		11,623
Spare parts inventory		18,066		25,333
Current deferred tax assets		41,449		49,200
Hedging assets		21,579		5,472
Income tax receivable		—		6,099
Gas and oil imbalance		5,134		6,001
Other		4,325		5,715
	$	121,621	$	123,065

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

		2011		2010

Restricted cash	$	33,741	$	35,339
Deferred drydock costs, net		5,381		11,086
Deferred financing costs, net		26,483		25,697
Intangible assets with finite lives		531		636
Other		2,771		1,803
	$	68,907	$	74,561

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

		2011		2010

Accrued payroll and related benefits	$	49,599	$	38,026
Royalties payable		19,391		15,008
Current asset retirement obligations		93,183		64,526
Unearned revenue		7,654		1,817
Billings in excess of costs		28,839		6,146
Accrued interest		24,028		27,308
Hedging liability		1,247		30,606
Gas and oil imbalance		4,177		770
Other		11,845		14,030
	$	239,963	$	198,237

Equity Investments

12 Months Ended

Dec. 31, 2011

Equity Investments [Abstract]

Equity Investments

Note 7 — Equity Investments

In June 2002, we formed Deepwater Gateway with Enterprise Products Partners, L.P., in which we each own a 50% interest, to design, construct, install, own and operate a tension leg platform ("TLP") production hub in deepwater of the Gulf of Mexico. Deepwater Gateway primarily services the Marco Polo field, which is owned and operated by Anadarko Petroleum Corporation. Our share of the Deepwater Gateway construction costs was approximately $120 million and our investment totaled $96.0 million and $99.8 million as of December 31, 2011 and 2010, respectively, and was included in our Production Facilities business segment. The investment balance at December 31, 2011 and 2010 included approximately $1.4 million and $1.5 million, respectively, of capitalized interest and insurance paid by us.

In December 2004, we acquired a 20% interest in Independence Hub, an affiliate of Enterprise. Independence Hub owns the Independence Hub platform located in Mississippi Canyon Block 920 in a water depth of 8,000 feet. First production began in July 2007. Our investment in Independence Hub was $79.7 million and $82.4 million as of December 31, 2011 and 2010, respectively (including capitalized interest of $4.9 million and $5.2 million at December 31, 2011 and 2010, respectively), and was included in our Production Facilities business segment.

We made the following contributions to our equity investments during the years ended December 31, 2011, 2010 and 2009 (in thousands):


		Year Ended December 31,
		2011		2010		2009

Clough Helix Pty Ltd. (see below)	$	2,699	$	8,253	$	—
Other		—		—		1,657
Total	$	2,699	$	8,253	$	1,657

We received the following distributions from our equity investments during the years ended December 31, 2011, 2010 and 2009 (in thousands):


		Year Ended December 31,
		2011		2010		2009

Deepwater Gateway	$	7,600	$	8,125	$	6,750
Independence Hub		18,580		21,615		26,000
Other		—		268		—
Total	$	26,180	$	30,008	$	32,750

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 vessel that is under charter to the joint venture until November 2013. 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; while 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 SapuraCrest Petroleum Berhad ("Sapura"). Sapura acquired Clough's 50% ownership interest in the joint venture in this transaction. The joint venture is continuing; however, there is now considerable uncertainty on whether the term of the joint venture will continue subsequent to the expiration of the original charter of the Normand Clough in November 2013. Separately, at December 31, 2011, the limited backlog of work indicated that earnings and resulting cash flow from the joint venture was at best expected to break even during 2012. Because of these indicators, we conducted an impairment assessment of our investment in the joint venture. 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.

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


		Year Ended December 31,
		2011		2010		2009

Revenues	$	193,521	$	141,705	$	141,664
Operating income		97,954		93,324		118,566
Net income		93,215		93,005		118,602


		At December 31,
		2011		2010		2009

Current assets	$	39,754	$	25,352	$	18,620
Total assets		591,761		594,645		602,413
Current liabilities		11,012		6,434		415
Total liabilities		27,163		19,695		734

(1)	Results do not include any amounts associated with Cal Dive. We accounted for our investment in Cal Dive under the equity method from June 10, 2009 to September 23, 2009 (Note 3).

The entire disclosure for equity investment, or group of investments, for which combined disclosure is appropriate, including: (a) the name of each investee and percentage of ownership of common stock, (b) accounting policies for investments in common stock, (c) difference between the amount at which the investment is carried and the amount of underlying equity in net assets and the accounting treatment of the difference, (d) the total fair value of each identified investment for which a market value is available, (e) summarized information as to assets, liabilities, and results of operations of the investees (for investments in unconsolidated subsidiaries, common stock of joint ventures, or other investments using the equity method), and (f) material effects of possible conversions, exercises, or contingent issuances of the investee. Other disclosures include (a) the names of any investee in which the investor owns 20 percent or more of the voting stock and investment is not accounted for using the equity method, and the reasons why not, and (b) the names of any investee in which the investor owns less than 20 percent of the voting stock and the investment is accounted for using the equity method, and the reasons why it is.

Kommandor LLC	12 Months Ended
Kommandor LLC	Dec. 31, 2011
Kommandor LLC [Abstract]
Kommandor LLC	Note 8 — 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 our Phoenix field, in which we hold a 70% working interest. 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 Gulf oil spill response 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 on October 19, 2010. 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 $196.2 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 the cash outlay to Kommandor RØMØ for its interest in Kommandor LLC at the time the put or call is exercised to 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, 2011.

Long-Term Debt

12 Months Ended

Dec. 31, 2011

Long-Term Debt [Abstract]

Long-Term Debt

Note 9 — Long-Term Debt

Senior Unsecured Notes

On December 21, 2007, we issued $550 million of 9.5% Senior Unsecured Notes due January 2016 ("Senior Unsecured Notes"). The Senior Unsecured Notes are fully and unconditionally guaranteed by substantially all of our existing restricted domestic subsidiaries, except Cal Dive I-Title XI, Inc. In addition, any future guarantor of our or any of our restricted subsidiaries' indebtedness is also required to guarantee the Senior Unsecured Notes. Our foreign subsidiaries are not guarantors of the Senior Unsecured Notes. We used the proceeds from the Senior Unsecured Notes to repay outstanding indebtedness under our Senior Credit Facilities (see below).

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 existing and future senior unsecured indebtedness of the Company. The Senior Unsecured Notes rank senior in right of payment to any of our future subordinated indebtedness and are fully and unconditionally guaranteed by the guarantors described above on a senior basis.

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 Senior Unsecured Notes indenture are terms, conditions and covenants that are customary for this type of offering. 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, 2011, we were in compliance with these covenants.

Prior to the stated maturity, after January 15, 2012, we may redeem all or a portion of the Senior Unsecured Notes, on not less than 30 days' nor more than 60 days' prior notice, at the redemption prices (expressed as percentages of the principal amount) set forth below, plus accrued and unpaid interest, 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) 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.

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 the $75.0 million in principal and $2.4 million in premium for the repurchased Senior Unsecured Notes. The premium is reflected as a component of "other income (expense)" in the accompanying consolidated statements of operations. 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 original issuance of the Senior Unsecured Notes.

Credit Agreement

In July 2006, we entered into a credit agreement (the "Credit Agreement") under which we borrowed $835 million in a term loan (the "Term Loan") and were initially able to borrow up to $300 million (the "Revolving Loans") under a revolving credit facility (the "Revolving Credit Facility"). The proceeds from the Term Loan were used to fund the cash portion of the acquisition of Remington Oil and Gas Corporation. At December 31, 2011, the total borrowing capacity under the Revolving Credit Facility totaled $600 million. The full amount of the Revolving Credit Facility may be used for issuances of letters of credit. At December 31, 2011 we had no amounts drawn on the Revolving Credit Facility and our availability under the Facility totaled $558.6 million, net of $41.4 million of unsecured letters of credit issued.

The Term Loan bears interest either at the one-, three- or six-month LIBOR at our current election plus a 2.00% margin (as amended in February 2010, the margin was increased up to 2.50% depending on current leverage ratios, as defined). Our average interest rate on the Term Loan for the years December 31, 2011 and 2010 was approximately 3.8% and 2.9%, respectively (including the effects of our interest rate swaps). The Revolving Loans bear interest based on one-, three- or six-month LIBOR rates or on Base Rates at our current election plus an applicable margin as discussed below. Margins on the Revolving Loans will fluctuate in relation to the consolidated leverage ratio as provided in the Credit Agreement. The average interest rate on the Revolving Loans was approximately 3.4% through the date of their repayment in the second quarter of 2009. We had no amounts outstanding under the revolver at any time during the year ended December 31, 2010.

We have amended the Credit Agreement three times over the past three years with the most recent amendment being effective in June 2011. These amendments among other things:

·	Increase the Revolving Credit Facility to $600 million (capacity was $435 million prior to closing of the June 2011 amendment);

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

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

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

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

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

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

·	amend the consolidated leverage ratio (the ratio is now 4.00 to 1.00).

·	add a Senior Credit Facility leverage ratio, which is now 2.00 to 1.00

increase the margin on Revolving Loans by 0.50% should the consolidated leverage ratio equal or exceed 4.50 to 1.00 and increases the margin on the Term Loan by 0.25% if consolidated leverage ratio is less than 4.50 to 1.00 and 0.50% if the consolidated leverage ratio is equal to or greater than 4.50 to 1.00.

·	permit the disposition of certain oil and gas properties without a limit as to value, provided that we use 60% of the proceeds from such sales to make certain mandatory prepayments of the Term Loan (40% of the proceeds can be reinvested into collateral);

relax limitations on our right to dispose of the Caesar vessel, by permitting the disposition of the Caesar provided that we use 60% of the proceeds from such sale to make certain mandatory prepayments of the Term Loan and permit us to contribute the Caesar to a joint venture or similar arrangement (40% of the proceeds can be reinvested into collateral); and

·	increase the maximum amount of all investments permitted in subsidiaries that are neither loan parties nor whose equity interests are pledged from $100 million to $200 million.

We may elect to prepay amounts outstanding under the Term Loan 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 equal to the amount of proceeds received from such occurrences. Such prepayments will be applied first to the Term Loan, and any remaining excess will then be applied to the Revolving Loans.

The Credit Agreement and the other documents (together, the "Loan Documents") include terms, conditions and covenants that we consider customary for this type of transaction. 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, 2011, 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 the Company. 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.

As the rates for our Term Loan are subject to market influences and will vary over the term of the credit agreement, we entered into various cash flow hedging interest rate swaps to stabilize cash flows relating to a portion of our interest payments for our Term Loan. In January 2010, we entered into $200 million, two-year interest rate swaps to stabilize cash flows relating to a portion of our interest payments on our Term Loan, which extend to January 2012. In August 2011, we entered into additional two-year interest rate swap contracts to assist in stabilizing cash flows related to our interest payment though January 2014 (Note 20).

Convertible Senior Notes

In March 2005, we issued $300 million of 3.25% Convertible Senior Notes due 2025 ("Convertible Senior Notes") at 100% of the principal amount to certain qualified institutional buyers. The Convertible Senior Notes are convertible into cash and, if applicable, shares of our common stock based on the specified conversion rate, subject to adjustment. As a result of our two for one stock split in December 2005, the initial conversion rate of the Convertible Senior Notes of 15.56 shares of common stock per $1,000 principal amount of the Convertible Senior Notes, which was equivalent to a conversion price of approximately $64.27 per share of common stock, was changed to 31.12 shares of common stock per $1,000 principal amount of the Convertible Senior Notes, which is equivalent to a conversion price of approximately $32.14 per share of common stock. We may redeem the Convertible Senior Notes on or after December 20, 2012. Beginning with the period commencing on December 20, 2012 to June 14, 2013 and for each six-month period thereafter, in addition to the stated interest rate of 3.25% per annum, we will pay contingent interest of 0.25% of the market value of the Convertible Senior Notes if, during specified testing periods, the average trading price of the Convertible Senior Notes exceeds 120% or more of the principal value. In addition, holders of the Convertible Senior Notes may require us to repurchase the notes at 100% of the principal amount on each of December 15, 2012, 2015, and 2020, and upon certain events, including a change of control (as defined) or the termination of trading of our common stock on a listed exchange. The effective interest rate for the Convertible Senior Notes was 6.6% following the adoption of accounting requirements as of January 1, 2009 (Note 2).

The Convertible Senior Notes can be converted prior to the stated maturity under the following circumstances:

•		during any fiscal quarter if the closing sale price of our common stock for at least 20 trading days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter exceeds 120% of the conversion price on that 30th trading day (i.e., $38.56 per share);
•		upon the occurrence of specified corporate transactions; or
•		if we have called the Convertible Senior Notes for redemption and the redemption has not yet occurred.

To the extent we do not have alternative long-term financing secured to cover such conversion notice, the Convertible Senior Notes would be classified as a current liability in the accompanying consolidated balance sheet. As the holders have the option to require us to redeem the Convertible Senior Notes on December 15, 2012, we assessed whether or not this debt was required to be classified as a current liability at December 31, 2011 and concluded this debt still qualified as a long term debt because a) we possess enough borrowing capacity under our Revolving Credit Facility (see "Credit Agreement" above) to settle the notes in full and b) it is our intent to utilize our Revolving Credit Facility borrowings or other alternative financing proceeds to settle our Convertible Senior Notes, if and when the holders exercise their redemption option.

In connection with any conversion, we will satisfy our obligation to convert the Convertible Senior Notes by delivering to holders in respect of each $1,000 aggregate principal amount of notes being converted a "settlement amount" consisting of:

•		cash equal to the lesser of $1,000 and the conversion value; and
•		to the extent the conversion value exceeds $1,000, a number of shares equal to the quotient of (A) the conversion value less $1,000, divided by (B) the last reported sale price of our common stock for such day.

The conversion value means the product of (1) the conversion rate in effect (plus any applicable additional shares resulting from an adjustment to the conversion rate) or, if the Convertible Senior Notes are converted during a registration default, 103% of such conversion rate (and any such additional shares), and (2) the average of the last reported sale prices of our common stock for the trading days during the cash settlement period. At December 31, 2011, the conversion trigger was not met.

Our weighted average share price for both 2011 and 2010 was below the conversion price of $32.14 per share. The maximum number of shares of common stock which may be issued upon conversion of the Convertible Senior Notes is 13,303,770. We registered the 13,303,770 shares of common stock that may be issued upon conversion of the Convertible Senior Notes as well as an indeterminate number of shares of common stock issuable upon conversion of the Convertible Senior Notes by means of an antidilution adjustment of the conversion price pursuant to the terms of the Convertible Senior Notes.

MARAD Debt

At December 31, 2011 and 2010, $110.2 million and $114.8 million, respectively, was outstanding on our long-term financing used for construction of the Q4000 ("MARAD Debt"). This U.S. Government guaranteed financing is pursuant to Title XI of the Merchant Marine Act of 1936 which is administered by the Maritime Administration. The MARAD Debt is payable in equal semi-annual installments which began in August 2002 and matures 25 years from such date. The MARAD Debt is collateralized by the Q4000, with us guaranteeing 50% of the debt, and initially bore interest at a floating rate which approximated AAA Commercial Paper yields plus 20 basis points. As provided for in the MARAD Debt agreements, in September 2005, we fixed the interest rate on the debt through the issuance of a 4.93% fixed-rate note with the same maturity date (February 2027). 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, 2011, we were in compliance with these debt covenants.

Other

We paid financing costs associated with our debt totaling $9.3 million in 2011 and $2.9 million in 2010. Deferred financing costs of $26.5 million and $25.7 million at December 31, 2011 and 2010, respectively, are included within the caption "Other Assets, Net" in the accompanying consolidated balance sheets and are being amortized over the life of the respective debt agreements.

Scheduled maturities of long-term debt as of December 31, 2011 are as follows (in thousands):

		Helix Term Loan			Helix Revolving Loans		Senior Unsecured Notes		Convertible Senior Notes(1)			MARAD Debt			Total

Less than one year	$	3,000		$	—	$	—	$	—		$	4,877		$	7,877
One to two years		3,000			—		—		—			5,120			8,120
Two to three years		3,000			—		—		—			5,376			8,376
Three to four years		270,750			—		—		—			5,644			276,394
Four to five years		—			—		474,960		—			5,925			480,885
Over five years		—			—		—		300,000			83,224			383,224
Total debt		279,750			—		474,960		300,000			110,166			1,164,876
Current maturities		(3,000	)		—		—		—			(4,877	)		(7,877	)
Long-term debt, less current maturities		276,750			—		474,960		300,000			105,289			1,156,999
Unamortized debt Discount		—			—		—		(9,555	)		—			(9,555	)
Long-term debt	$	276,750		$	—	$	474,960	$	290,445		$	105,289		$	1,147,444

(1)	Beginning in December 2012, we may at our option repurchase the notes or the holders may require us to repurchase the notes. The notes will increase to the $300 million face amount through accretion of non-cash interest charges through December 2012.

We had unsecured letters of credit outstanding at December 31, 2011 totaling approximately $41.4 million. These letters of credit primarily guarantee various contract bidding, asset retirement obligations and insurance activities. The following table details our interest expense and capitalized interest for the years ended December 31, 2011, 2010 and 2009 (in thousands):


		Year Ended December 31,
		2011			2010			2009

Interest expense	$	99,152		$	99,184		$	105,775
Interest income		(2,079	)		(1,407	)		(923	)
Capitalized interest		(1,277	)		(12,474	)		(48,119	)
Interest expense, net	$	95,796		$	85,303		$	56,733

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, 2011

Income Taxes [Abstract]

Income Taxes

Note 10 — 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 conduct our international operations in a number of locations that have varying laws and regulations with regard to taxes. Management believes that adequate provisions have been made for all taxes that will ultimately be payable. 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 were as follows:


	Year Ended December 31,
	2011			2010			2009

Statutory rate		35.0	%		35.0	%		35.0	%
Foreign provision		(2.0	)		(4.3	)		(1.1	)
Effect of Australian reorganization	(21.2		)	—				—
IRC Section 199 deduction	—			—				(1.2	)
CDI equity pick up in excess of tax basis	—			—				3.0
Nondeductible goodwill impairment (Note 2)	—				(4.4	)	—
Valuation allowance on certain deferred tax assets	—				(3.1	)	—
Other		(1.7	)		1.0			0.9
Effective rate		10.1	%		24.2	%		36.6	%

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.

Components of the provision (benefit) for income taxes reflected in the statements of operations consisted of the following (in thousands):


			Year Ended December 31,
		2011			2010			2009

Current	$	16,306		$	7,238		$	160,829
Deferred		(1,403	)		(46,836	)		(65,007	)
	$	14,903		$	(39,598	)	$	95,822

Domestic	$	119	$	(57,165	)	$	94,388
Foreign		14,784		17,567			1,434
	$	14,903	$	(39,598	)	$	95,822

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, 2011 and 2010 were as follows (in thousands):

		2011			2010

Deferred tax liabilities:
Depreciation and depletion	$	396,355		$	384,313
OID on Convertible Notes		37,067			34,169
Equity investments in production facilities		76,911			69,495
Prepaid and other		14,779			15,616
Total deferred tax liabilities	$	525,112		$	503,593

Deferred tax assets:
Net operating loss carryforward	$	(34,987	)	$	(38,718	)
Asset retirement obligations		(88,279	)		(81,345	)
Reserves, accrued liabilities and other		(39,995	)		(27,588	)
Total deferred tax assets	$	(163,261	)	$	(147,651	)
Valuation allowance		14,310			8,497

Net deferred tax liability	$	376,161		$	364,439

Deferred income tax is presented as:
Current deferred tax asset	$	(41,449	)	$	(49,200	)
Noncurrent deferred tax liabilities		417,610			413,639
Net deferred tax liability	$	376,161		$	364,439

At December 31, 2011, our federal net operating loss carryforward totaled $17.6 million and our foreign tax credit carryforward totaled $9.7 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, 2011, we had a $14.3 million valuation allowance related to certain non-U.S. deferred 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, 2011 and 2010, our principal non-U.S. subsidiaries had accumulated earnings and profits of approximately $113.4 million and $28.2 million, respectively. We have not provided deferred U.S. income tax on the accumulated earnings and profits.

We have $7.1 million related to uncertain tax positions, of which $0.9 million is accrued interest and penalties. We account for tax related interest in interest expense and tax penalties in operating expenses. During 2011, we recorded a $2.8 million long term liability related to an uncertain tax position and a $0.2 million long term liability for interest and penalties. As of December 31, 2011, 2010, and 2009 there were $6.2 million, $3.4 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):


	2011		2010		2009

Balance at January 1,	$	4,085	$	3,417	$	5,183
Additions based on tax positions related to current year		2,785	—		—
Additions for tax positions of prior years		215		668		773
Reductions for tax positions of prior years	—		—			(2,539	)
Balance at December 31,	$	7,085	$	4,085	$	3,417

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, 2006, 2007, 2008 and 2009 are under examination by the U.S. Internal Revenue Service ("IRS"). The tax periods ended December 31, 2010 and 2011 remain open to future review and examination by the IRS. In non-U.S. jurisdictions, the open tax periods include 2007, 2008, 2009, 2010 and 2011.

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.

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

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 136, 172
-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 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 43, 44, 45, 46, 47, 48, 49
-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 Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 15
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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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-SubTopic 10
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-Paragraph 9
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32639-109319

Reference 6: 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 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32537-109319

Reference 8: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 740
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-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32559-109319

Convertible Preferred Stock	12 Months Ended
Convertible Preferred Stock	Dec. 31, 2011
Convertible Preferred Stock [Abstract]
Convertible Preferred Stock	Note 11 — Convertible Preferred Stock In January 2009, Fletcher International, Ltd. ("Fletcher") issued a redemption notice with respect to its $30 million of Series A-2 Cumulative Convertible Preferred Stock and, pursuant to the resulting redemption, we issued and delivered 5,938,776 shares of our common stock to Fletcher. Accordingly, in the first quarter of 2009 we recognized a $29.3 million charge to reflect the terms of this redemption, which was recorded as a reduction in our net income applicable to common shareholders. This beneficial conversion charge reflected the value associated with the additional 3,974,718 shares delivered in connection with the redemption over the original 1,964,058 shares that would have been contractually required to be issued upon a conversion but was limited to the $29.3 million of net proceeds we received from the issuance of the Series A-2 Cumulative Convertible Preferred Stock in June 2004. In February 2009, the price of our common stock fell below $2.767 per share. Under the terms of the agreement governing the issuance of the preferred stock, we provided notice to Fletcher that with respect to the $25 million of Series A-1 Cumulative Convertible Preferred Stock the conversion price was reset to $2.767, the established minimum price per the agreement; that Fletcher shall have no further rights to redeem the shares; and that we have no further right to pay dividends in common stock. As a result of the reset of the conversion price, Fletcher would receive an aggregate of 9,035,056 shares in future conversion(s) into our common stock. In the event we elected to settle any future conversion in cash, Fletcher would receive cash in an amount approximately equal to the value of the shares it would receive upon a conversion, which could be substantially greater than the original face amount of the Series A-1 Cumulative Convertible Preferred Stock, and which would result in additional beneficial conversion charges in our statement of operations. Under the existing terms of our Credit Agreement (Note 9) we are not permitted to deliver cash upon a conversion of the Convertible Preferred Stock. In connection with the reset of the conversion price of the Series A-1 Cumulative Convertible Preferred Stock to $2.767, we were required to recognize a $24.1 million charge to reflect the value associated with the additional 7,368,388 shares that will be required to be delivered upon any future conversion(s) over the 1,666,668 shares that were to be delivered under the original contractual terms. This $24.1 million charge was recorded as a beneficial conversion charge reducing our net income applicable to common shareholders. The beneficial conversion charge for the Series A-1 Cumulative Convertible Preferred Stock was limited to the $24.1 million of net proceeds received upon its issuance in January 2003. In the third quarter of 2009, Fletcher converted $19 million of its Series A-1 Cumulative Convertible Preferred Stock into 6,866,641 shares of our common stock. In May 2010, Fletcher converted $5 million of its Series A-1 Cumulative Convertible Preferred Stock into 1,807,011 shares of our common stock. The remaining $1 million of the Series A-1 Cumulative Convertible Preferred Stock, which is convertible into 361,402 shares of our common stock, maintains its mezzanine presentation below liabilities but is not included as a component of shareholders' equity, because we may, under certain instances, be required to settle any future conversions in cash. Prior to any future conversion(s), the common shares issuable will be assessed for inclusion in our diluted earnings per share computations using the if converted method based on the applicable conversion price of $2.767 per share, meaning that for all periods in which we have positive earnings from continuing operations and our average stock price exceeds $2.767 per share we will have an assumed conversion of convertible preferred stock and the 361,402 shares will be included in our diluted shares outstanding amount. At December 31, 2010, the $1 million of Convertible Preferred Stock outstanding was excluded from our diluted earnings per share calculation because we had a loss from continuing operations (Note 2). The preferred stock has a minimum annual dividend rate of 4%, subject to adjustment, payable quarterly in cash. The dividend rate was 4% in 2011, 2010 and 2009. We paid these dividends in cash.

Employee Benefit Plans

12 Months Ended

Dec. 31, 2011

Employee Benefit Plans [Abstract]

Employee Benefit Plans

Note 12 — 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 50 percent of each employee's contribution up to five percent of the employee's salary. Our costs related to deferred compensation plans totaled $1.4 million, $1.6 million and $1.5 million for the years ended December 31, 2011, 2010 and 2009, 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 (the "2005 Incentive Plan"). As of December 31, 2011, there were approximately 920,748 shares available for grant under our 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 key executives and selected employees and non-employee members of the 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. The aggregate number of shares that may be granted under the 2005 Incentive Plan is 6,000,000 shares (after adjustment for the December 2005 two-for-one stock split) of which 4,000,000 shares may be granted in the form of restricted stock or restricted stock units and 2,000,000 shares may be granted in the form of 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. For awards granted in 2012 under the Incentive Plans the vesting period is now three years or 33% per year. Stock options granted have a maximum exercise life of ten years. At December 31, 2011, all stock options outstanding had previously vested.

We use the Black-Scholes option pricing model for valuing share-based payments relating to stock options and recognize compensation cost on a straight-line basis over the applicable vesting period. Forfeitures on restricted stock totaled approximately 17% 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. We did not grant any stock options in 2011, 2010 or 2009. 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 options outstanding at December 31, 2011, have exercise prices as follows: 98,000 at $8.57; 14,000 shares at $10.59; 28,000 at $10.92 and 52,800 shares at $13.91 and a weighted average remaining contractual life of 1.4 years.

Options outstanding are as follows:


	2011					2010					2009
	Shares			Weighted Average Exercise Price		Shares			Weighted Average Exercise Price		Shares			Weighted Average Exercise Price

Options outstanding at beginning of year		432,918		$	10.78		501,318		$	10.74		521,654		$	10.66
Exercised		(181,670	)	$	10.92		(68,400	)	$	10.52		(20,336	)	$	8.67
Terminated		(58,448	)	$	11.20		—			—		—			—
Options outstanding at end of year		192,800		$	10.52		432,918		$	10.78		501,318		$	10.74
Options exercisable end of year		192,800		$	10.52		432,918		$	10.78		501,318		$	10.74

There was no compensation recognized associated with stock options in 2011 or 2010 as all stock options outstanding are vested. For the year ended December 31, 2009, $0.1 million was recognized as compensation expense related to stock options. The aggregate intrinsic value of the stock options exercised in 2011, 2010 and 2009 was approximately $1.1 million, $0.1 million and $0.1 million, respectively. The aggregate intrinsic value of options exercisable at December 31, 2011, 2010 and 2009 was approximately $1.0 million, $0.6 million and $0.5 million, respectively.

Restricted Shares

We grant restricted shares to members of our board of directors, all executive officers and selected management employees. Compensation cost for each award is the product of grant date market value of each share and the number of shares granted. The following table summarizes information about our restricted shares during the years ended December 31, 2011, 2010 and 2009:


	2011					2010					2009
	Shares			Grant Date Fair Value(1)		Shares			Grant Date Fair Value(1)		Shares			Grant Date Fair Value(1)
Restricted shares outstanding at beginning of year		1,463,298		$	16.93		1,443,265		$	21.55		1,206,526		$	31.73
Granted		571,163		$	12.77		599,996		$	12.01		656,887		$	7.12
Vested		(504,813	)	$	19.87		(444,905	)	$	25.10		(327,777	)	$	33.69
Forfeited		(266,430	)	$	12.55		(135,058	)	$	17.48		(92,371	)	$	8.90
Restricted shares outstanding at end of year		1,263,218		$	14.80		1,463,298		$	16.93		1,443,265		$	21.55

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

For the years ended December 31, 2011, 2010 and 2009, $8.4 million, $9.0 million, $9.4 million, respectively, was recognized as compensation expense related to restricted shares. Future compensation cost associated with unvested restricted stock awards at December 31, 2011, 2010, and 2009 totaled approximately $23.4 million, $29.7 million and $21.8 million, respectively. The weighted average vesting period related to nonvested restricted stock awards at December 31, 2011 was approximately 2.7 years.

In January 2012, we granted our executive officers 132,910 restricted shares under the 2005 Long-Term Incentive Plan. The market value of the restricted shares was $15.80 per share or $2.1 million and the shares vest 33% per year for a three-year period. Separately, we issued our executive officers 132,910 performance share units ("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.

In January 2012, we also granted selected management employees 139,243 restricted stock units ("RSUs") 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. The market value of these RSUs was $15.80 per share or $2.2 million and will vest 33% per year for a three-year period.

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.

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 terms of the 2009 LTI Plan, the cash awards that have been granted to non-executive management vest over a five-year period of employment and are made in a fixed sum amount. There were no cash awards to non-executive officers in 2011. Our executive officers are granted cash awards in which the amount of the payment on each applicable payment anniversary date (five-year term for awards granted prior to the January 2012 grant, which has a three-year term) will fluctuate based upon the Company's stock performance. 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. 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 50% (75% for 2012 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. The share-based component of our 2009 LTI Plan is considered a liability plan and as such will be re-measured to fair value each reporting period with corresponding changes be recorded as a charge to income as appropriate. At December 31, 2011 the liability under this stock-based liability plan was $8.5 million. We paid $4.0 million of this liability on January 3, 2012.

The awards made under the 2009 LTI Plan totaled $5.2 million to our executive officers in 2011, $10.2 million, including $6.0 million to our executive officers in 2010 and $14.7 million, including $8.1 million for our Executive Officers in 2009. For the years ended December 31, 2011, 2010 and 2009, $7.9 million ($6.5 million related to our executive officers), $8.6 million ($6.9 million related to our executive officers) and $3.7 million ($2.6 million related to executive officers), respectively, was recognized as compensation expense related to the 2009 LTI Plan. In January 2012, $4.2 million was awarded under the 2009 LTI Plan to our executive officers. No cash awards were given to non-executive employees.

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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-Name Statement of Financial Accounting Standard (FAS)
-Number 123R
-Paragraph 64, 65, A240
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Name Statement of Position (SOP)
-Number 93-6
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-Number Topic 14

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Shareholders' Equity

12 Months Ended

Dec. 31, 2011

Shareholders' Equity [Abstract]

Shareholders' Equity

Note 13 — 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, 2011 and 2010 were as follows (in thousands):

		2011			2010

Cumulative foreign currency translation adjustment	$	(22,958	)	$	(21,956	)
Unrealized losses on hedges, net (1)		12,941			(17,102	)
Accumulated other comprehensive loss	$	(10,017	)	$	(39,058	)

(1)	Amounts are net of deferred income tax asset (liabilities) totaling $7.0 million and $(9.2) million at December 31, 2011 and 2010, respectively.

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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-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 12
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Name Regulation S-X (SX)
-Number 210
-Section 04
-Article 3

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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Research Bulletin (ARB)
-Number 43
-Chapter 1
-Section B
-Paragraph 7, 11A
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 129
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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-Name Regulation S-X (SX)
-Number 210
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-Article 4

Reference 7: http://www.xbrl.org/2003/role/presentationRef
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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-Name Regulation S-X (SX)
-Number 210
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Reference 21: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Preferred Stock
-URI http://asc.fasb.org/extlink&oid=6521494

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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Stock Buyback Program	12 Months Ended
Stock Buyback Program	Dec. 31, 2011
Stock Buyback Program [Abstract]
Stock Buyback Program	Note 14 — 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 12) as permitted under our Credit Agreement (Note 9). 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 early October 2011, we purchased the remaining 497,412 shares then available under this plan for $6.5 million or an average of $13.07 per share. As of December 31, 2011, we had repurchased a total of 2,473,730 shares of our common stock for $30.5 million or an average of $12.34 per share. We retire all repurchased shares.

Related Party Transactions	12 Months Ended
Related Party Transactions	Dec. 31, 2011
Related Party Transactions [Abstract]
Related Party Transactions	Note 15 — Related Party Transactions In April 2000, we acquired a 20% working interest in Gunnison, a Deepwater Gulf of Mexico prospect of Kerr-McGee. Financing for the exploratory costs of approximately $20 million was provided by an investment partnership (OKCD Investments, Ltd. or "OKCD"), the investors of which include certain current and former Helix senior management, in exchange for a revenue interest that is an overriding royalty interest of 25% of Helix's 20% working interest. Production from the Gunnison field commenced in December 2003. We have made payments to OKCD totaling $8.3 million, $11.2 million and $11.3 million in the years ended December 31, 2011, 2010 and 2009 respectively. Our Chief Executive Officer, Owen Kratz, through Class A limited partnership interests in OKCD, personally owns approximately 80.7% of the partnership. In 2000, OKCD also awarded Class B revenue interests 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 $3.6 million for services provided to us in 2011. During 2010 and 2009, while this individual was still a member of our board of directors, we paid $6.9 million and $3.3 million, respectively, to Weatherford, an oil and gas industry company, for services provided to us.

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

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Regulation S-X (SX)
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-Article 4
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Name Regulation S-X (SX)
-Number 210
-Article 3A
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Reference 3: 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	12 Months Ended
Commitments And Contingencies	Dec. 31, 2011
Commitments And Contingencies [Abstract]
Commitments And Contingencies	Note 16 — Commitments and Contingencies Lease Commitments We lease several facilities, ROVs and vessels under noncancelable operating leases. Future minimum rentals under these leases are approximately $54.4 million at December 31, 2011 with $42.8 million due in 2012, $7.6 million in 2013, $1.8 million in 2014, $1.2 million in 2015, $0.4 million in 2016 and $0.6 million thereafter. Total rental expense under these operating leases was approximately $62.2 million, $66.2 million and $89.9 million for the years ended December 31, 2011, 2010 and 2009, respectively. 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 Intrepid, Seawell and Express and $375,000 on the Caesar. In addition to the primary deductibles the vessels are subject to an Annual Aggregate Deductible of $1.25 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, 2011 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. Litigation, Contingencies and Claims In March 2009, we were notified of a third party's intention to terminate an international construction contract based on a claimed breach of that contract by one of our subsidiaries. Under the terms of the contract, our potential liability for damages was generally capped at approximately $32 million Australian dollars ("AUD"). We asserted counterclaims that in the aggregate approximated $12 million U.S. dollars. On March 30, 2010, an out of court settlement of these claims was reached. Pursuant to the terms of the settlement agreement, in April 2010 we paid the third party $15 million AUD to settle all of its damage claims against us. We also agreed not to seek any further payment of our counterclaims against them. In the first quarter of 2010, we recorded approximately $17.5 million in expenses associated with this settlement agreement, including $13.8 million for the litigation settlement payment and $3.7 million to write off our remaining trade receivable from the third party. These amounts were recorded as selling, general and administrative expenses in the accompanying consolidated statements of operations. In 2006, we were subcontracted to perform development work for a large gas field offshore India. Work commenced in the fourth quarter of 2007 and we completed our scope of work in the third quarter of 2009. To date we have collected approximately $303 million related to this project with an amount of trade receivables and claims yet to be collected. We have requested arbitration in India pursuant to the terms of the subcontract to pursue our claims and the prime contractor has also requested arbitration and has asserted certain counterclaims against us. If we are not successful in resolving these matters through ongoing discussions with the prime contractor, then arbitration in India remains a potential remedy. Based on number of factors associated with the ongoing negotiations with the prime contractor, in 2010, we established 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 related to a subsea construction and diving contract we entered into in December 2006 in India for the tax years 2007, 2008, 2009, and 2010. The State claims we owe unpaid taxes related to products consumed by us during the period of the contract. We are of the opinion that the State has arbitrarily assessed this VAT tax and has no foundation for the assessment and believe that we have complied with all rules and regulations as relate to VAT in the State. We also believe that our position is supported by law and intend to vigorously defend our position. However, the ultimate outcome of this assessment and our potential liability from it, if any, cannot be determined at this time. If the current assessment is upheld, it may have a material negative effect on our consolidated results of operations while also impacting our financial position. 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. We had one such contract in 2008, which was ultimately terminated because of the delay in the delivery of the Caesar. As of December 31, 2008, we estimated the loss under this contract at $9.0 million. In the second quarter of 2009, services under this contract were substantially completed by a third party and we revised our estimated loss to approximately $15.8 million. Subsequently, we settled the liability for $12.7 million. Accordingly we included an additional $3.7 million of charges to cost of sales in the accompanying consolidated statements of operations for the year ended December 31, 2009. We paid $7.2 million of the loss in 2008 and the remaining $5.5 million in the second quarter of 2010. In 2010, we had two additional 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. Commitments Since September 30, 2009, we have added three vessels to our fleet. The Well Enhancer joined our well operations fleet in October 2009, and the Caesar, a pipelay vessel, and the HP I, a floating production unit vessel, were placed in service in the first half of 2010. The construction of these three vessels has represented a substantial amount of our capital expenditures since 2007. Although all three vessels are in service, a certain amount of future capital will be required to be spent to fully complete the vessels. For example, in 2010, we completed installation of a coil tubing unit on the Well Enhancer. The timing of future capital upgrades is mainly determined by the vessel's utilization as we attempt to coordinate such activities with known gaps in its contractual backlog or when the vessel is scheduled for a regulatory inspection and/or drydocking. In February 2012, we announced that we are initiating construction of a new multi-service semi-submersible well intervention and well operations vessel similar to our existing Q4000 vessel. This vessel is expected to be completed and placed in service in 2015.

The entire disclosure for commitments and contingencies.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Business Segment Information [Abstract]

Business Segment Information

12 Months Ended

Dec. 31, 2011

Business Segment Information

Note 17 — Business Segment Information

Our operations are conducted through the following lines of business: contracting services and oil and gas. We have disaggregated our contracting services operations into two reportable business segments: Contracting Services and Production Facilities. As a result, our reportable segments consisted of the following: Contracting Services, Oil and Gas and Production Facilities. Contracting Services operations include well operations and robotics, subsea construction and deepwater pipelay. Previously, we had a fourth business segment, Shelf Contracting, which represented the operations of CDI. In June 2009, we ceased consolidating CDI when our ownership interest decreased to below 50% following the sale of a substantial portion of CDI common stock held by us (Note 3). We continued to disclose the results of Shelf Contracting business as a segment up to and through June 10, 2009, the date we deconsolidated it from our financial statements. All material intercompany transactions between the segments have been eliminated.

We evaluate our performance based on income before income taxes of each segment. Segment assets are comprised of all assets attributable to the reportable segment. The majority of our Production Facilities segment (Deepwater Gateway and Independence Hub) is accounted for under the equity method of accounting. We consolidate our investment in the HP I and Kommandor LLC and its results are included within our Production Facilities segment.

The following summarizes certain financial data by business segment:


		Year Ended December 31,
		2011			2010			2009

		(in thousands)

Revenues —
Contracting Services	$	738,235		$	780,339		$	796,158
Shelf Contracting		—			—			404,709
Oil and Gas		696,607			425,369			385,338
Production Facilities(1)		75,460			117,300			3,395
Intercompany elimination		(111,695	)		(123,170	)		(127,913	)
Total	$	1,398,607		$	1,199,838		$	1,461,687

Income (loss) from operations —
Contracting Services	$	107,013		$	77,391		$	118,176
Shelf Contracting		—			—			59,077
Oil and Gas		129,936			(160,206	)		91,668
Production Facilities(1)		38,404			63,863			(3,918	)
Corporate		(39,918	)		(56,609	)		(47,734	)
Intercompany elimination		93			(19,095	)		(13,454	)
Total(2)	$	235,528		$	(94,656	)	$	203,815

Net interest expense and other —
Contracting Services	$	765		$	1,299		$	(2,280	)
Shelf Contracting		—			—			6,642
Oil and Gas		25,833			18,886			20,152
Production Facilities		442			865			2,011
Corporate and eliminations		72,913			65,274			24,970
Total	$	99,953		$	86,324		$	51,495

Equity in earnings of equity investments	$	22,215		$	19,469		$	32,329

Income (loss) before income taxes —
Contracting Services	$	97,798		$	72,459		$	120,456
Shelf Contracting		—			—			52,435
Oil and Gas		104,103			(179,092	)		71,516
Production Facilities(1)		58,064			86,100			18,300
Corporate and eliminations		(111,985	)		(143,218	)		(715	)
Total	$	147,980		$	(163,751	)	$	261,992


		Year Ended December 31,
		2011			2010			2009

		(in thousands)

Provision (benefit) for income taxes —
Contracting Services	$	29,235		$	42,828		$	43,334
Shelf Contracting		—			—			16,275
Oil and Gas		35,858			(62,954	)		23,352
Production Facilities		19,233			29,049			6,198
Corporate and eliminations		(69,423	)		(48,521	)		6,663
Total	$	14,903		$	(39,598	)	$	95,822

Identifiable assets —
Contracting Services	$	2,006,065		$	1,856,016		$	1,738,005
Oil and Gas		1,041,506			1,223,014			1,541,153
Production Facilities		534,776			512,990			499,497
Discontinued operations		—			—			878
Total	$	3,582,347		$	3,592,020		$	3,779,533

Capital expenditures —
Contracting Services	$	69,259		$	65,949		$	204,228
Shelf Contracting		—			—			39,569
Oil and Gas		119,614			84,554			137,168
Production Facilities		30,896			56,269			42,408
Total	$	219,769		$	206,772		$	423,373

Depreciation and amortization —
Contracting Services	$	73,291		$	66,333		$	53,411
Shelf Contracting		—			—			34,243
Oil and Gas		219,915			235,290			168,101
Production Facilities		14,935			9,907			3,295
Corporate and eliminations		2,962			5,586			3,567
Total	$	311,103		$	317,116		$	262,617

(1)	In April 2009, Kommandor LLC commenced leasing the HP I to us under terms of a charter arrangement following the completion of the initial conversion of the vessel (Note 8). The HP I was certified as a floating oil and gas production unit in June 2010 following the completion of installation of oil and gas processing facilities on the vessel. The HP I participated in the BP oil spill and containment response efforts and is currently being utilized as the processing unit for our Phoenix field.

(2)	Includes $16.7 million of goodwill impairment charge for year ending December 31, 2010 related to our contracting services segment. Also includes approximately $132.6 million, $181.1 million and $120.6 million of asset impairment charges for certain oil and gas properties for the years ended December 31, 2011, 2010 and 2009 respectively.

Intercompany segment revenues during the years ended December 31, 2011, 2010 and 2009 was as follows (in thousands):


		Year Ended December 31,
		2011		2010		2009

Contracting Services	$	65,638	$	109,012	$	120,048
Production Facilities		46,057		14,158		—
Shelf Contracting		—		—		7,865
Total	$	111,695	$	123,170	$	127,913

Intercompany segment profit (loss) (which only relates to intercompany capital projects) during the years ended December 31, 2011, 2010 and 2009 was as follows (in thousands):


		Year Ended December 31,
		2011			2010		2009

Contracting Services	$	104		$	15,655	$	13,205
Production Facilities		(197	)		3,457		(116	)
Shelf Contracting		—			—		365
Total	$	(93	)	$	19,112	$	13,454

Revenue by individually significant country during the years ended December 31, 2011, 2010 and 2009 was as follows (in thousands):


		Year Ended December 31,
		2011		2010		2009

United States	$	1,013,476	$	827,597	$	923,481
United Kingdom		275,499		198,011		124,896
India		44,772		56,311		233,466
Other		64,860		117,919		179,844
Total	$	1,398,607	$	1,199,838	$	1,461,687

We include the property and equipment, net in the county in which it is legally owned. The following table provides our property and equipment, net of depreciation by country (in thousands):


		Year Ended December 31,
		2011		2010		2009

United States	$	2,034,978	$	2,236,455	$	2,564,673
United Kingdom		281,430		275,012		284,637
Other		14,919		15,613		14,396
Total	$	2,331,327	$	2,527,080	$	2,863,706

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.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Number 131
-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.

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Supplemental Oil and Gas Disclosures [Abstract]

Allowance Accounts

12 Months Ended

Dec. 31, 2011

Allowance Accounts [Abstract]

Allowance Accounts

Note 18 — 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, 2011 (in thousands):


	Allowance for Uncollectible Accounts			Deferred Tax Asset Valuation Allowance
Balance, December 31, 2008	$	5,905		$	3,317
Additions		9,220			—
Deductions (1)		(9,953	)		(3,317	)
Balance, December 31, 2009		5,172			—
Additions (2)		4,108			8,497
Deductions(3)		(4,753	)		—
Balance, December 31, 2010		4,527			8,497
Additions(4)		61			5,813
Deductions		(521	)		—
Balance, December 31, 2011	$	4,067		$	14,310

(1)	Amounts include reductions of $5.9 million to the allowance for uncollectible accounts and $3.3 million to the deferred tax valuation allowance to reflect the deconsolidation of Cal Dive in June 2009 (Note 3).

(2)

Amounts include a $4.0 million bad debt allowance related to a large international construction contract and the valuation allowance includes a $7.3 million 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.

(3)	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 16).

(4)	The valuation allowance includes $4.9 million related to our WOSEA operations and $0.9 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 10 for a detailed discussion of the valuation allowance related to our deferred tax assets.

Supplemental Oil And Gas Disclosures

12 Months Ended

Dec. 31, 2011

Supplemental Oil And Gas Disclosures

Note 19 — Supplemental Oil and Gas Disclosures (Unaudited)

Accounting Rules Activities

We adopted the modernized oil and gas reserve requirements for our proved reserve estimates and the related reserve report at December 31, 2009. Generally, adoption of these new regulations had little effect on our estimates of reserves however, the rule requiring development of proved undeveloped reserves within five years has subsequently affected our proved reserve estimate and could significantly impact future estimates of our proved reserves (see "Proved Undeveloped Reserves" below).

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):

		2011			2010

Unproved oil and gas properties	$	50,389		$	56,093
Proved oil and gas properties		2,524,304			2,691,802
Total oil and gas properties		2,574,693			2,747,895

Accumulated depletion, depreciation and amortization		(1,703,046	)		(1,673,740	)
Net capitalized costs	$	871,647		$	1,074,155

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 in the accompanying consolidated balance sheets. At December 31, 2011 and 2010, our oil and gas asset retirement obligations totaled $254.4 million and $234.9 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):


	United States		United Kingdom		Total
Year Ended December 31, 2011—
Property acquisition costs:
Proved properties	$	—	$	—	$	—
Unproved properties		41		—		41
Total property acquisition costs		41		—		41

Exploration costs		2,513		—		2,513
Development costs(1)		126,196		—		126,196
Asset retirement cost		26,523		19,923		46,446
Total costs incurred	$	155,273	$	19,923	$	175,196

Year Ended December 31, 2010—
Property acquisition costs:
Proved properties	$	—	$	—	$	—
Unproved properties		364		—		364
Total property acquisition costs		364		—		364

Exploration costs		1,362		—		1,362
Development costs(1)		53,002		—		53,002
Asset retirement cost		18,814		6,542		25,356
Total costs incurred	$	73,542	$	6,542	$	80,084

Year Ended December 31, 2009—
Property acquisition costs:
Proved properties	$	56	$	—	$	56
Unproved properties		1,829		—		1,829
Total property acquisition costs		1,885		—		1,885
Exploration costs		39,225		—		39,225
Development costs(1)		71,489		—		71,489
Asset retirement cost		66,468		2,644		69,112
Total costs incurred	$	179,067	$	2,644	$	181,711

(1)	Development costs include costs incurred to obtain access to proved reserves to drill and equip development wells. Development costs also include costs of developmental dry holes.

Results of Operations for Oil and Gas Producing Activities

Amounts in thousands:


	United States			United Kingdom			Total

Year Ended December 31, 2011—
Revenues	$	696,607		$	—		$	696,607
Production (lifting) costs		176,269			3,974			180,243
Hurricane repair expense (Note 4)		(4,838	)		—			(4,838	)
Exploration expenses(2)		10,914			—			10,914
Depreciation, depletion, amortization and accretion		219,915			—			219,915
Proved property impairment charges and other (3)		113,439			19,967			133,406
Gain on sale or acquisition of oil and gas properties		(4,531	)		—			(4,531	)
Selling and administrative expenses		31,455			107			31,562
Pretax income (loss) from producing activities		153,984			(24,048	)		129,936
Income tax expense (benefit)		45,233			(9,375	)		35,858
Results of oil and gas producing activities(1)	$	108,751		$	(14,673	)	$	94,078

Year Ended December 31, 2010—
Revenues	$	425,369		$	—		$	425,369
Production (lifting) costs		131,156			4,529			135,685
Net hurricane costs (Note 4)		4,699			—			4,699
Exploration expenses(2)		8,276			—			8,276
Depreciation, depletion, amortization and accretion		235,243			47			235,290
Proved property impairment charges and other (3)		177,138			4,995			182,133
Gain on sale of oil and gas properties		(287	)		(5,959	)		(6,246	)
Gain on oil and gas derivative contracts		(1,088	)		—			(1,088	)
Selling and administrative expenses		26,714			112			26,826
Pretax loss from producing activities		(156,482	)		(3,724	)		(160,206	)
Income tax expense (benefit)		(62,526	)		(428	)		(62,954	)
Results of oil and gas producing activities(1)	$	(93,956	)	$	(3,296	)	$	(97,252	)

	United States			United Kingdom			Total
Year Ended December 31, 2009—
Revenues	$	384,375		$	963		$	385,338
Production (lifting) costs		117,565			2,271			119,836
Net hurricane costs (Note 4)		(23,332	)		—			(23,332	)
Exploration expenses(2)		24,383			—			24,383
Depreciation, depletion, amortization and accretion		167,812			1,444			169,256
Proved property impairment charges and other (3)		73,407			—			73,407
Gain on sale of oil and gas properties		(1,949	)		—			(1,949	)
Gain on oil and gas derivative contracts		(89,485	)		—			(89,485	)
Selling and administrative expenses		21,495			59			21,554
Pretax loss from producing activities		94,479			(2,811	)		91,668
Income tax expense (benefit)		24,280			(1,028	)		23,252
Results of oil and gas producing activities(1)	$	70,199		$	(1,783	)	$	68,416

(1)	Excludes net interest expense and other.

(2)	See Note 5 for additional information related to the components of our exploration costs, including impairment charges for expiring unproved leases.
(3)	Other amounts represent additional asset retirement expense recorded upon completion of a field's abandonment.

Estimated Quantities of Proved Oil and Gas Reserves

We employ 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. Our internal reservoir engineers and independent petroleum engineers analyze 100% of our significant United States oil and gas fields (65 fields as of December 31, 2011). 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 engaged Huddleston & Co., Inc. ("Huddleston"), an independent reservoir engineering firm, to prepare a report to estimate our proved reserves. Huddleston prepared a report to estimate our proved reserves at December 31, 2011, 2010 and 2009. Their reserve report at December 31, 2011 is included as Exhibit 99.1 to this Annual Report.

The following table presents our net ownership interest in proved oil reserves (MBbls):


	United States			United Kingdom		Total

Total proved reserves at December 31, 2008		32,012			—		32,012
Revision of previous estimates		232			—		232
Production		(2,741	)		—		(2,741	)
Purchases of reserves in place		—			—		—
Sales of reserves in place		(1	)		—		(1	)
Extensions and discoveries		225			—		225
Total proved reserves at December 31, 2009		29,727			—		29,727
Revision of previous estimates(1)		(1,555	)		—		(1,555	)
Production		(3,354	)		—		(3,354	)
Purchases of reserves in place		—			—		—
Sales of reserves in place		—			—		—
Extensions and discoveries		—			—		—
Total proved reserves at December 31, 2010		24,818			—		24,818
Revision of previous estimates(2)		3,475			—		3,475
Production		(5,785	)		—		(5,785	)
Purchases of reserves in place		—			—		—
Sales of reserves in place		(205	)		—		(205	)
Extensions and discoveries		386			—		386
Total proved reserves at December 31, 2011		22,689			—		22,689

Total proved developed reserves as of :
December 31, 2008		12,809			—		12,809
December 31, 2009		14,850			—		14,850
December 31, 2010		11,796			—		11,796
December 31, 2011		12,754			—		12,754


(1)	Includes an approximate 1.8 MMBbls decrease 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 of our producing fields, most notably our Bushwood field at Garden Banks Blocks 462/463/506/507, as well as changes in the field economics of some of our other oil and gas properties. The changes in field economics primarily affected properties that were either close to the end of their production life or in which we had proved undeveloped reserves, which would have been required to be developed in the near term. The decision not to develop these properties in light of these economic changes was also driven by our desire to pursue potential alternatives to divest 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 oil spill from the Macondo well.

(2)	The positive revision reflects the better than expected production volumes primarily from our Phoenix field at Green Canyon Blocks 236, 237, 238 and 282 since it began production in October 2010.

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


	United States			United(1)Kingdom			Total

Total proved reserves at December 31, 2008		460,456			12,950			473,406
Revision of previous estimates (2)		(44,615	)		(755	)		(45,370	)
Production		(27,139	)		(195	)		(27,334	)
Purchases of reserves in place		—			—			—
Sales of reserves in place		(7,933	)		—			(7,933	)
Extensions and discoveries		6,546			—			6,546
Total proved reserves at December 31, 2009		387,315			12,000			399,315
Revision of previous estimates (3)		(132,954	)		(12,000	)		(144,954	)
Production		(27,097	)		—			(27,097	)
Purchases of reserves in place		—			—			—
Sales of reserves in place		—			—			—
Extensions and discoveries		—			—			—
Total proved reserves at December 31, 2010		227,264			—			227,264
Revision of previous estimates(4)		(108,947	)		—			(108,947	)
Production		(17,458	)		—			(17,458	)
Purchases of reserves in place		—			—			—
Sales of reserves in place		(4,109	)		—			(4,109	)
Extensions and discoveries		271			—			271
Total proved reserves at December 31, 2011		97,021			—			97,021

Total proved developed reserves as of :
December 31, 2008		256,794			950			257,744
December 31, 2009		124,763			—			124,763
December 31, 2010		75,664			—			75,664
December 31, 2011		59,859			—			59,859

(1)	Reflects 50% ownership in the Camelot field's reserves in 2009 and 2008. In February 2010 we acquired the other 50% ownership interest in the Camelot field. We no longer have any development plans for the field and we intend to fully abandon the field in 2012 in accordance with the applicable regulations in the United Kingdom. See Note 5 for additional information regarding our Camelot field.

(2)	Includes a 38 Bcfe reduction of the proved reserves at Bushwood field reflecting certain reservoir issues for our Noonan Gas wells subsequent to their reestablishing sustained production in January 2009 and new geologic data collected throughout 2009.

(3)	Includes an approximate 131 Bcf decrease 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 of our producing fields, most notably our Bushwood field at Garden Banks Blocks 462/463/506/507, as well as changes in the field economics of some of our other oil and gas properties. The changes in field economics primarily affected properties that were either close to the end of their production life or in which we had proved undeveloped reserves, which would have been required to be developed in the near term. The decision not to develop these properties in light of these economic changes was also driven by our desire to pursue potential alternatives to divest 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 oil spill from the Macondo well.

(4)	Decrease primarily represents a reclassification of estimate 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 our Bushwood field, where we reclassified approximately 87 Bcf at December 31, 2011.

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 States			United(1)Kingdom			Total

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	)
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	)
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

As of December 31, 2009—
Future cash inflows	$	3,166,306		$	60,840		$	3,227,146
Future costs:
Production		(618,391	)		(19,075	)		(637,466	)
Development and abandonment		(755,726	)		(33,807	)		(789,533	)
Future net cash flows before income taxes		1,792,189			7,958			1,800,147
Future income tax expense		(417,042	)		(1,560	)		(418,602	)
Future net cash flows		1,375,147			6,398			1,381,545
Discount at 10% annual rate		(387,036	)		(3,449	)		(390,485	)
Standardized measure of discounted future net cash flows	$	988,111		$	2,949		$	991,060

(1)	Reflects 50% ownership in the Camelot field's reserves in 2009. In February 2010 we acquired the other 50% ownership interest in the Camelot field (Note 5).

Future cash inflows are computed by applying the appropriate average twelve 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:


	United States		United Kingdom		Total

Year Ended December 31, 2011—
Oil price per Bbl	$	105.35	$	—	$	105.35
Natural gas prices per Mcf	$	4.34	$	—	$	4.34

Year Ended December 31, 2010—
Oil price per Bbl	$	77.55	$	—	$	77.55
Natural gas prices per Mcf	$	4.40	$	—	$	4.40

Year Ended December 31, 2009—
Oil price per Bbl	$	58.05	$	—	$	58.05
Natural gas prices per Mcf	$	3.72	$	5.07	$	3.76

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,
		2011			2010			2009

Standardized measure, beginning of year	$	991,067		$	991,060		$	1,312,155
Changes during the year:
Sales, net of production costs		(516,895	)		(294,212	)		(265,501	)
Net change in prices and production costs		414,426			577,687			(245,883	)
Changes in future development costs		(108,007	)		84,907			(16,905	)
Development costs incurred		168,005			55,646			74,133
Accretion of discount		131,464			129,083			161,254
Net change in income taxes		(54,613	)		(41,115	)		257,919
Purchases of reserves in place		—			—			—
Extensions and discoveries		29,479			—			10,457
Sales of reserves in place		(14,324	)		—			(30,124	)
Net change due to revision in quantity estimates		(186,197	)		(422,987	)		(85,450	)
Changes in production rates (timing) and other		208,727			(89,002	)		(180,995	)
Total		72,065			7			(321,095	)
Standardized measure, end of year	$	1,063,132		$	991,067		$	991,060

Derivative Instruments And Hedging Activities

12 Months Ended

Dec. 31, 2011

Derivative Instruments And Hedging Activities [Abstract]

Derivative Instruments And Hedging Activities

Note 20 — Derivative Instruments and Hedging Activities

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


	As of December 31, 2011			As of December 31, 2010
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value

Asset Derivatives:
Natural gas contracts	Other current assets	$	12,957	Other current assets	$	5,324
Oil contracts	Other current assets		8,567	Other current assets		—
Natural gas contracts	Other assets		857	Other assets		—
Interest rate swaps	Other assets		327	Other assets		—
		$	22,708		$	5,324


	As of December 31, 2011			As of December 31, 2010
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value

Liability Derivatives:
Oil contracts	Accrued liabilities	$	886	Accrued liabilities	$	28,855
Interest rate swaps	Accrued liabilities		202	Accrued liabilities		1,751
Gas contracts	Other long-term liabilities		—	Other long-term liabilities		913
Oil contracts	Other long-term liabilities		1,711	Other long-term liabilities		—
Interest rate swaps	Other long-term liabilities		—	Other long-term liabilities		115
		$	2,799		$	31,634

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


	As of December 31, 2011			As of December 31, 2010
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value

Asset Derivatives:
Foreign exchange forwards	Other current assets	$	55	Other current assets	$	148
Foreign exchange forwards	Other assets		—	Other assets		42
		$	55		$	190


	As of December 31, 2011			As of December 31, 2010
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value

Liability Derivatives:
Foreign exchange forwards	Accrued liabilities	$	159	Accrued liabilities	$	—
		$	159		$	—

The following tables present the impact that derivative instruments designated as cash flow hedges had on our consolidated statement of operations for the years ended December 31, 2011, 2010 and 2009 (in thousands):


	Gain (Loss) Recognized in OCI on Derivatives
		2011(1)		2010			2009

Oil and natural gas commodity contracts	$	28,749	$	(6,486	)	$	(19,092	)
Foreign exchange forwards		—		—			(538	)
Interest rate swaps		1,294		(1,213	)		712
	$	30,043	$	(7,699	)	$	(18,918	)

(1)

All unrealized gains (losses) related to our derivatives are expected to be reclassified into earnings by no later than December 31, 2014. The last of our interest rate swaps will be settled in January 2014. The last of our oil and natural gas commodity contracts will settle in December 2013. Most of our unrealized gain (losses) in OCI at December 31, 2011 is expected to be reclassified to earnings in 2012, including $13.4 million for our oil and natural gas contracts and $(0.1) million related to our interest swap contracts.


	Location of Gain (Loss) Reclassified from Accumulated OCI into Income		Gain (Loss) Reclassified from Accumulated OCI into Income
			Years Ended December 31,
			2011			2010			2009

Oil and natural gas commodity contracts	Oil and Gas Revenues	$	(21,659	)	$	25,575		$	16,972
Interest rate swaps	Net interest expense		(2,010	)		(1,849	)		(1,096	)
		$	(23,669	)	$	23,726		$	15,876

The following tables present the impact that derivative instruments not designated as hedges had on our consolidated statement of operations for the years ended December 31, 2011, 2010 and 2009 (in thousands):


	Location of Gain (Loss) Recognized in Income on Derivatives		Gain (Loss) Recognized in Income on Derivatives
			Years Ended December 31,
			2011		2010			2009

Natural gas contracts	Gain on oil and gas derivative contracts	$	—	$	1,088		$	89,485
Foreign exchange forwards	Other income (expense)		249		(2,560	)		3,279
Interest rate swaps	Other income (expense)		—		—			(468	)
		$	249	$	(1,472	)	$	92,296

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.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Statement of Financial Accounting Standard (FAS)
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-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.

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Quarterly Financial Information [Abstract]

Quarterly Financial Information

12 Months Ended

Dec. 31, 2011

Quarterly Financial Information

Note 21 — 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 2010 and 2009 (in thousands, except per share data):


		Quarter Ended
		March 31,			June 30,			September 30,		December 31,

2011
Net revenues	$	291,607		$	338,319		$	372,496	$	396,185
Gross profit (1)		77,076			100,198			122,295		31,023
Net income (2)		25,867			41,323			46,026		16,763
Net income applicable to common shareholders		25,857			41,313			46,016		16,753
Basic earnings per common share		0.24			0.39			0.43		0.16
Diluted earnings per common share		0.24			0.39			0.43		0.16

		Quarter Ended
		March 31,			June 30,			September 30,		December 31,

2010
Net revenues	$	201,570		$	299,262		$	392,669	$	306,337
Gross profit (loss) (3)		25,856			(94,818	)		86,552		16,082
Net income (loss) (4)		(17,831	)		(85,517	)		26,171		(49,811	)
Net income (loss) applicable to common shareholders		(17,891	)		(85,551	)		26,161		(49,821	)
Basic earnings (loss) per common share		(0.17	)		(0.82	)		0.25		(0.48	)
Diluted earnings (loss) per common share		(0.17	)		(0.82	)		0.25		(0.48	)

(1)

Includes oil and gas property impairment charges totaling $22.7 million in the second quarter of 2011 and $2.4 million in the third quarter of 2011. Our fourth quarter of 2011 includes a total of $107.5 million of impairment charges, including $79.3 million related to eight oil and gas properties to reduce them to their estimated fair value at December 31, 2011 and $28.2 million to increase certain non-producing properties estimated asset retirement obligations, including $15.9 million related to our one U.K. oil and gas property (Note 5). The fourth quarter also includes a $6.6 million impairment charge to reduce our Australian well intervention equipment to is estimated fair value at December 31, 2011. There were no asset impairment charges in the first quarter of 2011.

(2)	Our fourth quarter 2011 includes a $10.6 million other than temporary impairment loss on our equity investment in our Australian joint venture (Note 7). The fourth quarter also includes a $31.3 million tax benefit related to reorganization of our Australian well intervention business.

(3)	Includes oil and gas property impairment charges totaled $11.1 in the first quarter of 2010, $159.9 million in the second quarter of 2010, $0.9 million in the third quarter of 2010 and $9.2 million in the fourth quarter of 2010.

(4)	Includes an impairment charges of $16.7 million to reduce goodwill associated with our Australia well intervention business in the fourth quarter of 2010 (Note 2).

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]

Subsequent Event	12 Months Ended
Subsequent Event	Dec. 31, 2011
Subsequent Event [Abstract]
Subsequent Event	Note 22 — Subsequent Event On February 21, 2012, we entered into an amendment to our Credit Agreement. Under terms of the amendment the participating lenders agree to loan us $100 million pursuant to a new term loan (Term Loan A). The terms of the new Term Loan A are the same as those regarding the Revolving Credit Facility, with the Term Loan A requiring a $5 million annual amortization of the principal balance. The Term Loan A will fund in March 2012. See Note 9 for additional information regarding our Credit Agreement and our Senior Unsecured Notes.

Condensed Consolidated Guarantor And Non-Guarantor Financial Information

12 Months Ended

Dec. 31, 2011

Condensed Consolidated Guarantor And Non-Guarantor Financial Information

Note 23 — Condensed Consolidated Guarantor and Non-Guarantor Financial Information

The payment of obligations under the Senior Unsecured Notes is guaranteed by all of our restricted domestic subsidiaries ("Subsidiary Guarantors") except for Cal Dive I-Title XI, Inc. Cal Dive and its subsidiaries were never guarantors of our Senior Unsecured Notes. Each of these Subsidiary Guarantors is included in our consolidated financial statements and has fully and unconditionally guaranteed the Senior Unsecured Notes on a joint and several basis. As a result of these guaranty arrangements, we are required to present the following condensed consolidating financial information. The accompanying guarantor financial information is presented on the equity method of accounting for all periods presented. Under this method, investments in subsidiaries are recorded at cost and adjusted for our share in the subsidiaries' cumulative results of operations, capital contributions and distributions and other changes in equity. Elimination entries relate primarily to the elimination of investments in subsidiaries and associated intercompany balances and transactions.

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(in thousands)


	As of December 31, 2011
		Helix			Guarantors		Non-Guarantors			Consolidating Entries			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	495,484		$	2,434	$	48,547		$	—		$	546,465
Accounts receivable, net		79,290			117,767		41,724			—			238,781
Unbilled revenue		10,530			155		26,690			—			37,375
Income taxes receivable		80,388			—		—			(80,388	)		—
Other current assets		68,627			48,661		10,159			(5,826	)		121,621
Total current assets		734,319			169,017		127,120			(86,214	)		944,242
Intercompany		(147,187	)		315,821		(102,826	)		(65,808	)		—
Property and equipment, net		230,946			1,422,326		682,899			(4,844	)		2,331,327
Other assets:
Equity investments in unconsolidated affiliates		—			—		175,656			—			175,656
Equity investments in affiliates		1,952,392			37,239		—			(1,989,631	)		—
Goodwill, net		—			45,107		17,108			—			62,215
Other assets, net		53,425			36,453		16,809			(37,780	)		68,907
Due from subsidiaries/parent		64,655			430,496		—			(495,151	)		—
	$	2,888,550		$	2,456,459	$	916,766		$	(2,679,428	)	$	3,582,347

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	39,280		$	82,750	$	25,013		$	—		$	147,043
Accrued liabilities		115,921			97,692		26,350			—			239,963
Income taxes payable		—			97,692		217			(96,616	)		1,293
Current maturities of long-term debt		3,000			—		10,377			(5,500	)		7,877
Total current liabilities		158,201			278,134		61,957			(102,116	)		396,176
Long-term debt		1,042,155			—		105,289			—			1,147,444
Deferred income taxes		231,255			88,625		103,552			(5,822	)		417,610
Asset retirement obligations		—			161,208		—			—			161,208
Other long-term liabilities		4,150			4,647		571			—			9,368
Due to parent		—			—		98,285			(98,285	)		—
Total liabilities		1,435,761			532,614		369,654			(206,223	)		2,131,806
Convertible preferred stock		1,000			—		—			—			1,000
Total equity		1,451,789			1,923,845		547,112			(2,473,205	)		1,449,541
	$	2,888,550		$	2,456,459	$	916,766		$	(2,679,428	)	$	3,582,347

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(in thousands)


	As of December 31, 2010
		Helix		Guarantors		Non-Guarantors			Consolidating Entries			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	376,434	$	3,294	$	11,357		$	—		$	391,085
Accounts receivable, net		61,846		91,659		23,788			—			177,293
Unbilled revenue		11,990		—		37,421			—			49,411
Income taxes receivable		19,334		—		7,195			(20,430	)		6,099
Other current assets		63,306		49,557		12,889			(8,786	)		116,966
Total current assets		532,910		144,510		92,650			(29,216	)		740,854
Intercompany		1,906		263,920		(171,513	)		(94,313	)		—
Property and equipment, net		217,153		1,605,906		709,082			(5,061	)		2,527,080
Other assets:
Equity investments in unconsolidated affiliates		—		—		187,031			—			187,031
Equity investments in affiliates		1,998,289		29,899		—			(2,028,188	)		—
Goodwill, net		—		45,107		17,387			—			62,494
Other assets, net		43,971		38,324		21,900			(29,634	)		74,561
Due from subsidiaries/parent		95,398		105,434		—			(200,832	)		—
	$	2,889,627	$	2,233,100	$	856,537		$	(2,387,244	)	$	3,592,020

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	60,308	$	56,107	$	42,966		$	—		$	159,381
Accrued liabilities		58,074		107,874		32,289			—			198,237
Income taxes payable		—		36,678		—			(36,678	)		—
Current maturities of long-term debt		4,326		—		14,301			(8,448	)		10,179
Total current liabilities		122,708		200,659		89,556			(45,126	)		367,797
Long-term debt		1,237,587		—		110,166			—			1,347,753
Deferred income taxes		185,453		135,101		98,968			(5,883	)		413,639
Assets retirement obligations		—		170,410		—			—			170,410
Other long-term liabilities		1,421		3,691		665			—			5,777
Due to parent		—		—		120,884			(120,884	)		—
Total liabilities		1,547,169		509,861		420,239			(171,893	)		2,305,376
Convertible preferred stock		1,000		—		—			—			1,000
Total equity		1,341,458		1,723,239		436,298			(2,215,351	)		1,285,644
	$	2,889,627	$	2,233,100	$	856,537		$	(2,387,244	)	$	3,592,020

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(in thousands)


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

Net revenues		$	84,748		$	1,059,255		$	367,114		$	(112,510	)	$	1,398,607
Cost of sales			72,902			673,415			289,462			(111,281	)		924,498
Oil and gas impairments			—			112,636			19,967			—			132,603
Exploration expense			—			10,914			—			—			10,914
Gross profit (loss)			11,846			262,290			57,685			(1,229	)		330,592
Gain on sale of assets, net			(6	)		4,531			—			—			4,525
Selling, general and administrative expenses			(74,205	)		(38,915	)		12,101			1,430			(99,589	)
Loss from operations			(62,365	)		227,906			69,786			201			235,528
Equity in earnings of unconsolidated affiliates			—			—			22,215			—			22,215
Equity in earnings (losses) of affiliates			262,990			7,340			—			(270,330	)		—
Gain on investment in Cal Dive common stock			753			—			—			—			753
Other than temporary loss on equity investments			—			—			(10,563	)		—			(10,563	)
Net interest expense and other			(158,299	)		(32,345	)		67,181			23,510			(99,953	)
Income before income taxes			43,079			202,901			148,619			(246,619	)		147,980
(Benefit) provision for income taxes			(63,242	)		69,890			8,186			69			14,903
Net income (loss), including noncontrolling interests			106,321			133,011			140,433			(246,688	)		133,077
Net income applicable to noncontrolling interests			—			—			—			(3,098	)		(3,098	)
Net income (loss) applicable to Helix			106,321			133,011			140,433			(249,786	)		129,979
Preferred stock dividends			(40	)		—			—			—			(40	)
Net income (loss) applicable to Helix common shareholders		$	106,281		$	133,011		$	140,433		$	(249,786	)	$	129,939


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

Net revenues		$	183,147		$	801,503		$	334,726		$	(119,538	)	$	1,199,838
Cost of sales			124,722			659,859			297,056			(104,830	)		976,807
Oil and gas impairments			—			176,088			4,995			—			181,083
Exploration expense			—			8,276			—			—			8,276
Gross profit (loss)			58,425			(42,720	)		32,675			(14,708	)		33,672
Goodwill impairment			—			—			(16,743	)		—			(16,743	)
Gain on oil and gas derivative commodity contracts			—			1,088			—			—			1,088
Gain on sale of assets, net			3,159			287			5,959			—			9,405
Selling, general and administrative expenses			(67,165	)		(34,233	)		(22,482	)		1,802			(122,078	)
Loss from operations			(5,581	)		(75,578	)		(591	)		(12,906	)		(94,656	)
Equity in earnings of unconsolidated affiliates			—			—			19,469			—			19,469
Equity in earnings (losses) of affiliates			(60,443	)		8,473			—			51,970			—
Other than temporary loss on equity investments			(2,240	)		—			—			—			(2,240	)
Net interest expense and other			(59,522	)		(21,677	)		(5,125	)		—			(86,324	)
Income before income taxes			(127,786	)		(88,782	)		13,753			39,064			(163,751	)
(Benefit) provision for income taxes			(9,175	)		(35,299	)		9,405			(4,529	)		(39,598	)
Net income (loss), including noncontrolling interests			(118,611	)		(53,483	)		4,348			43,593			(124,153	)
Net income applicable to noncontrolling interests			—			—			—			(2,835	)		(2,835	)
Net income (loss) applicable to Helix			(118,611	)		(53,483	)		4,348			40,758			(126,988	)
Preferred stock dividends			(114	)		—			—			—			(114	)
Net income (loss) applicable to Helix common shareholders		$	(118,725	)	$	(53,483	)	$	4,348		$	40,758		$	(127,102	)

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(in thousands)


	Year Ended December 31, 2009
			Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated
Net revenues	$	211,222			$	701,706		$	648,705		$	(99,946	)	$	1,461,687
Cost of sales		162,225				484,802			521,689			(95,124	)		1,073,592
Oil and gas impairments		—				120,550			—			—			120,550
Exploration expense		—				24,383			—			—			24,383
Gross profit (loss)		48,997				71,971			127,016			(4,822	)		243,162
Gain on oil and gas derivative commodity contracts		—				89,485			—			—			89,485
Gain on sale of assets, net		—				2,019			—			—			2,019
Selling, general and administrative expenses		(52,101		)		(28,520	)		(53,919	)		3,689			(130,851	)
Income (loss) from operations		(3,104		)		134,955			73,097			(1,133	)		203,815
Equity in earnings of unconsolidated affiliates		—				—			33,229			(900	)		32,329
Equity in earnings (losses) of affiliates		145,340				(1,725	)		—			(143,615	)		—
Gain on investment in of Cal Dive common stock		77,343				—			—			—			77,343
Net interest expense and other		(18,188		)		(16,978	)		(15,341	)		(988	)		(51,495	)
Income before income taxes		201,391				116,252			90,985			(146,636	)		261,992
(Benefit) provision for income taxes		43,417				39,855			13,571			(1,021	)		95,822
Income (loss) from continuing operations		157,974				76,397			77,414			(145,615	)		166,170
Discontinued operations, net of tax		99				—			9,482			—			9,581
Net income (loss), including noncontrolling interests		158,073				76,397			86,896			(145,615	)		175,751
Net income applicable to noncontrolling interests		—				—			—			(19,697	)		(19,697	)
Net income (loss) applicable to Helix		158,073				76,397			86,896			(165,312	)		156,054
Preferred stock dividends		(54,187		)		—			—			—			(54,187	)
Net income (loss) applicable to Helix common shareholders	$	103,886			$	76,397		$	86,896		$	(165,312	)	$	101,867

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS


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

	(in thousands)

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) to net cash provided by (used in) operating activities:
Equity in earnings of affiliates		(262,990	)		(7,340	)		—			270,330			—
Other adjustments		39,860			353,728			40,293			198			434,079
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	)		(174,739	)		(12,613	)		—			(219,769	)
Investments in equity investments		—			—			(2,699	)		—			(2,699	)
Distributions from equity investments, net		—			—			3,965			—			3,965
Proceeds from sale of Cal Dive common stock		3,588			—			—			—			3,588
Other, net		—			32,598			—			—			32,598
Net cash used in investing activities		(28,829	)		(142,141	)		(11,347	)		—			(182,317	)

Cash flows from financing activities:
Borrowings on revolvers		109,400			—			—			—			109,400
Repayments on revolvers		(109,400	)		—			—			—			(109,400	)
Repayments of debt		(208,085	)		—			(4,645	)		—			(212,730	)
Loan notes repayment		—			—			(1,215	)		—			(1,215	)
Deferred financing costs		(9,311	)		—			—			—			(9,311	)
Preferred stock dividends paid		(40	)		—			—			—			(40	)
Repurchase of common stock		(7,604	)		—			—			—			(7,604	)
Excess tax benefit from stock-based compensation		(1,013	)		—			—			—			(1,013	)
Exercise of stock options, net		2,018			—			—			—			2,018
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 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

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS


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

	(in thousands)

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) to net cash provided by (used in) operating activities:
Equity in earnings of affiliates		60,443			(8,473	)		—			(51,970	)		—
Other adjustments		94,376			305,649			76,865			(21,283	)		455,607
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	)		(121,709	)		(28,413	)		—			(206,772	)
Investments in equity investments		—			—			(8,253	)		—			(8,253	)
Distributions from equity investments, net		—			—			10,539			—			10,539
Proceeds from insurance reimbursement		7,020			9,086			—			—			16,106
Proceeds from sale of Cal Dive common stock		—			—			—			—			—
Proceeds from sales of property		6,042			852			—			—			6,894
Increases in restricted cash		—			(70	)		—			—			(70	)
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	)
Loan notes repayment		—			—			(2,517	)		—			(2,517	)
Deferred financing costs		(2,947	)		—			—			—			(2,947	)
Preferred stock dividends paid		(114	)		—			—			—			(114	)
Repurchase of common stock		(11,680	)		—			—			—			(11,680	)
Excess tax benefit from stock-based compensation		(3,945	)		—			—			—			(3,945	)
Exercise of stock options, net		674			—			—			—			674
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

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS


		For the Year Ended December 31, 2009
		Helix			Guarantors			Non-Guarantors			Consolidating Entries		Consolidated

		(in thousands)

Cash flows from operating activities:
Net income (loss), including noncontrolling interests	$	158,073		$	76,397		$	86,896		$	(145,615	$	175,751
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Equity in earnings of unconsolidated affiliates		—			—			(7,220	)		899		(6,321	)
Equity in earnings of affiliates		(145,340	)		1,725			—			143,615		—
Other adjustments		26,633			163,451			82,411			(17,987		254,508
Net cash provided by (used in) operating activities		39,366			241,573			162,087			(19,088		423,938
Net cash used in discontinued operations		—			—			(6,261	)		—		(6,261	)
Net cash provided by (used in) operating activities		39,366			241,573			155,826			(19,088		417,677

Cash flows from investing activities:
Capital expenditures		(35,657	)		(245,354	)		(142,362	)		—		(423,373	)
Acquisition of businesses, net of cash acquired		—			—			—			—		—
Investments in equity investments		—			—			(1,657	)		—		(1,657	)
Distributions from equity investments, net		—			—			6,742			—		6,742
Increases in restricted cash		—			(6	)		—			—		(6	)
Proceeds from sale of Cal Dive common stock		504,168			—			(112,995	)		(86,000		305,173
Proceeds from sales of property		—			23,717			—			—		23,717
Net cash provided by (used in) investing activities		468,511			(221,643	)		(250,272	)		(86,000		(89,404	)
Net cash provided by discontinued operations		—			—			20,872			—		20,872
Net cash provided by (used in) investing activities		468,511			(221,643	)		(229,400	)		(86,000		(68,532	)

Cash flows from financing activities:
Borrowings on revolvers		—			—			100,000			—		100,000
Repayments on revolvers		(349,500	)		—			—			—		(349,500	)
Repayments of debt		(4,326	)		—			(24,214	)		—		(28,540	)
Loan notes repayment		—			—			(2,130	)		—		(2,130	)
Deferred financing costs		(6,970	)		—			—			—		(6,970	)
Preferred stock dividends paid		(645	)		—			—			—		(645	)
Repurchase of common stock		(13,995	)		—			(86,000	)		86,000		(13,995	)
Excess tax benefit from stock-based compensation		895			—			—			—		895
Exercise of stock options, net		176			—			—			—		176
Intercompany financing		(23,474	)		(22,391	)		26,777			19,088		—
Net cash provided by (used in) financing activities		(397,839	)		(22,391	)		14,433			105,088		(300,709	)
Effect of exchange rate changes on cash and cash equivalents		—			—			(1,376	)		—		(1,376	)
Net increase (decrease) in cash and cash equivalents		110,038			(2,461	)		(60,517	)		—		47,060
Cash and cash equivalents:
Balance, beginning of year		148,704			4,983			69,926			—		223,613
Balance, end of year	$	258,742		$	2,522		$	9,409		$	—	$	270,673

Summary Of Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2011

Summary Of Significant Accounting Policies [Abstract]

Principles Of Consolidation

Principles of Consolidation

Use Of Estimates

Use of Estimates

Cash And Cash Equivalents

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,
		2011		2010		2009

Interest paid, net of interest capitalized	$	81,000	$	68,534	$	48,313
Income taxes paid	$	11,216	$	10,071	$	106,480

Accounts Receivable And Allowance For Uncollectible Accounts

<div class="MetaData"> <div style="text-indent: 0pt; display: block; margin-left: 9pt; margin-right: 0pt;" align="justify"><font style="font-style: italic; display: inline; font-family: Arial; font-size: 14pt; font-weight: bold;" class="_mt">Accounts Receivable and Allowance for Uncollectible Accounts</font></div> <div style="text-indent: 0pt; display: block;"> </div> <div style="text-indent: 36pt; display: block; margin-left: 0pt; margin-right: 0pt;" align="left"><font style="display: inline; font-family: Arial; font-size: 14pt;" class="_mt">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 18).</font></div></div>

Inventories

Property And Equipment

Property and Equipment

Overview. Property and equipment is recorded at cost. The following is a summary of the gross components of property and equipment (dollars in thousands):

	Estimated Useful Life		2011		2010

ROVs/Vessels	10to 30 years	$	1,616,772	$	1,573,471
Oil and gas leases and related equipment	Units-of-Production		2,574,693		2,747,895
Machinery, equipment, buildings and leasehold improvements	5to 30 years		199,599		164,711
Total property and equipment		$	4,391,064	$	4,486,077

Equity Investments

Goodwill And Other Intangible Assets

Goodwill and Other Intangible Assets

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


	Contracting Services

Balance at December 31, 2009 (1)	$	78,643
Impairments (2)		(16,743	)
Other adjustments(3)		594
Balance at December 31, 2010		62,494
Impairments		—
Other adjustments(3)		(279	)
Balance at December 31, 2011	$	62,215

(1)	Prior to 2009, we fully impaired our oil and gas related goodwill ($704.3 million) as well as the $8.3 million of goodwill associated with our former reservoir consulting business.

(2)	Amount reflects full write off of goodwill associated with our WOSEA operations.

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

Recertification Costs And Deferred Drydock Charges

Recertification Costs and Deferred Drydock Charges

Accounting For Asset Retirement Obligations

Accounting for Asset Retirement Obligations

The following table describes the changes in our asset retirement obligations (both long term and current) for the years ended December 31, 2011 and 2010 (in thousands):

		2011			2010

Asset retirement obligations at January 1,	$	234,936		$	248,128
Liability incurred during the period		4,982			18,056
Liability settled during the period		(42,675	)		(55,114	)
Other revisions in estimated cash flows		42,268	(1)		8,349
Accretion expense (included in depreciation and amortization)		14,880			15,517
Asset retirement obligations at December 31,	$	254,391		$	234,936

(1)	Includes impairment charges totaling $41.7 million, including $20.0 million associated with our only United Kingdom oil and gas property, to increase the estimated asset retirement obligation related to properties that are no longer producing oil or natural gas.

Revenue Recognition

Contracting Services Revenues

•		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.

Oil and Gas Revenues

Income Taxes

Foreign Currency

Derivative Instruments And Hedging Activities

Derivative Instruments and Hedging Activities

Commodity Price Risks

Production Period	Instrument Type	Average Monthly Volumes	Weighted Average Price a
Crude Oil:			(per barrel)
January 2012 — December 2012	Collar	75.0 MBbl	$ 96.67 — $118.57b
January 2012 — December 2012	Collar	139.0 MBbl	$ 99.42 — $117.59
January 2012 — December 2012	Swap	16.0 MBbl	$103.20
January 2013 — December 2013	Swap	41.7 MBbl	$99.15
January 2013 — December 2013	Collar	41.7 MBbl	$ 95.00 — $102.60

Natural Gas:			(per Mcf)
January 2012 — December 2012	Swaps	750.0 Mmcf	$4.35
January 2012 — December 2012	Collar	166.7 Mmcf	$4.75 — $5.09
January 2013 — December 2013	Swaps	500.0 Mmcf	$4.09

a.	The prices quoted in the table above are NYMEX Henry Hub for natural gas. For oil most of the contracts are priced as Brent crude oil.

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

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

Variable Interest Rate Risks

Foreign Currency Exchange Risks

Earnings Per Share


		Year Ended December 31,
		2011				2010				2009
		Income		Shares		Income		Shares		Income		Shares
Basic:
Net income (loss) applicable to common shareholders	$	129,939			$	(127,102	)		$	101,867
Less: Undistributed net income allocable to participating securities		(1,599	)			—				(1,436	)
Undistributed net income (loss) applicable to common shareholders		128,340				(127,102	)			100,431
(Income) loss from discontinued operations		—				—				(9,581	)
Add: Undiscounted net income from discontinued operations allocable to participating securities		—				—				135
Income (loss) per common share – continuing operations	$	128,340		104,528	$	(127,102	)	103,857	$	90,985		99,136


		Year Ended December 31,
		2011			2010				2009
		Income	Shares		Income		Shares		Income	Shares
Diluted:
Net income (loss) per common share – continuing operations – Basic	$	128,340	104,528	$	(127,102	)	103,857	$	90,985	99,136
Effect of dilutive securities:
Stock options		—	64		—		—		—	28
Undistributed earnings reallocated to participating securities		7	—		—		—		80	—
Convertible Senior Notes		—	—		—		—		—	—
Convertible preferred stock		40	361		—		—		748	6,556
Income (loss) per common share — continuing operations		128,387			(127,102	)			91,813
Income (loss) per common share — discontinued operations		—			—				9,581
Net income (loss) per common share	$	128,387	104,953	$	(127,102	)	103,857	$	101,394	105,720


	2010
Diluted shares (as reported)		103,857
Stock options		54
Convertible preferred stock		1,015
Total		104,926

There were no dilutive shares associated with our 3.25% Convertible Senior Notes as the conversion price of $32.14 was not met in any of the years ended December 31, 2011, 2010 and 2009 (Note 9).

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 noted. The valuation techniques are 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 value 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 and gas swaps and collars	$	–	$	22,381	$	–	$	22,381	(c)
Interest rate swaps		–		327		–		327	(c)
Foreign currency forwards		–		55		–		55	(c)

Liabilities:
Oil and gas swaps and collars		–		2,597		–		2,597	(c)
Interest rate swaps		–		202		–		202	(c)
Foreign currency forwards		–		159		–		159	(c)
Fair value of long term debt (2)		1,081,376		124,488		–		1,205,864	(a)
Total net liability	$	1,081,376	$	104,683	$	–	$	1,186,059

(1)

(2)	See Note 9 for additional information regarding our long term debt.

The fair value of our debt at December 31, 2011 and December 31, 2010 is as follows:


	2011				2010
	Carrying Value		Fair Value		Carrying Value		Fair Value

Term Loan(1)	$	279,750	$	279,750	$	410,441	$	406,337
Revolving Credit Facility	—		—		—		—
Convertible Senior Notes(1) (2)		300,000		300,543		300,000		289,158
Senior Unsecured Notes(1)		474,960		501,083		550,000		567,875
MARAD Debt(3)		110,166		124,488		114,811		122,159
Loan Notes	—		—			1,208		1,208
Total	$	1,164,876	$	1,205,864	$	1,376,460	$	1,386,737

(1)	The fair values of these instruments were based on quoted market prices as of December 31, 2011 and 2010. The fair values were estimated using level 1 inputs using the market approach.
(2)	Carrying amounts exclude the $9.6 million and $18.5 million of unamortized discount on the Convertible Senior Notes at December 31, 2011 and 2010, respectively.
(3)	The fair value of the MARAD debt was determined by a third-party evaluation of the remaining average life and outstanding principal balance of the MARAD indebtedness as compared to other government guaranteed obligations in the market place with similar terms. The fair value of the MARAD debt was estimated using Level 2 fair value inputs using the market approach.

Debt Discount

Summary Of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2011

Summary Of Significant Accounting Policies [Abstract]

Supplemental Cash Flow Information


		Year Ended December 31,
		2011		2010		2009

Interest paid, net of interest capitalized	$	81,000	$	68,534	$	48,313
Income taxes paid	$	11,216	$	10,071	$	106,480

Summary Of Gross Components Of Property And Equipment

	Estimated Useful Life		2011		2010

ROVs/Vessels	10to 30 years	$	1,616,772	$	1,573,471
Oil and gas leases and related equipment	Units-of-Production		2,574,693		2,747,895
Machinery, equipment, buildings and leasehold improvements	5to 30 years		199,599		164,711
Total property and equipment		$	4,391,064	$	4,486,077

Summary Of Changes In The Carrying Amount Of Goodwill


	Contracting Services

Balance at December 31, 2009 (1)	$	78,643
Impairments (2)		(16,743	)
Other adjustments(3)		594
Balance at December 31, 2010		62,494
Impairments		—
Other adjustments(3)		(279	)
Balance at December 31, 2011	$	62,215

(1)	Prior to 2009, we fully impaired our oil and gas related goodwill ($704.3 million) as well as the $8.3 million of goodwill associated with our former reservoir consulting business.

(2)	Amount reflects full write off of goodwill associated with our WOSEA operations.

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

Schedule Of Changes In Asset Retirement Obligations

		2011			2010

Asset retirement obligations at January 1,	$	234,936		$	248,128
Liability incurred during the period		4,982			18,056
Liability settled during the period		(42,675	)		(55,114	)
Other revisions in estimated cash flows		42,268	(1)		8,349
Accretion expense (included in depreciation and amortization)		14,880			15,517
Asset retirement obligations at December 31,	$	254,391		$	234,936

(1)	Includes impairment charges totaling $41.7 million, including $20.0 million associated with our only United Kingdom oil and gas property, to increase the estimated asset retirement obligation related to properties that are no longer producing oil or natural gas.

Summary Of Volumes Under Derivatives And Forward Sales Contracts

Production Period	Instrument Type	Average Monthly Volumes	Weighted Average Price a
Crude Oil:			(per barrel)
January 2012 — December 2012	Collar	75.0 MBbl	$ 96.67 — $118.57b
January 2012 — December 2012	Collar	139.0 MBbl	$ 99.42 — $117.59
January 2012 — December 2012	Swap	16.0 MBbl	$103.20
January 2013 — December 2013	Swap	41.7 MBbl	$99.15
January 2013 — December 2013	Collar	41.7 MBbl	$ 95.00 — $102.60

Natural Gas:			(per Mcf)
January 2012 — December 2012	Swaps	750.0 Mmcf	$4.35
January 2012 — December 2012	Collar	166.7 Mmcf	$4.75 — $5.09
January 2013 — December 2013	Swaps	500.0 Mmcf	$4.09

a.	The prices quoted in the table above are NYMEX Henry Hub for natural gas. For oil most of the contracts are priced as Brent crude oil.

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

Computations Of Basic And Diluted EPS


		Year Ended December 31,
		2011				2010				2009
		Income		Shares		Income		Shares		Income		Shares
Basic:
Net income (loss) applicable to common shareholders	$	129,939			$	(127,102	)		$	101,867
Less: Undistributed net income allocable to participating securities		(1,599	)			—				(1,436	)
Undistributed net income (loss) applicable to common shareholders		128,340				(127,102	)			100,431
(Income) loss from discontinued operations		—				—				(9,581	)
Add: Undiscounted net income from discontinued operations allocable to participating securities		—				—				135
Income (loss) per common share – continuing operations	$	128,340		104,528	$	(127,102	)	103,857	$	90,985		99,136


		Year Ended December 31,
		2011			2010				2009
		Income	Shares		Income		Shares		Income	Shares
Diluted:
Net income (loss) per common share – continuing operations – Basic	$	128,340	104,528	$	(127,102	)	103,857	$	90,985	99,136
Effect of dilutive securities:
Stock options		—	64		—		—		—	28
Undistributed earnings reallocated to participating securities		7	—		—		—		80	—
Convertible Senior Notes		—	—		—		—		—	—
Convertible preferred stock		40	361		—		—		748	6,556
Income (loss) per common share — continuing operations		128,387			(127,102	)			91,813
Income (loss) per common share — discontinued operations		—			—				9,581
Net income (loss) per common share	$	128,387	104,953	$	(127,102	)	103,857	$	101,394	105,720

Summary Of Shares Included In Diluted Per Share Calculations


	2010
Diluted shares (as reported)		103,857
Stock options		54
Convertible preferred stock		1,015
Total		104,926

Assets And Liabilities Measured At Fair Value On A Recurring Basis

		Level 1		Level 2 (1)		Level 3		Total	Valuation Technique
Assets:
Oil and gas swaps and collars	$	–	$	22,381	$	–	$	22,381	(c)
Interest rate swaps		–		327		–		327	(c)
Foreign currency forwards		–		55		–		55	(c)

Liabilities:
Oil and gas swaps and collars		–		2,597		–		2,597	(c)
Interest rate swaps		–		202		–		202	(c)
Foreign currency forwards		–		159		–		159	(c)
Fair value of long term debt (2)		1,081,376		124,488		–		1,205,864	(a)
Total net liability	$	1,081,376	$	104,683	$	–	$	1,186,059

(1)

(2)	See Note 9 for additional information regarding our long term debt.

Fair Value Of Long Term Debt


	2011				2010
	Carrying Value		Fair Value		Carrying Value		Fair Value

Term Loan(1)	$	279,750	$	279,750	$	410,441	$	406,337
Revolving Credit Facility	—		—		—		—
Convertible Senior Notes(1) (2)		300,000		300,543		300,000		289,158
Senior Unsecured Notes(1)		474,960		501,083		550,000		567,875
MARAD Debt(3)		110,166		124,488		114,811		122,159
Loan Notes	—		—			1,208		1,208
Total	$	1,164,876	$	1,205,864	$	1,376,460	$	1,386,737

(1)	The fair values of these instruments were based on quoted market prices as of December 31, 2011 and 2010. The fair values were estimated using level 1 inputs using the market approach.
(2)	Carrying amounts exclude the $9.6 million and $18.5 million of unamortized discount on the Convertible Senior Notes at December 31, 2011 and 2010, respectively.
(3)	The fair value of the MARAD debt was determined by a third-party evaluation of the remaining average life and outstanding principal balance of the MARAD indebtedness as compared to other government guaranteed obligations in the market place with similar terms. The fair value of the MARAD debt was estimated using Level 2 fair value inputs using the market approach.

Oil And Gas Properties (Tables)

12 Months Ended

Dec. 31, 2011

Oil And Gas Properties [Abstract]

Capitalized Exploratory Project Costs

		2011		2010
Wang (1)	$	3,096	$	3,095
Danny 2 (1)		2,619		32
Other		125		125
Total	$	5,840	$	3,252

(1)

Changes In Suspended Exploratory Well Costs

		2011		2010			2009

Beginning balance at January 1,	$	3,252	$	3,059		$	2,105
Additions pending the determination of proved reserves		2,513		(944	)		36,208
Reclassifications to proved properties		5		713			(34,622	)
Charged to dry hole expense		70		424			(632	)
Ending balance at December 31,	$	5,840	$	3,252		$	3,059

Components Of Exploration Expenses


		Years Ended December 31,
		2011			2010			2009

Delay rental and geological and geophysical costs	$	2,650		$	2,306		$	3,016
Impairment of unproved properties		8,334			6,394			20,130
Dry hole expense		(70	)		(424	)		1,237
Total exploration expense	$	10,914		$	8,276		$	24,383

Fair Value Of Assets Acquired And Liabilities Assumed

Cash	$	10,156
Deferred tax asset		2,083
Accrued liabilities		(439	)
Asset retirement obligation		(5,841	)
Gain on acquisition of assets	$	5,959

Details Of Certain Accounts (Tables)

12 Months Ended

Dec. 31, 2011

Details Of Certain Accounts [Abstract]

Other Current Assets

		2011		2010

Other receivables	$	5,096	$	1,247
Prepaid insurance		12,701		12,375
Other prepaids		13,271		11,623
Spare parts inventory		18,066		25,333
Current deferred tax assets		41,449		49,200
Hedging assets		21,579		5,472
Income tax receivable		—		6,099
Gas and oil imbalance		5,134		6,001
Other		4,325		5,715
	$	121,621	$	123,065

Other Assets, Net

		2011		2010

Restricted cash	$	33,741	$	35,339
Deferred drydock costs, net		5,381		11,086
Deferred financing costs, net		26,483		25,697
Intangible assets with finite lives		531		636
Other		2,771		1,803
	$	68,907	$	74,561

Accrued Liabilities

		2011		2010

Accrued payroll and related benefits	$	49,599	$	38,026
Royalties payable		19,391		15,008
Current asset retirement obligations		93,183		64,526
Unearned revenue		7,654		1,817
Billings in excess of costs		28,839		6,146
Accrued interest		24,028		27,308
Hedging liability		1,247		30,606
Gas and oil imbalance		4,177		770
Other		11,845		14,030
	$	239,963	$	198,237

Equity Investments (Tables)

12 Months Ended

Dec. 31, 2011

Equity Investments [Abstract]

Contributions To Equity Investments


		Year Ended December 31,
		2011		2010		2009

Clough Helix Pty Ltd. (see below)	$	2,699	$	8,253	$	—
Other		—		—		1,657
Total	$	2,699	$	8,253	$	1,657

Distributions From Equity Investments


		Year Ended December 31,
		2011		2010		2009

Deepwater Gateway	$	7,600	$	8,125	$	6,750
Independence Hub		18,580		21,615		26,000
Other		—		268		—
Total	$	26,180	$	30,008	$	32,750

Schedule Of Summarized Aggregated Financial Information Related To The Subsidiaries


		Year Ended December 31,
		2011		2010		2009

Revenues	$	193,521	$	141,705	$	141,664
Operating income		97,954		93,324		118,566
Net income		93,215		93,005		118,602


		At December 31,
		2011		2010		2009

Current assets	$	39,754	$	25,352	$	18,620
Total assets		591,761		594,645		602,413
Current liabilities		11,012		6,434		415
Total liabilities		27,163		19,695		734

(1)	Results do not include any amounts associated with Cal Dive. We accounted for our investment in Cal Dive under the equity method from June 10, 2009 to September 23, 2009 (Note 3).

Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2011

Long-Term Debt [Abstract]

Redemption Price

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

Maturities Of Long-Term Debt

		Helix Term Loan			Helix Revolving Loans		Senior Unsecured Notes		Convertible Senior Notes(1)			MARAD Debt			Total

Less than one year	$	3,000		$	—	$	—	$	—		$	4,877		$	7,877
One to two years		3,000			—		—		—			5,120			8,120
Two to three years		3,000			—		—		—			5,376			8,376
Three to four years		270,750			—		—		—			5,644			276,394
Four to five years		—			—		474,960		—			5,925			480,885
Over five years		—			—		—		300,000			83,224			383,224
Total debt		279,750			—		474,960		300,000			110,166			1,164,876
Current maturities		(3,000	)		—		—		—			(4,877	)		(7,877	)
Long-term debt, less current maturities		276,750			—		474,960		300,000			105,289			1,156,999
Unamortized debt Discount		—			—		—		(9,555	)		—			(9,555	)
Long-term debt	$	276,750		$	—	$	474,960	$	290,445		$	105,289		$	1,147,444

(1)	Beginning in December 2012, we may at our option repurchase the notes or the holders may require us to repurchase the notes. The notes will increase to the $300 million face amount through accretion of non-cash interest charges through December 2012.

Interest Expense And Capitalized Interest


		Year Ended December 31,
		2011			2010			2009

Interest expense	$	99,152		$	99,184		$	105,775
Interest income		(2,079	)		(1,407	)		(923	)
Capitalized interest		(1,277	)		(12,474	)		(48,119	)
Interest expense, net	$	95,796		$	85,303		$	56,733

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2011

Income Taxes [Abstract]

Schedule Of Effective Income Tax Rate Reconciliation


	Year Ended December 31,
	2011			2010			2009

Statutory rate		35.0	%		35.0	%		35.0	%
Foreign provision		(2.0	)		(4.3	)		(1.1	)
Effect of Australian reorganization	(21.2		)	—				—
IRC Section 199 deduction	—			—				(1.2	)
CDI equity pick up in excess of tax basis	—			—				3.0
Nondeductible goodwill impairment (Note 2)	—				(4.4	)	—
Valuation allowance on certain deferred tax assets	—				(3.1	)	—
Other		(1.7	)		1.0			0.9
Effective rate		10.1	%		24.2	%		36.6	%

Schedule Of Components Of Income Tax Expense (Benefit)


			Year Ended December 31,
		2011			2010			2009

Current	$	16,306		$	7,238		$	160,829
Deferred		(1,403	)		(46,836	)		(65,007	)
	$	14,903		$	(39,598	)	$	95,822

Domestic	$	119	$	(57,165	)	$	94,388
Foreign		14,784		17,567			1,434
	$	14,903	$	(39,598	)	$	95,822

Schedule Of Deferred Tax Assets And Liabilities

		2011			2010

Deferred tax liabilities:
Depreciation and depletion	$	396,355		$	384,313
OID on Convertible Notes		37,067			34,169
Equity investments in production facilities		76,911			69,495
Prepaid and other		14,779			15,616
Total deferred tax liabilities	$	525,112		$	503,593

Deferred tax assets:
Net operating loss carryforward	$	(34,987	)	$	(38,718	)
Asset retirement obligations		(88,279	)		(81,345	)
Reserves, accrued liabilities and other		(39,995	)		(27,588	)
Total deferred tax assets	$	(163,261	)	$	(147,651	)
Valuation allowance		14,310			8,497

Net deferred tax liability	$	376,161		$	364,439

Deferred income tax is presented as:
Current deferred tax asset	$	(41,449	)	$	(49,200	)
Noncurrent deferred tax liabilities		417,610			413,639
Net deferred tax liability	$	376,161		$	364,439

Reconciliation Of Beginning And Ending Amount Of Unrecognized Tax Benefits


	2011		2010		2009

Balance at January 1,	$	4,085	$	3,417	$	5,183
Additions based on tax positions related to current year		2,785	—		—
Additions for tax positions of prior years		215		668		773
Reductions for tax positions of prior years	—		—			(2,539	)
Balance at December 31,	$	7,085	$	4,085	$	3,417

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 Stock Options Activity

Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2011


	2011					2010					2009
	Shares			Weighted Average Exercise Price		Shares			Weighted Average Exercise Price		Shares			Weighted Average Exercise Price

Options outstanding at beginning of year		432,918		$	10.78		501,318		$	10.74		521,654		$	10.66
Exercised		(181,670	)	$	10.92		(68,400	)	$	10.52		(20,336	)	$	8.67
Terminated		(58,448	)	$	11.20		—			—		—			—
Options outstanding at end of year		192,800		$	10.52		432,918		$	10.78		501,318		$	10.74
Options exercisable end of year		192,800		$	10.52		432,918		$	10.78		501,318		$	10.74

Restricted Stock Units (RSUs) [Member]

Schedule Of Restricted Stock And Restricted Stock Units Activity


	2011					2010					2009
	Shares			Grant Date Fair Value(1)		Shares			Grant Date Fair Value(1)		Shares			Grant Date Fair Value(1)
Restricted shares outstanding at beginning of year		1,463,298		$	16.93		1,443,265		$	21.55		1,206,526		$	31.73
Granted		571,163		$	12.77		599,996		$	12.01		656,887		$	7.12
Vested		(504,813	)	$	19.87		(444,905	)	$	25.10		(327,777	)	$	33.69
Forfeited		(266,430	)	$	12.55		(135,058	)	$	17.48		(92,371	)	$	8.90
Restricted shares outstanding at end of year		1,263,218		$	14.80		1,463,298		$	16.93		1,443,265		$	21.55

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

Shareholders' Equity (Tables)

12 Months Ended

Dec. 31, 2011

Shareholders' Equity [Abstract]

Components Of Accumulated Other Comprehensive Income Loss

		2011			2010

Cumulative foreign currency translation adjustment	$	(22,958	)	$	(21,956	)
Unrealized losses on hedges, net (1)		12,941			(17,102	)
Accumulated other comprehensive loss	$	(10,017	)	$	(39,058	)

(1)	Amounts are net of deferred income tax asset (liabilities) totaling $7.0 million and $(9.2) million at December 31, 2011 and 2010, respectively.

Business Segment Information (Tables)

12 Months Ended

Dec. 31, 2011

Business Segment Information [Abstract]

Summary Of Financial Data By Segment


		Year Ended December 31,
		2011			2010			2009

		(in thousands)

Revenues —
Contracting Services	$	738,235		$	780,339		$	796,158
Shelf Contracting		—			—			404,709
Oil and Gas		696,607			425,369			385,338
Production Facilities(1)		75,460			117,300			3,395
Intercompany elimination		(111,695	)		(123,170	)		(127,913	)
Total	$	1,398,607		$	1,199,838		$	1,461,687

Income (loss) from operations —
Contracting Services	$	107,013		$	77,391		$	118,176
Shelf Contracting		—			—			59,077
Oil and Gas		129,936			(160,206	)		91,668
Production Facilities(1)		38,404			63,863			(3,918	)
Corporate		(39,918	)		(56,609	)		(47,734	)
Intercompany elimination		93			(19,095	)		(13,454	)
Total(2)	$	235,528		$	(94,656	)	$	203,815

Net interest expense and other —
Contracting Services	$	765		$	1,299		$	(2,280	)
Shelf Contracting		—			—			6,642
Oil and Gas		25,833			18,886			20,152
Production Facilities		442			865			2,011
Corporate and eliminations		72,913			65,274			24,970
Total	$	99,953		$	86,324		$	51,495

Equity in earnings of equity investments	$	22,215		$	19,469		$	32,329

Income (loss) before income taxes —
Contracting Services	$	97,798		$	72,459		$	120,456
Shelf Contracting		—			—			52,435
Oil and Gas		104,103			(179,092	)		71,516
Production Facilities(1)		58,064			86,100			18,300
Corporate and eliminations		(111,985	)		(143,218	)		(715	)
Total	$	147,980		$	(163,751	)	$	261,992


		Year Ended December 31,
		2011			2010			2009

		(in thousands)

Provision (benefit) for income taxes —
Contracting Services	$	29,235		$	42,828		$	43,334
Shelf Contracting		—			—			16,275
Oil and Gas		35,858			(62,954	)		23,352
Production Facilities		19,233			29,049			6,198
Corporate and eliminations		(69,423	)		(48,521	)		6,663
Total	$	14,903		$	(39,598	)	$	95,822

Identifiable assets —
Contracting Services	$	2,006,065		$	1,856,016		$	1,738,005
Oil and Gas		1,041,506			1,223,014			1,541,153
Production Facilities		534,776			512,990			499,497
Discontinued operations		—			—			878
Total	$	3,582,347		$	3,592,020		$	3,779,533

Capital expenditures —
Contracting Services	$	69,259		$	65,949		$	204,228
Shelf Contracting		—			—			39,569
Oil and Gas		119,614			84,554			137,168
Production Facilities		30,896			56,269			42,408
Total	$	219,769		$	206,772		$	423,373

Depreciation and amortization —
Contracting Services	$	73,291		$	66,333		$	53,411
Shelf Contracting		—			—			34,243
Oil and Gas		219,915			235,290			168,101
Production Facilities		14,935			9,907			3,295
Corporate and eliminations		2,962			5,586			3,567
Total	$	311,103		$	317,116		$	262,617

(1)	In April 2009, Kommandor LLC commenced leasing the HP I to us under terms of a charter arrangement following the completion of the initial conversion of the vessel (Note 8). The HP I was certified as a floating oil and gas production unit in June 2010 following the completion of installation of oil and gas processing facilities on the vessel. The HP I participated in the BP oil spill and containment response efforts and is currently being utilized as the processing unit for our Phoenix field.

(2)	Includes $16.7 million of goodwill impairment charge for year ending December 31, 2010 related to our contracting services segment. Also includes approximately $132.6 million, $181.1 million and $120.6 million of asset impairment charges for certain oil and gas properties for the years ended December 31, 2011, 2010 and 2009 respectively.

Summary Of Intercompany Segment Revenues


		Year Ended December 31,
		2011		2010		2009

Contracting Services	$	65,638	$	109,012	$	120,048
Production Facilities		46,057		14,158		—
Shelf Contracting		—		—		7,865
Total	$	111,695	$	123,170	$	127,913

Intercompany Segment Gross Profit (Loss)


		Year Ended December 31,
		2011			2010		2009

Contracting Services	$	104		$	15,655	$	13,205
Production Facilities		(197	)		3,457		(116	)
Shelf Contracting		—			—		365
Total	$	(93	)	$	19,112	$	13,454

Revenue By Individually Significant Country


		Year Ended December 31,
		2011		2010		2009

United States	$	1,013,476	$	827,597	$	923,481
United Kingdom		275,499		198,011		124,896
India		44,772		56,311		233,466
Other		64,860		117,919		179,844
Total	$	1,398,607	$	1,199,838	$	1,461,687

Property And Equipment Net Of Depreciation


		Year Ended December 31,
		2011		2010		2009

United States	$	2,034,978	$	2,236,455	$	2,564,673
United Kingdom		281,430		275,012		284,637
Other		14,919		15,613		14,396
Total	$	2,331,327	$	2,527,080	$	2,863,706

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.

Schedule Of Allowance Accounts

Allowance Accounts (Tables)

12 Months Ended

Dec. 31, 2011

Allowance Accounts [Abstract]


	Allowance for Uncollectible Accounts			Deferred Tax Asset Valuation Allowance
Balance, December 31, 2008	$	5,905		$	3,317
Additions		9,220			—
Deductions (1)		(9,953	)		(3,317	)
Balance, December 31, 2009		5,172			—
Additions (2)		4,108			8,497
Deductions(3)		(4,753	)		—
Balance, December 31, 2010		4,527			8,497
Additions(4)		61			5,813
Deductions		(521	)		—
Balance, December 31, 2011	$	4,067		$	14,310

(1)	Amounts include reductions of $5.9 million to the allowance for uncollectible accounts and $3.3 million to the deferred tax valuation allowance to reflect the deconsolidation of Cal Dive in June 2009 (Note 3).

(2)

(3)	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 16).

(4)	The valuation allowance includes $4.9 million related to our WOSEA operations and $0.9 million to our oil and gas operations in the United Kingdom. WOSEA has a full valuation allowance against its deferred tax asset balance.

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 (Tables)

12 Months Ended

Dec. 31, 2011

Costs Incurred In Oil And Gas Producing Activities

Capitalized Costs

		2011			2010

Unproved oil and gas properties	$	50,389		$	56,093
Proved oil and gas properties		2,524,304			2,691,802
Total oil and gas properties		2,574,693			2,747,895

Accumulated depletion, depreciation and amortization		(1,703,046	)		(1,673,740	)
Net capitalized costs	$	871,647		$	1,074,155


	United States		United Kingdom		Total
Year Ended December 31, 2011—
Property acquisition costs:
Proved properties	$	—	$	—	$	—
Unproved properties		41		—		41
Total property acquisition costs		41		—		41

Exploration costs		2,513		—		2,513
Development costs(1)		126,196		—		126,196
Asset retirement cost		26,523		19,923		46,446
Total costs incurred	$	155,273	$	19,923	$	175,196

Year Ended December 31, 2010—
Property acquisition costs:
Proved properties	$	—	$	—	$	—
Unproved properties		364		—		364
Total property acquisition costs		364		—		364

Exploration costs		1,362		—		1,362
Development costs(1)		53,002		—		53,002
Asset retirement cost		18,814		6,542		25,356
Total costs incurred	$	73,542	$	6,542	$	80,084

Year Ended December 31, 2009—
Property acquisition costs:
Proved properties	$	56	$	—	$	56
Unproved properties		1,829		—		1,829
Total property acquisition costs		1,885		—		1,885
Exploration costs		39,225		—		39,225
Development costs(1)		71,489		—		71,489
Asset retirement cost		66,468		2,644		69,112
Total costs incurred	$	179,067	$	2,644	$	181,711

(1)	Development costs include costs incurred to obtain access to proved reserves to drill and equip development wells. Development costs also include costs of developmental dry holes.

Results Of Operations For Oil And Gas Producing Activities


	United States			United Kingdom			Total

Year Ended December 31, 2011—
Revenues	$	696,607		$	—		$	696,607
Production (lifting) costs		176,269			3,974			180,243
Hurricane repair expense (Note 4)		(4,838	)		—			(4,838	)
Exploration expenses(2)		10,914			—			10,914
Depreciation, depletion, amortization and accretion		219,915			—			219,915
Proved property impairment charges and other (3)		113,439			19,967			133,406
Gain on sale or acquisition of oil and gas properties		(4,531	)		—			(4,531	)
Selling and administrative expenses		31,455			107			31,562
Pretax income (loss) from producing activities		153,984			(24,048	)		129,936
Income tax expense (benefit)		45,233			(9,375	)		35,858
Results of oil and gas producing activities(1)	$	108,751		$	(14,673	)	$	94,078

Year Ended December 31, 2010—
Revenues	$	425,369		$	—		$	425,369
Production (lifting) costs		131,156			4,529			135,685
Net hurricane costs (Note 4)		4,699			—			4,699
Exploration expenses(2)		8,276			—			8,276
Depreciation, depletion, amortization and accretion		235,243			47			235,290
Proved property impairment charges and other (3)		177,138			4,995			182,133
Gain on sale of oil and gas properties		(287	)		(5,959	)		(6,246	)
Gain on oil and gas derivative contracts		(1,088	)		—			(1,088	)
Selling and administrative expenses		26,714			112			26,826
Pretax loss from producing activities		(156,482	)		(3,724	)		(160,206	)
Income tax expense (benefit)		(62,526	)		(428	)		(62,954	)
Results of oil and gas producing activities(1)	$	(93,956	)	$	(3,296	)	$	(97,252	)

	United States			United Kingdom			Total
Year Ended December 31, 2009—
Revenues	$	384,375		$	963		$	385,338
Production (lifting) costs		117,565			2,271			119,836
Net hurricane costs (Note 4)		(23,332	)		—			(23,332	)
Exploration expenses(2)		24,383			—			24,383
Depreciation, depletion, amortization and accretion		167,812			1,444			169,256
Proved property impairment charges and other (3)		73,407			—			73,407
Gain on sale of oil and gas properties		(1,949	)		—			(1,949	)
Gain on oil and gas derivative contracts		(89,485	)		—			(89,485	)
Selling and administrative expenses		21,495			59			21,554
Pretax loss from producing activities		94,479			(2,811	)		91,668
Income tax expense (benefit)		24,280			(1,028	)		23,252
Results of oil and gas producing activities(1)	$	70,199		$	(1,783	)	$	68,416

(1)	Excludes net interest expense and other.

(2)	See Note 5 for additional information related to the components of our exploration costs, including impairment charges for expiring unproved leases.
(3)	Other amounts represent additional asset retirement expense recorded upon completion of a field's abandonment.

Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves


	United States			United(1)Kingdom			Total

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	)
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	)
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

As of December 31, 2009—
Future cash inflows	$	3,166,306		$	60,840		$	3,227,146
Future costs:
Production		(618,391	)		(19,075	)		(637,466	)
Development and abandonment		(755,726	)		(33,807	)		(789,533	)
Future net cash flows before income taxes		1,792,189			7,958			1,800,147
Future income tax expense		(417,042	)		(1,560	)		(418,602	)
Future net cash flows		1,375,147			6,398			1,381,545
Discount at 10% annual rate		(387,036	)		(3,449	)		(390,485	)
Standardized measure of discounted future net cash flows	$	988,111		$	2,949		$	991,060

(1)	Reflects 50% ownership in the Camelot field's reserves in 2009. In February 2010 we acquired the other 50% ownership interest in the Camelot field (Note 5).

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


	United States		United Kingdom		Total

Year Ended December 31, 2011—
Oil price per Bbl	$	105.35	$	—	$	105.35
Natural gas prices per Mcf	$	4.34	$	—	$	4.34

Year Ended December 31, 2010—
Oil price per Bbl	$	77.55	$	—	$	77.55
Natural gas prices per Mcf	$	4.40	$	—	$	4.40

Year Ended December 31, 2009—
Oil price per Bbl	$	58.05	$	—	$	58.05
Natural gas prices per Mcf	$	3.72	$	5.07	$	3.76

Changes In Standardized Measure Of Discounted Future Net Cash Flows


		Year Ended December 31,
		2011			2010			2009

Standardized measure, beginning of year	$	991,067		$	991,060		$	1,312,155
Changes during the year:
Sales, net of production costs		(516,895	)		(294,212	)		(265,501	)
Net change in prices and production costs		414,426			577,687			(245,883	)
Changes in future development costs		(108,007	)		84,907			(16,905	)
Development costs incurred		168,005			55,646			74,133
Accretion of discount		131,464			129,083			161,254
Net change in income taxes		(54,613	)		(41,115	)		257,919
Purchases of reserves in place		—			—			—
Extensions and discoveries		29,479			—			10,457
Sales of reserves in place		(14,324	)		—			(30,124	)
Net change due to revision in quantity estimates		(186,197	)		(422,987	)		(85,450	)
Changes in production rates (timing) and other		208,727			(89,002	)		(180,995	)
Total		72,065			7			(321,095	)
Standardized measure, end of year	$	1,063,132		$	991,067		$	991,060

Oil Reserves [Member]

Estimated Quantities Of Proved Oil And Gas Reserves


	United States			United Kingdom		Total

Total proved reserves at December 31, 2008		32,012			—		32,012
Revision of previous estimates		232			—		232
Production		(2,741	)		—		(2,741	)
Purchases of reserves in place		—			—		—
Sales of reserves in place		(1	)		—		(1	)
Extensions and discoveries		225			—		225
Total proved reserves at December 31, 2009		29,727			—		29,727
Revision of previous estimates(1)		(1,555	)		—		(1,555	)
Production		(3,354	)		—		(3,354	)
Purchases of reserves in place		—			—		—
Sales of reserves in place		—			—		—
Extensions and discoveries		—			—		—
Total proved reserves at December 31, 2010		24,818			—		24,818
Revision of previous estimates(2)		3,475			—		3,475
Production		(5,785	)		—		(5,785	)
Purchases of reserves in place		—			—		—
Sales of reserves in place		(205	)		—		(205	)
Extensions and discoveries		386			—		386
Total proved reserves at December 31, 2011		22,689			—		22,689

Total proved developed reserves as of :
December 31, 2008		12,809			—		12,809
December 31, 2009		14,850			—		14,850
December 31, 2010		11,796			—		11,796
December 31, 2011		12,754			—		12,754


(1)	Includes an approximate 1.8 MMBbls decrease 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 of our producing fields, most notably our Bushwood field at Garden Banks Blocks 462/463/506/507, as well as changes in the field economics of some of our other oil and gas properties. The changes in field economics primarily affected properties that were either close to the end of their production life or in which we had proved undeveloped reserves, which would have been required to be developed in the near term. The decision not to develop these properties in light of these economic changes was also driven by our desire to pursue potential alternatives to divest 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 oil spill from the Macondo well.

(2)	The positive revision reflects the better than expected production volumes primarily from our Phoenix field at Green Canyon Blocks 236, 237, 238 and 282 since it began production in October 2010.

Natural Gas Liquids Reserves [Member]

Estimated Quantities Of Proved Oil And Gas Reserves


	United States			United(1)Kingdom			Total

Total proved reserves at December 31, 2008		460,456			12,950			473,406
Revision of previous estimates (2)		(44,615	)		(755	)		(45,370	)
Production		(27,139	)		(195	)		(27,334	)
Purchases of reserves in place		—			—			—
Sales of reserves in place		(7,933	)		—			(7,933	)
Extensions and discoveries		6,546			—			6,546
Total proved reserves at December 31, 2009		387,315			12,000			399,315
Revision of previous estimates (3)		(132,954	)		(12,000	)		(144,954	)
Production		(27,097	)		—			(27,097	)
Purchases of reserves in place		—			—			—
Sales of reserves in place		—			—			—
Extensions and discoveries		—			—			—
Total proved reserves at December 31, 2010		227,264			—			227,264
Revision of previous estimates(4)		(108,947	)		—			(108,947	)
Production		(17,458	)		—			(17,458	)
Purchases of reserves in place		—			—			—
Sales of reserves in place		(4,109	)		—			(4,109	)
Extensions and discoveries		271			—			271
Total proved reserves at December 31, 2011		97,021			—			97,021

Total proved developed reserves as of :
December 31, 2008		256,794			950			257,744
December 31, 2009		124,763			—			124,763
December 31, 2010		75,664			—			75,664
December 31, 2011		59,859			—			59,859

(1)	Reflects 50% ownership in the Camelot field's reserves in 2009 and 2008. In February 2010 we acquired the other 50% ownership interest in the Camelot field. We no longer have any development plans for the field and we intend to fully abandon the field in 2012 in accordance with the applicable regulations in the United Kingdom. See Note 5 for additional information regarding our Camelot field.

(2)	Includes a 38 Bcfe reduction of the proved reserves at Bushwood field reflecting certain reservoir issues for our Noonan Gas wells subsequent to their reestablishing sustained production in January 2009 and new geologic data collected throughout 2009.

(3)	Includes an approximate 131 Bcf decrease 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 of our producing fields, most notably our Bushwood field at Garden Banks Blocks 462/463/506/507, as well as changes in the field economics of some of our other oil and gas properties. The changes in field economics primarily affected properties that were either close to the end of their production life or in which we had proved undeveloped reserves, which would have been required to be developed in the near term. The decision not to develop these properties in light of these economic changes was also driven by our desire to pursue potential alternatives to divest 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 oil spill from the Macondo well.

(4)	Decrease primarily represents a reclassification of estimate 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 our Bushwood field, where we reclassified approximately 87 Bcf at December 31, 2011.

Derivative Instruments And Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2011

Derivative Instruments And Hedging Activities [Abstract]

Derivatives Designated As Hedging Instruments


	As of December 31, 2011			As of December 31, 2010
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value

Asset Derivatives:
Natural gas contracts	Other current assets	$	12,957	Other current assets	$	5,324
Oil contracts	Other current assets		8,567	Other current assets		—
Natural gas contracts	Other assets		857	Other assets		—
Interest rate swaps	Other assets		327	Other assets		—
		$	22,708		$	5,324


	As of December 31, 2011			As of December 31, 2010
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value

Liability Derivatives:
Oil contracts	Accrued liabilities	$	886	Accrued liabilities	$	28,855
Interest rate swaps	Accrued liabilities		202	Accrued liabilities		1,751
Gas contracts	Other long-term liabilities		—	Other long-term liabilities		913
Oil contracts	Other long-term liabilities		1,711	Other long-term liabilities		—
Interest rate swaps	Other long-term liabilities		—	Other long-term liabilities		115
		$	2,799		$	31,634

Derivatives Not Designated As Hedging Instruments


	As of December 31, 2011			As of December 31, 2010
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value

Asset Derivatives:
Foreign exchange forwards	Other current assets	$	55	Other current assets	$	148
Foreign exchange forwards	Other assets		—	Other assets		42
		$	55		$	190


	As of December 31, 2011			As of December 31, 2010
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value

Liability Derivatives:
Foreign exchange forwards	Accrued liabilities	$	159	Accrued liabilities	$	—
		$	159		$	—

Impact Of Derivative Instruments On Accumulated Comprehensive Income (Loss)


	Gain (Loss) Recognized in OCI on Derivatives
		2011(1)		2010			2009

Oil and natural gas commodity contracts	$	28,749	$	(6,486	)	$	(19,092	)
Foreign exchange forwards		—		—			(538	)
Interest rate swaps		1,294		(1,213	)		712
	$	30,043	$	(7,699	)	$	(18,918	)

(1)

Gain (Loss) Reclassified From Accumulated OCI Into Income


	Location of Gain (Loss) Reclassified from Accumulated OCI into Income		Gain (Loss) Reclassified from Accumulated OCI into Income
			Years Ended December 31,
			2011			2010			2009

Oil and natural gas commodity contracts	Oil and Gas Revenues	$	(21,659	)	$	25,575		$	16,972
Interest rate swaps	Net interest expense		(2,010	)		(1,849	)		(1,096	)
		$	(23,669	)	$	23,726		$	15,876

Impact Of Non-Designated Derivative Instruments On Income Statement


	Location of Gain (Loss) Recognized in Income on Derivatives		Gain (Loss) Recognized in Income on Derivatives
			Years Ended December 31,
			2011		2010			2009

Natural gas contracts	Gain on oil and gas derivative contracts	$	—	$	1,088		$	89,485
Foreign exchange forwards	Other income (expense)		249		(2,560	)		3,279
Interest rate swaps	Other income (expense)		—		—			(468	)
		$	249	$	(1,472	)	$	92,296

Quarterly Financial Information (Tables)

12 Months Ended

Dec. 31, 2011

Quarterly Financial Information [Abstract]

Schedule Of Quarterly Financial Information


		Quarter Ended
		March 31,			June 30,			September 30,		December 31,

2011
Net revenues	$	291,607		$	338,319		$	372,496	$	396,185
Gross profit (1)		77,076			100,198			122,295		31,023
Net income (2)		25,867			41,323			46,026		16,763
Net income applicable to common shareholders		25,857			41,313			46,016		16,753
Basic earnings per common share		0.24			0.39			0.43		0.16
Diluted earnings per common share		0.24			0.39			0.43		0.16

		Quarter Ended
		March 31,			June 30,			September 30,		December 31,

2010
Net revenues	$	201,570		$	299,262		$	392,669	$	306,337
Gross profit (loss) (3)		25,856			(94,818	)		86,552		16,082
Net income (loss) (4)		(17,831	)		(85,517	)		26,171		(49,811	)
Net income (loss) applicable to common shareholders		(17,891	)		(85,551	)		26,161		(49,821	)
Basic earnings (loss) per common share		(0.17	)		(0.82	)		0.25		(0.48	)
Diluted earnings (loss) per common share		(0.17	)		(0.82	)		0.25		(0.48	)

(1)

(2)	Our fourth quarter 2011 includes a $10.6 million other than temporary impairment loss on our equity investment in our Australian joint venture (Note 7). The fourth quarter also includes a $31.3 million tax benefit related to reorganization of our Australian well intervention business.

(3)	Includes oil and gas property impairment charges totaled $11.1 in the first quarter of 2010, $159.9 million in the second quarter of 2010, $0.9 million in the third quarter of 2010 and $9.2 million in the fourth quarter of 2010.

(4)	Includes an impairment charges of $16.7 million to reduce goodwill associated with our Australia well intervention business in the fourth quarter of 2010 (Note 2).

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

12 Months Ended

Dec. 31, 2011

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

Schedule Of Condensed Consolidating Balance Sheet

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(in thousands)


	As of December 31, 2011
		Helix			Guarantors		Non-Guarantors			Consolidating Entries			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	495,484		$	2,434	$	48,547		$	—		$	546,465
Accounts receivable, net		79,290			117,767		41,724			—			238,781
Unbilled revenue		10,530			155		26,690			—			37,375
Income taxes receivable		80,388			—		—			(80,388	)		—
Other current assets		68,627			48,661		10,159			(5,826	)		121,621
Total current assets		734,319			169,017		127,120			(86,214	)		944,242
Intercompany		(147,187	)		315,821		(102,826	)		(65,808	)		—
Property and equipment, net		230,946			1,422,326		682,899			(4,844	)		2,331,327
Other assets:
Equity investments in unconsolidated affiliates		—			—		175,656			—			175,656
Equity investments in affiliates		1,952,392			37,239		—			(1,989,631	)		—
Goodwill, net		—			45,107		17,108			—			62,215
Other assets, net		53,425			36,453		16,809			(37,780	)		68,907
Due from subsidiaries/parent		64,655			430,496		—			(495,151	)		—
	$	2,888,550		$	2,456,459	$	916,766		$	(2,679,428	)	$	3,582,347

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	39,280		$	82,750	$	25,013		$	—		$	147,043
Accrued liabilities		115,921			97,692		26,350			—			239,963
Income taxes payable		—			97,692		217			(96,616	)		1,293
Current maturities of long-term debt		3,000			—		10,377			(5,500	)		7,877
Total current liabilities		158,201			278,134		61,957			(102,116	)		396,176
Long-term debt		1,042,155			—		105,289			—			1,147,444
Deferred income taxes		231,255			88,625		103,552			(5,822	)		417,610
Asset retirement obligations		—			161,208		—			—			161,208
Other long-term liabilities		4,150			4,647		571			—			9,368
Due to parent		—			—		98,285			(98,285	)		—
Total liabilities		1,435,761			532,614		369,654			(206,223	)		2,131,806
Convertible preferred stock		1,000			—		—			—			1,000
Total equity		1,451,789			1,923,845		547,112			(2,473,205	)		1,449,541
	$	2,888,550		$	2,456,459	$	916,766		$	(2,679,428	)	$	3,582,347

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(in thousands)


	As of December 31, 2010
		Helix		Guarantors		Non-Guarantors			Consolidating Entries			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	376,434	$	3,294	$	11,357		$	—		$	391,085
Accounts receivable, net		61,846		91,659		23,788			—			177,293
Unbilled revenue		11,990		—		37,421			—			49,411
Income taxes receivable		19,334		—		7,195			(20,430	)		6,099
Other current assets		63,306		49,557		12,889			(8,786	)		116,966
Total current assets		532,910		144,510		92,650			(29,216	)		740,854
Intercompany		1,906		263,920		(171,513	)		(94,313	)		—
Property and equipment, net		217,153		1,605,906		709,082			(5,061	)		2,527,080
Other assets:
Equity investments in unconsolidated affiliates		—		—		187,031			—			187,031
Equity investments in affiliates		1,998,289		29,899		—			(2,028,188	)		—
Goodwill, net		—		45,107		17,387			—			62,494
Other assets, net		43,971		38,324		21,900			(29,634	)		74,561
Due from subsidiaries/parent		95,398		105,434		—			(200,832	)		—
	$	2,889,627	$	2,233,100	$	856,537		$	(2,387,244	)	$	3,592,020

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	60,308	$	56,107	$	42,966		$	—		$	159,381
Accrued liabilities		58,074		107,874		32,289			—			198,237
Income taxes payable		—		36,678		—			(36,678	)		—
Current maturities of long-term debt		4,326		—		14,301			(8,448	)		10,179
Total current liabilities		122,708		200,659		89,556			(45,126	)		367,797
Long-term debt		1,237,587		—		110,166			—			1,347,753
Deferred income taxes		185,453		135,101		98,968			(5,883	)		413,639
Assets retirement obligations		—		170,410		—			—			170,410
Other long-term liabilities		1,421		3,691		665			—			5,777
Due to parent		—		—		120,884			(120,884	)		—
Total liabilities		1,547,169		509,861		420,239			(171,893	)		2,305,376
Convertible preferred stock		1,000		—		—			—			1,000
Total equity		1,341,458		1,723,239		436,298			(2,215,351	)		1,285,644
	$	2,889,627	$	2,233,100	$	856,537		$	(2,387,244	)	$	3,592,020

Schedule Of Condensed Consolidating Statements Of Operations

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(in thousands)


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

Net revenues		$	84,748		$	1,059,255		$	367,114		$	(112,510	)	$	1,398,607
Cost of sales			72,902			673,415			289,462			(111,281	)		924,498
Oil and gas impairments			—			112,636			19,967			—			132,603
Exploration expense			—			10,914			—			—			10,914
Gross profit (loss)			11,846			262,290			57,685			(1,229	)		330,592
Gain on sale of assets, net			(6	)		4,531			—			—			4,525
Selling, general and administrative expenses			(74,205	)		(38,915	)		12,101			1,430			(99,589	)
Loss from operations			(62,365	)		227,906			69,786			201			235,528
Equity in earnings of unconsolidated affiliates			—			—			22,215			—			22,215
Equity in earnings (losses) of affiliates			262,990			7,340			—			(270,330	)		—
Gain on investment in Cal Dive common stock			753			—			—			—			753
Other than temporary loss on equity investments			—			—			(10,563	)		—			(10,563	)
Net interest expense and other			(158,299	)		(32,345	)		67,181			23,510			(99,953	)
Income before income taxes			43,079			202,901			148,619			(246,619	)		147,980
(Benefit) provision for income taxes			(63,242	)		69,890			8,186			69			14,903
Net income (loss), including noncontrolling interests			106,321			133,011			140,433			(246,688	)		133,077
Net income applicable to noncontrolling interests			—			—			—			(3,098	)		(3,098	)
Net income (loss) applicable to Helix			106,321			133,011			140,433			(249,786	)		129,979
Preferred stock dividends			(40	)		—			—			—			(40	)
Net income (loss) applicable to Helix common shareholders		$	106,281		$	133,011		$	140,433		$	(249,786	)	$	129,939


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

Net revenues		$	183,147		$	801,503		$	334,726		$	(119,538	)	$	1,199,838
Cost of sales			124,722			659,859			297,056			(104,830	)		976,807
Oil and gas impairments			—			176,088			4,995			—			181,083
Exploration expense			—			8,276			—			—			8,276
Gross profit (loss)			58,425			(42,720	)		32,675			(14,708	)		33,672
Goodwill impairment			—			—			(16,743	)		—			(16,743	)
Gain on oil and gas derivative commodity contracts			—			1,088			—			—			1,088
Gain on sale of assets, net			3,159			287			5,959			—			9,405
Selling, general and administrative expenses			(67,165	)		(34,233	)		(22,482	)		1,802			(122,078	)
Loss from operations			(5,581	)		(75,578	)		(591	)		(12,906	)		(94,656	)
Equity in earnings of unconsolidated affiliates			—			—			19,469			—			19,469
Equity in earnings (losses) of affiliates			(60,443	)		8,473			—			51,970			—
Other than temporary loss on equity investments			(2,240	)		—			—			—			(2,240	)
Net interest expense and other			(59,522	)		(21,677	)		(5,125	)		—			(86,324	)
Income before income taxes			(127,786	)		(88,782	)		13,753			39,064			(163,751	)
(Benefit) provision for income taxes			(9,175	)		(35,299	)		9,405			(4,529	)		(39,598	)
Net income (loss), including noncontrolling interests			(118,611	)		(53,483	)		4,348			43,593			(124,153	)
Net income applicable to noncontrolling interests			—			—			—			(2,835	)		(2,835	)
Net income (loss) applicable to Helix			(118,611	)		(53,483	)		4,348			40,758			(126,988	)
Preferred stock dividends			(114	)		—			—			—			(114	)
Net income (loss) applicable to Helix common shareholders		$	(118,725	)	$	(53,483	)	$	4,348		$	40,758		$	(127,102	)

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(in thousands)


	Year Ended December 31, 2009
			Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated
Net revenues	$	211,222			$	701,706		$	648,705		$	(99,946	)	$	1,461,687
Cost of sales		162,225				484,802			521,689			(95,124	)		1,073,592
Oil and gas impairments		—				120,550			—			—			120,550
Exploration expense		—				24,383			—			—			24,383
Gross profit (loss)		48,997				71,971			127,016			(4,822	)		243,162
Gain on oil and gas derivative commodity contracts		—				89,485			—			—			89,485
Gain on sale of assets, net		—				2,019			—			—			2,019
Selling, general and administrative expenses		(52,101		)		(28,520	)		(53,919	)		3,689			(130,851	)
Income (loss) from operations		(3,104		)		134,955			73,097			(1,133	)		203,815
Equity in earnings of unconsolidated affiliates		—				—			33,229			(900	)		32,329
Equity in earnings (losses) of affiliates		145,340				(1,725	)		—			(143,615	)		—
Gain on investment in of Cal Dive common stock		77,343				—			—			—			77,343
Net interest expense and other		(18,188		)		(16,978	)		(15,341	)		(988	)		(51,495	)
Income before income taxes		201,391				116,252			90,985			(146,636	)		261,992
(Benefit) provision for income taxes		43,417				39,855			13,571			(1,021	)		95,822
Income (loss) from continuing operations		157,974				76,397			77,414			(145,615	)		166,170
Discontinued operations, net of tax		99				—			9,482			—			9,581
Net income (loss), including noncontrolling interests		158,073				76,397			86,896			(145,615	)		175,751
Net income applicable to noncontrolling interests		—				—			—			(19,697	)		(19,697	)
Net income (loss) applicable to Helix		158,073				76,397			86,896			(165,312	)		156,054
Preferred stock dividends		(54,187		)		—			—			—			(54,187	)
Net income (loss) applicable to Helix common shareholders	$	103,886			$	76,397		$	86,896		$	(165,312	)	$	101,867

Schedule Of Condensed Consolidating Statements Of Cash Flows

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS


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

	(in thousands)

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) to net cash provided by (used in) operating activities:
Equity in earnings of affiliates		(262,990	)		(7,340	)		—			270,330			—
Other adjustments		39,860			353,728			40,293			198			434,079
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	)		(174,739	)		(12,613	)		—			(219,769	)
Investments in equity investments		—			—			(2,699	)		—			(2,699	)
Distributions from equity investments, net		—			—			3,965			—			3,965
Proceeds from sale of Cal Dive common stock		3,588			—			—			—			3,588
Other, net		—			32,598			—			—			32,598
Net cash used in investing activities		(28,829	)		(142,141	)		(11,347	)		—			(182,317	)

Cash flows from financing activities:
Borrowings on revolvers		109,400			—			—			—			109,400
Repayments on revolvers		(109,400	)		—			—			—			(109,400	)
Repayments of debt		(208,085	)		—			(4,645	)		—			(212,730	)
Loan notes repayment		—			—			(1,215	)		—			(1,215	)
Deferred financing costs		(9,311	)		—			—			—			(9,311	)
Preferred stock dividends paid		(40	)		—			—			—			(40	)
Repurchase of common stock		(7,604	)		—			—			—			(7,604	)
Excess tax benefit from stock-based compensation		(1,013	)		—			—			—			(1,013	)
Exercise of stock options, net		2,018			—			—			—			2,018
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 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

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS


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

	(in thousands)

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) to net cash provided by (used in) operating activities:
Equity in earnings of affiliates		60,443			(8,473	)		—			(51,970	)		—
Other adjustments		94,376			305,649			76,865			(21,283	)		455,607
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	)		(121,709	)		(28,413	)		—			(206,772	)
Investments in equity investments		—			—			(8,253	)		—			(8,253	)
Distributions from equity investments, net		—			—			10,539			—			10,539
Proceeds from insurance reimbursement		7,020			9,086			—			—			16,106
Proceeds from sale of Cal Dive common stock		—			—			—			—			—
Proceeds from sales of property		6,042			852			—			—			6,894
Increases in restricted cash		—			(70	)		—			—			(70	)
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	)
Loan notes repayment		—			—			(2,517	)		—			(2,517	)
Deferred financing costs		(2,947	)		—			—			—			(2,947	)
Preferred stock dividends paid		(114	)		—			—			—			(114	)
Repurchase of common stock		(11,680	)		—			—			—			(11,680	)
Excess tax benefit from stock-based compensation		(3,945	)		—			—			—			(3,945	)
Exercise of stock options, net		674			—			—			—			674
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

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS


		For the Year Ended December 31, 2009
		Helix			Guarantors			Non-Guarantors			Consolidating Entries		Consolidated

		(in thousands)

Cash flows from operating activities:
Net income (loss), including noncontrolling interests	$	158,073		$	76,397		$	86,896		$	(145,615	$	175,751
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Equity in earnings of unconsolidated affiliates		—			—			(7,220	)		899		(6,321	)
Equity in earnings of affiliates		(145,340	)		1,725			—			143,615		—
Other adjustments		26,633			163,451			82,411			(17,987		254,508
Net cash provided by (used in) operating activities		39,366			241,573			162,087			(19,088		423,938
Net cash used in discontinued operations		—			—			(6,261	)		—		(6,261	)
Net cash provided by (used in) operating activities		39,366			241,573			155,826			(19,088		417,677

Cash flows from investing activities:
Capital expenditures		(35,657	)		(245,354	)		(142,362	)		—		(423,373	)
Acquisition of businesses, net of cash acquired		—			—			—			—		—
Investments in equity investments		—			—			(1,657	)		—		(1,657	)
Distributions from equity investments, net		—			—			6,742			—		6,742
Increases in restricted cash		—			(6	)		—			—		(6	)
Proceeds from sale of Cal Dive common stock		504,168			—			(112,995	)		(86,000		305,173
Proceeds from sales of property		—			23,717			—			—		23,717
Net cash provided by (used in) investing activities		468,511			(221,643	)		(250,272	)		(86,000		(89,404	)
Net cash provided by discontinued operations		—			—			20,872			—		20,872
Net cash provided by (used in) investing activities		468,511			(221,643	)		(229,400	)		(86,000		(68,532	)

Cash flows from financing activities:
Borrowings on revolvers		—			—			100,000			—		100,000
Repayments on revolvers		(349,500	)		—			—			—		(349,500	)
Repayments of debt		(4,326	)		—			(24,214	)		—		(28,540	)
Loan notes repayment		—			—			(2,130	)		—		(2,130	)
Deferred financing costs		(6,970	)		—			—			—		(6,970	)
Preferred stock dividends paid		(645	)		—			—			—		(645	)
Repurchase of common stock		(13,995	)		—			(86,000	)		86,000		(13,995	)
Excess tax benefit from stock-based compensation		895			—			—			—		895
Exercise of stock options, net		176			—			—			—		176
Intercompany financing		(23,474	)		(22,391	)		26,777			19,088		—
Net cash provided by (used in) financing activities		(397,839	)		(22,391	)		14,433			105,088		(300,709	)
Effect of exchange rate changes on cash and cash equivalents		—			—			(1,376	)		—		(1,376	)
Net increase (decrease) in cash and cash equivalents		110,038			(2,461	)		(60,517	)		—		47,060
Cash and cash equivalents:
Balance, beginning of year		148,704			4,983			69,926			—		223,613
Balance, end of year	$	258,742		$	2,522		$	9,409		$	—	$	270,673

Organization (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
Organization (Details) - USD ($) $ in Millions	Apr. 30, 2009	Dec. 31, 2009
Gain on sale of Helix Energy Limited		$ 8.3
Helix Energy Limited [Member]
Sale of Helix reservoir consulting business	$ 25.0

Gain (loss) after tax expense or benefit, not previously recognized and resulting from the sale of a business component, which is recognized at the date of sale. A gain (loss) reflects the amount by which the consideration received exceeds (is exceeded by) the net carrying amount (reflecting previous provisions for loss on disposal, if any) of the disposal group.

Summary Of Significant Accounting Policies [Line Items]

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

1 Months Ended

3 Months Ended

6 Months Ended

9 Months Ended

12 Months Ended

Jun. 30, 2010

MBbls

Jan. 31, 2010

USD ($)

Dec. 31, 2011

USD ($)

$ / shares

Sep. 30, 2011

USD ($)

Jun. 30, 2011

USD ($)

Mar. 31, 2011

USD ($)

Dec. 31, 2010

USD ($)

Sep. 30, 2010

USD ($)

Jun. 30, 2010

USD ($)

Mar. 31, 2010

USD ($)

Dec. 31, 2009

USD ($)

Sep. 30, 2009

USD ($)

Jun. 30, 2009

USD ($)

Jun. 30, 2010

USD ($)

Jun. 30, 2009

USD ($)

Sep. 30, 2010

USD ($)

Dec. 31, 2011

USD ($)

$ / shares

MMbls

Dec. 31, 2010

USD ($)

Dec. 31, 2009

USD ($)

Dec. 31, 2008

USD ($)

Aug. 31, 2011

USD ($)

Jan. 31, 2009

USD ($)

Ownership in CDI reduced

50.00%

Restricted cash

$ 33,741

$ 35,339

$ 33,741

$ 35,339

Accruals for capital expenditures

26,100

21,900

$ 48,900

Inventory

18,066

25,333

18,066

25,333

Number of drilling pipes sold, actual

2,500

Charges to reduce inventory to its lower cost

2,100

1,800

Repair and maintenance expenses

40,100

35,000

35,600

Capitalized software costs

18,100

17,800

18,100

17,800

Amortization of software costs

2,600

Assets classified as held for sale

Impairment of unproved properties

107,500

$ 2,400

$ 22,700

$ 0

9,200

$ 900

$ 159,900

$ 11,100

$ 64,600

$ 48,200

132,603

181,083

120,550

8,334

6,394

20,130

Dry hole expense and other

(70)

(424)

1,237

Interest expense capitalized

1,300

12,500

48,100

Goodwill and other indefinite-lived intangible impairments

16,700

16,743

^[1]

Goodwill

62,215

62,494

$ 78,643

^[2]

62,215

62,494

78,643

^[2]

$ 704,300

Intangible assets other than goodwill

1,600

Intangible asset, net of accumulated amortization

531

636

531

636

Amortization expenses for intangible assets

100

2,400

Amortization expense 2012

100

Amortization expense 2013

100

Amortization expense 2014

100

Amortization expense 2015

100

Amortization expense 2016

100

Deferred drydock costs, net

5,381

11,086

5,381

11,086

Drydock amortization expense

7,600

6,900

16,400

Cash paid for loss on contracts

$ 5,500

$ 7,200

Previously accrued loss

$ 200

$ 12,000

30,000

3,700

Net imbalance

900

Unrealized (loss) gain on translation adjustment

(1,000)

(10,000)

Foreign currency gains (losses)

(1,600)

1,700

2,200

Commodity derivative contracts qualified for hedge accounting (MMbls) | MBbls

480

Commodity derivative, net liability

$ 19,800

24,400

19,800

24,400

Unrealized gains (losses) on commodity derivatives

28,700

(6,500)

(19,100)

Unrealized gains (losses) on commodity derivatives, tax

15,500

(3,500)

(10,300)

Gains (losses) reclassified from accumulated other comprehensive income (loss) to oil and gas revenues

$ (21,700)

25,600

17,000

Gain (Loss) on Sale of Commodity Contracts

1,088

89,485

Costless collar financial derivative contract | MMbls

0.1

Floor price

100

Ceiling price

120

Interest rate swap maximum term in years

two

Interest rate swaps notional amount

$ 200,000

Interest swap contracts assets

$ 100

Interest swap contracts liability

1,900

Foreign currency forwards net

100

200

100

200

Recorded gains (losses) foreign currency forwards

200

(2,600)

3,300

Preferred stock beneficial conversion charges

53,439

Dividends and related costs

$ 40

114

54,187

Subsea services to customers

Aggregate fair value of properties

60,600

91,500

$ 60,600

91,500

Net book value of the affected fields

28,200

20,000

2,331,327

$ 2,527,080

2,863,706

2,331,327

2,527,080

2,863,706

Unamortized debt discount

$ 9,555

$ 60,200

Conversion price | $ / shares

$ 38.56

Cal Dive International Inc [Member]

Summary Of Significant Accounting Policies [Line Items]

Drydock amortization expense

$ 9,300

ROVs/Vessels [Member]

Summary Of Significant Accounting Policies [Line Items]

Summary Of Significant Accounting Policies [Line Items]

$ 0

ROV Equipment [Member]

Equipment In Australia [Member]

$ 1,300

Summary Of Significant Accounting Policies [Line Items]

Gulf Of Mexico Oil And Gas Properties [Member]

6,600

Summary Of Significant Accounting Policies [Line Items]

Non Producing Oil Field [Member]

21,700

Summary Of Significant Accounting Policies [Line Items]

Producing Oil Field [Member]

3,500

Summary Of Significant Accounting Policies [Line Items]

Other Current Assets [Member]

90,900

$ 172,600

$ 72,400

Summary Of Significant Accounting Policies [Line Items]

Net imbalance

$ 5,100

5,100

Accrued Liabilities [Member]

Summary Of Significant Accounting Policies [Line Items]

Net imbalance

$ 4,200

Shell [Member]

Summary Of Significant Accounting Policies [Line Items]

Revenues from major customers representing 10% or more of revenues

49.00%

29.00%

19.00%

49.00%

29.00%

19.00%

BP Plc [Member]

Summary Of Significant Accounting Policies [Line Items]

Revenues from major customers representing 10% or more of revenues

17.00%

Crude Oil [Member]

Summary Of Significant Accounting Policies [Line Items]

Forward sales contract volume

3,800,000

Natural Gas [Member]

Summary Of Significant Accounting Policies [Line Items]

Forward sales contract volume

17,000,000,000

Convertible Preferred Stock [Member]

Summary Of Significant Accounting Policies [Line Items]

Dividends and related costs

$ 100

Drilling Pipe Inventory [Member]

Summary Of Significant Accounting Policies [Line Items]

Inventory

$ 4,600

Summary Of Significant Accounting Policies [Line Items]

$ 5,000

20,000

5,000

Net book value of the affected fields

15,900

$ 281,430

$ 275,012

$ 284,637

$ 281,430

$ 275,012

$ 284,637

Gulf Of Mexico Oil And Gas Properties [Member]

Summary Of Significant Accounting Policies [Line Items]

Aggregate fair value of properties

$ 36,200

36,200

3.25% Convertible Senior Notes [Member]

Summary Of Significant Accounting Policies [Line Items]

Conversion price | $ / shares

$ 32.14

Debt instrument stated percentage

3.25%

Hurricane [Member]

Summary Of Significant Accounting Policies [Line Items]

Goodwill, beginning balance

$ 43,800

$ 51,500

[1]	Amount reflects full write off of goodwill associated with our WOSEA operations.
[2]	Prior to 2009, we fully impaired our oil and gas related goodwill ($704.3 million) as well as the $8.3 million of goodwill associated with our former reservoir consulting business.

Summary Of Significant Accounting Policies (Supplemental Cash Flow Information) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Summary Of Significant Accounting Policies [Abstract]
Interest paid, net of interest capitalized	$ 81,000	$ 68,534	$ 48,313
Income Taxes Paid	$ 11,216	$ 10,071	$ 106,480

Summary Of Significant Accounting Policies (Summary Of Gross Components Of Property And Equipment) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2011 USD ($) years	Dec. 31, 2010 USD ($)
Property, Plant and Equipment [Line Items]
Total property and equipment \| $	$ 4,391,064	$ 4,486,077
ROVs/Vessels [Member]
Property, Plant and Equipment [Line Items]
Total property and equipment \| $	$ 1,616,772	1,573,471
Estimated Useful Life, Minimum in years \| years	10
Estimated Useful Life, Maximum in years \| years	30
Oil And Gas Leases And Related Equipment [Member]
Property, Plant and Equipment [Line Items]
Total property and equipment \| $	$ 2,574,693	2,747,895
Machinery, Equipment, Buildings And Leasehold Improvements [Member]
Property, Plant and Equipment [Line Items]
Total property and equipment \| $	$ 199,599	$ 164,711
Estimated Useful Life, Minimum in years \| years	5
Estimated Useful Life, Maximum in years \| years	30

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

3 Months Ended

12 Months Ended

Dec. 31, 2010

Dec. 31, 2011

Dec. 31, 2010

Goodwill [Line Items]

$ 62,494

$ 78,643

^[1]

$ (16,700)

(16,743)

^[2]

Other adjustments

^[3]

(279)

594

Goodwill, ending balance

$ 62,494

$ 62,215

$ 62,494

[1]	Prior to 2009, we fully impaired our oil and gas related goodwill ($704.3 million) as well as the $8.3 million of goodwill associated with our former reservoir consulting business.
[2]	Amount reflects full write off of goodwill associated with our WOSEA operations.
[3]	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 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 2: 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 3: 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 4: 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 5: 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=6905597&loc=d3e13816-109267

Reference 6: 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 7: 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 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 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.

Reference 2: 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 3: 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 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 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 6: 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=6905597&loc=d3e13854-109267

Reference 7: 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 8: 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=6905597&loc=d3e13816-109267

Reference 9: 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.

Asset Retirement Obligations [Line Items]

Summary Of Significant Accounting Policies (Schedule Of Changes In Asset Retirement Obligations) (Details) - USD ($)
$ in Thousands

3 Months Ended

6 Months Ended

12 Months Ended

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2010

Sep. 30, 2010

Jun. 30, 2010

Mar. 31, 2010

Sep. 30, 2009

Jun. 30, 2009

Jun. 30, 2010

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Asset retirement obligations beginning balance

$ 234,936

$ 248,128

$ 234,936

$ 248,128

Liability incurred during the period

4,982

18,056

Liability settled during the period

(42,675)

(55,114)

Other revisions in estimated cash flows

^[1]

42,268

8,349

Accretion expense (included in depreciation and amortization)

14,880

15,517

Asset retirement obligations ending balance

$ 254,391

$ 234,936

254,391

234,936

$ 248,128

$ 107,500

$ 2,400

$ 22,700

$ 0

$ 9,200

$ 900

$ 159,900

$ 11,100

$ 64,600

$ 48,200

132,603

181,083

$ 120,550

Asset Retirement Obligations [Line Items]

Asset Retirement Obligation [Member]

$ 5,000

20,000

$ 5,000

Asset Retirement Obligations [Line Items]

Next Year [Member] | Crude Oil [Member] | Collar [Member]

$ 41,700

[1]	Includes impairment charges totaling $41.7 million, including $20.0 million associated with our only United Kingdom oil and gas property, to increase the estimated asset retirement obligation related to properties that are no longer producing oil or natural gas.

Summary Of Significant Accounting Policies (Summary Of Volumes Under Derivatives And Forward Sales Contracts) (Details)

12 Months Ended

Dec. 31, 2011

MMcf

MBbls

Next Year [Member] | Crude Oil [Member] | Collar 2 [Member]

75.0

Next Year [Member] | Natural Gas [Member] | Swap [Member]

139.0

Average Monthly Volumes | MMcf

750.0

Next Year [Member] | Natural Gas [Member] | Collar [Member]

4.35

Average Monthly Volumes | MMcf

166.7

Next Year [Member] | Brent Crude Oil [Member] | Swap [Member]

16.0

Second Year [Member] | Natural Gas [Member] | Swap [Member]

103.20

Average Monthly Volumes | MMcf

500.0

Second Year [Member] | Brent Crude Oil [Member] | Swap [Member]

4.09

41.7

Second Year [Member] | Brent Crude Oil [Member] | Collar [Member]

99.15

Maximum [Member] | Next Year [Member] | Crude Oil [Member] | Collar [Member]

41.7

Maximum [Member] | Next Year [Member] | Natural Gas [Member] | Collar [Member]

118.57

^[1],[2]

Maximum [Member] | Next Year [Member] | Brent Crude Oil [Member] | Collar 2 [Member]

5.09

^[1]

Maximum [Member] | Second Year [Member] | Brent Crude Oil [Member] | Collar [Member]

117.59

^[1]

Minimum [Member] | Next Year [Member] | Crude Oil [Member] | Collar [Member]

102.60

^[1]

Minimum [Member] | Next Year [Member] | Natural Gas [Member] | Collar [Member]

96.67

^[1]

Minimum [Member] | Next Year [Member] | Brent Crude Oil [Member] | Collar 2 [Member]

4.75

^[1]

Minimum [Member] | Second Year [Member] | Brent Crude Oil [Member] | Collar [Member]

99.42

^[1]

95.00

^[1]

[1]	The prices quoted in the table above are NYMEX Henry Hub for natural gas. For oil most of the contracts are priced as Brent crude oil.
[2]	This contract is priced using NYMEX West Texas Intermediate for crude oil.

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, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Earnings Per Share
Net income (loss) applicable to common shareholders	$ 16,753	$ 46,016	$ 41,313	$ 25,857	$ (49,821)	$ 26,161	$ (85,551)	$ (17,891)	$ 129,939	$ (127,102)	$ 101,867
Less: Undistributed net income allocable to participating securities									(1,599)		(1,436)
Undistributed net income (loss) applicable to common shareholders									128,340	(127,102)	100,431
(Income) loss from discontinued operations											(9,581)
Add: Undiscounted net income from discontinued operations allocable to participating securities											135
Income (loss) per common share - continuing operations									$ 128,340	$ (127,102)	$ 90,985
Weighted average number of shares outstanding - basic									104,528	103,857	99,136
Stock options, Shares									64		28
Undistributed earnings reallocated to participating securities, value									$ 7		$ 80
Convertible Senior Notes, Value
Convertible Senior Notes, Shares
Convertible preferred stock, Income									$ 40		$ 748
Shares to be included in diluted shares outstanding amount									361		6,556
Income (loss) per common share - continuing operations									$ 128,387	$ (127,102)	$ 91,813
Income (loss) per common share - discontinued operations											9,581
Net income (loss) per common share - Diluted									$ 128,387	$ (127,102)	$ 101,394
Weighted Average Number of Shares Outstanding, Diluted, Total									104,953	103,857	105,720

Summary Of Significant Accounting Policies (Summary Of Shares Included In Diluted Per Share Calculations) (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Diluted (in shares)	104,953	103,857	105,720
Total		104,926
Stock Options [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive securities		54
Convertible Preferred Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive securities		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 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 2: 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.

Reference 3: 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 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 Accounting Standards Codification
-Glossary Diluted Earnings Per Share
-URI http://asc.fasb.org/extlink&oid=6510752

Reference 6: 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 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Antidilution
-URI http://asc.fasb.org/extlink&oid=6505113

Reference 8: 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.

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) - USD ($)
$ in Thousands

Dec. 31, 2011

Dec. 31, 2010

$ 60,600

$ 91,500

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

1,186,059

Level 1 [Member]

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

1,081,376

Level 2 [Member]

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

^[1]

104,683

Level 3 [Member]

Oil And Gas Swaps And Collars [Member]

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

Oil And Gas Swaps And Collars [Member] | Level 1 [Member]

22,381

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

Oil And Gas Swaps And Collars [Member] | Level 2 [Member]

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

Oil And Gas Swaps And Collars [Member] | Level 3 [Member]

^[1]

22,381

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

Foreign Currency Forwards [Member]

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

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

159

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]

^[1]

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

^[1]

159

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

Oil And Gas Swaps And Collars [Member]

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

Oil And Gas Swaps And Collars [Member] | Level 1 [Member]

2,597

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

Oil And Gas Swaps And Collars [Member] | Level 2 [Member]

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

Oil And Gas Swaps And Collars [Member] | Level 3 [Member]

^[1]

2,597

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]

^[2]

1,205,864

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

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

^[2]

1,081,376

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

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

^[1],[2]

124,488

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]

327

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

202

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

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

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

^[1]

327

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

^[1]

202

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]

[1]

[2]

See Note 9 for additional information regarding our long term debt.

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

Dec. 31, 2011

Dec. 31, 2010

Jan. 31, 2009

Mar. 31, 2005

$ 1,164,876

$ 1,376,460

Unamortized debt discount

1,205,864

1,386,737

9,555

$ 60,200

Term Loan [Member]

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

^[1]

279,750

410,441

Revolving Credit Facility [Member]

^[1]

279,750

406,337

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

Convertible Senior Notes [Member]

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

300,000

^[1],[2]

300,000

^[1],[2]

$ 300,000

Unamortized debt discount

^[1],[2]

300,543

289,158

9,555

^[3]

18,500

Senior Unsecured Notes [Member]

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

^[1]

474,960

550,000

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

^[1]

501,083

567,875

MARAD Debt [Member]

^[4]

110,166

114,811

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

^[4]

$ 124,488

122,159

Loan Notes [Member]

1,208

$ 1,208

[1]	The fair values of these instruments were based on quoted market prices as of December 31, 2011 and 2010. The fair values were estimated using level 1 inputs using the market approach.
[2]	Carrying amounts exclude the $9.6 million and $18.5 million of unamortized discount on the Convertible Senior Notes at December 31, 2011 and 2010, respectively.
[3]	Beginning in December 2012, we may at our option repurchase the notes or the holders may require us to repurchase the notes. The notes will increase to the $300 million face amount through accretion of non-cash interest charges through December 2012.
[4]	The fair value of the MARAD debt was determined by a third-party evaluation of the remaining average life and outstanding principal balance of the MARAD indebtedness as compared to other government guaranteed obligations in the market place with similar terms. The fair value of the MARAD debt was estimated using Level 2 fair value inputs using the market approach.

Ownership Of Cal Dive International, Inc. (Details) - USD ($) $ / shares in Units, $ in Thousands, shares in Millions		1 Months Ended					3 Months Ended		12 Months Ended
	Jun. 10, 2009	Sep. 24, 2009	Sep. 23, 2009	Jun. 30, 2009	Jan. 31, 2009	Dec. 31, 2008	Mar. 31, 2011	Dec. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Subsidiary or Equity Method Investee [Line Items]
Sale of subsidiary/equity method investee shares by parent company					13.6
Gain on sale of Cal Dive common stock					$ (2,900)				$ 753		$ 77,343
Ownership percentage in Cal Dive					51.00%
Proceeds from sale of Cal Dive common stock					$ 86,000		$ 3,600		3,588		418,168
Gain associated with the re-measurement of remaining ownership	$ 27,100
Remaining ownership interest	26.00%
Other than temporary impairment non-cash								$ 2,200	10,563	$ 2,240
Remaining shares of Cal Dive common stock, shares										0.5
Outstanding shares, percentage										1.00%
Gain (loss) on investment in Cal Dive common stock	$ 59,400								753		$ 77,343
Equity investments								187,031	$ 175,656	$ 187,031
Cal Dive International Inc [Member]
Subsidiary or Equity Method Investee [Line Items]
Equity investments								$ 2,800		$ 2,800
IPO [Member]
Subsidiary or Equity Method Investee [Line Items]
Ownership percentage in Cal Dive						57.20%
Secondary Public Offering [Member]
Subsidiary or Equity Method Investee [Line Items]
Sale of subsidiary/equity method investee shares by parent company				22.6
Ownership percentage in Cal Dive				26.00%
Proceeds from sale of Cal Dive common stock				$ 182,900
Repurchase of shares by subsidiary				1.6
Proceeds from repurchase of common stock				$ 14,000
Common stock, per share				$ 8.50
Second Secondary Public Offering [Member]
Subsidiary or Equity Method Investee [Line Items]
Sale of subsidiary/equity method investee shares by parent company		2.6	20.6
Proceeds from sale of Cal Dive common stock		$ 221,500
Common stock, per share		$ 10
Gain (loss) on investment in Cal Dive common stock		$ 17,900

Insurance Matters (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended											12 Months Ended
Insurance Matters (Details) - USD ($) $ in Thousands	Sep. 30, 2008	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2009	Sep. 30, 2009	Jun. 30, 2009	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Supplementary Insurance Information, by Segment [Line Items]
Hurricane-related repair costs														$ 4,700	$ 25,800
Insurance proceeds													$ 5,000
Oil and gas impairments		$ 107,500	$ 2,400	$ 22,700	$ 0	$ 9,200	$ 900	$ 159,900	$ 11,100		$ 64,600	$ 48,200	132,603	181,083	$ 120,550
Prepaid insurance		12,701				12,375							$ 12,701	$ 12,375
Hurricane [Member]
Supplementary Insurance Information, by Segment [Line Items]
Aggregate deductibles	$ 6,000
Hurricane-related repair costs												8,100
Insurance proceeds												102,600
Reduction in cost of sales												43,000
Hurricane-related impairment charges												51,500
Oil and gas impairments												43,800
Catastrophic Bond [Member]
Supplementary Insurance Information, by Segment [Line Items]
Insurance expense		$ 2,000	$ 8,400			$ 2,300	$ 9,400			$ 2,400	$ 10,400
Prepaid insurance				$ 10,600				$ 11,900				$ 13,100

Oil And Gas Properties (Narrative) (Details) - USD ($)
$ in Thousands

1 Months Ended

3 Months Ended

6 Months Ended

12 Months Ended

Feb. 28, 2010

Aug. 31, 2006

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2010

Sep. 30, 2010

Jun. 30, 2010

Mar. 31, 2010

Sep. 30, 2009

Jun. 30, 2009

Mar. 31, 2009

Jun. 30, 2010

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Dec. 31, 2007

Feb. 28, 2009

Capitalized exploration cost

$ 5,800

Royalty Payments To US Government

$ 85,400

$ 37,200

$ 26,800

Working interest in oil and gas field, sold

50.00%

100.00%

50.00%

30.00%

Working interest in oil and gas field

50.00%

25.00%

100.00%

Cash payment for development of fields

^[1]

$ 126,196

$ 53,002

$ 71,489

Proceeds from sales of property

$ 800

$ 18,000

31,000

$ 40,000

Proceeds from sale of oil and gas property

800

$ 18,000

31,000

$ 40,000

Gain (loss) on sale of oil and gas property

1,200

4,500

Leasehold interests (in percentage)

100.00%

Partner paid drilling costs to evaluate prospective (in percentage)

100.00%

Accrued royalties

$ 73,500

Additional royalties interest (in percentage)

5.00%

28,200

20,000

Asset retirement obligation

107,500

$ 2,400

$ 22,700

$ 0

$ 9,200

$ 900

$ 159,900

$ 11,100

$ 64,600

48,200

132,603

181,083

$ 120,550

254,391

$ 234,936

254,391

234,936

248,128

Cash payment for development of fields

^[1]

15,900

$ 5,000

20,000

5,000

Camelot Field [Member]

Asset retirement obligation

50.00%

$ 27,300

27,300

Hurricane [Member]

Gulf Of Mexico Oil And Gas Properties [Member]

$ 43,800

51,500

112,600

Non Producing Oil Field [Member]

21,700

Producing Oil Field [Member]

3,500

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

$ 90,900

$ 172,600

$ 72,400

[1]	Development costs include costs incurred to obtain access to proved reserves to drill and equip development wells. Development costs also include costs of developmental dry holes.

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

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Dec. 31, 2008

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

$ 5,840

$ 3,252

$ 3,059

$ 2,105

Wang [Member]

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

^[1]

3,096

3,095

Danny 2 [Member]

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

^[1]

2,619

Other [Member]

Delay rental and geological and geophysical costs

$ 125

[1]

Oil And Gas Properties (Changes In Suspended Exploratory Well Costs) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Oil And Gas Properties [Abstract]
Beginning balance	$ 3,252	$ 3,059	$ 2,105
Additions pending the determination of proved reserves	2,513	(944)	36,208
Reclassifications to proved properties	5	713	(34,622)
Charged to dry hole expense	70	424	(632)
Ending balance	$ 5,840	$ 3,252	$ 3,059

Oil And Gas Properties (Components Of Exploration Expenses) (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Oil And Gas Properties [Abstract]

$ 2,650

$ 2,306

$ 3,016

Impairment of unproved properties

8,334

6,394

20,130

Dry hole expense

(70)

(424)

1,237

Total exploration expense

^[1]

$ 10,914

$ 8,276

$ 24,383

[1]	See Note 5 for additional information related to the components of our exploration costs, including impairment charges for expiring unproved leases.

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.

Oil And Gas Properties (Fair Value Of Assets Acquired And Liabilities Assumed) (Details) $ in Thousands	Dec. 31, 2011 USD ($)
Oil And Gas Properties [Abstract]
Cash	$ 10,156
Deferred tax asset	2,083
Accrued liabilities	(439)
Asset retirement obligation	(5,841)
Gain on acquisition of assets	$ 5,959

Details Of Certain Accounts (Other Current Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Details Of Certain Accounts [Abstract]
Other receivables	$ 5,096	$ 1,247
Prepaid insurance	12,701	12,375
Other prepaids	13,271	11,623
Spare parts inventory	18,066	25,333
Current deferred tax assets	41,449	49,200
Hedging assets	21,579	5,472
Income tax receivable		6,099
Gas and oil imbalance	5,134	6,001
Other	4,325	5,715
Other current assets	$ 121,621	$ 123,065

Details Of Certain Accounts (Other Assets, Net) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Details Of Certain Accounts [Abstract]
Restricted cash	$ 33,741	$ 35,339
Deferred drydock costs, net	5,381	11,086
Deferred financing costs, net	26,483	25,697
Intangible assets with finite lives	531	636
Other	2,771	1,803
Other assets, net	$ 68,907	$ 74,561

Details Of Certain Accounts (Accrued Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Details Of Certain Accounts [Abstract]
Accrued payroll and related benefits	$ 49,599	$ 38,026
Royalties payable	19,391	15,008
Current asset retirement obligations	93,183	64,526
Unearned revenue	7,654	1,817
Billings in excess of costs	28,839	6,146
Accrued interest	24,028	27,308
Hedging liability	1,247	30,606
Gas and oil imbalance	4,177	770
Other	11,845	14,030
Accrued liabilities	$ 239,963	$ 198,237

Equity Investments (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Schedule of Equity Method Investments [Line Items]
Equity investments	$ 175,656	$ 187,031	$ 175,656	$ 187,031
Equity in earnings (loss) of investments			22,215	19,469	$ 32,329
Other than temporary impairment non-cash		2,200	$ 10,563	2,240
Deepwater Gateway [Member]
Schedule of Equity Method Investments [Line Items]
Ownership percentage	50.00%		50.00%
Construction costs			$ 120,000
Equity investments	$ 96,000	99,800	96,000	99,800
Capitalized interest	$ 1,400	1,500	$ 1,400	1,500
Independence Hub [Member]
Schedule of Equity Method Investments [Line Items]
Ownership percentage	20.00%		20.00%
Equity investments	$ 79,700	82,400	$ 79,700	82,400
Capitalized interest	$ 4,900	$ 5,200	4,900	5,200
Clough Helix Pty Ltd. [Member]
Schedule of Equity Method Investments [Line Items]
Equity in earnings (loss) of investments			$ 2,100	$ (3,600)
Sapura [Member]
Schedule of Equity Method Investments [Line Items]
Ownership percentage	50.00%		50.00%
Equity investments	$ 10,600		$ 10,600
Other than temporary impairment non-cash	$ 10,600

Equity Investments (Contributions To Equity Investments) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Schedule of Equity Method Investments [Line Items]
Contributions to equity investments	$ 2,699	$ 8,253	$ 1,657
Clough Helix Pty Ltd. [Member]
Schedule of Equity Method Investments [Line Items]
Contributions to equity investments	$ 2,699	$ 8,253
Other [Member]
Schedule of Equity Method Investments [Line Items]
Contributions to equity investments			$ 1,657

Equity Investments (Distributions From Equity Investments) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Schedule of Equity Method Investments [Line Items]
Distributions from equity investments	$ 26,180	$ 30,008	$ 32,750
Deepwater Gateway [Member]
Schedule of Equity Method Investments [Line Items]
Distributions from equity investments	7,600	8,125	6,750
Independence Hub [Member]
Schedule of Equity Method Investments [Line Items]
Distributions from equity investments	$ 18,580	21,615	$ 26,000
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, 2011	Dec. 31, 2010	Dec. 31, 2009
Equity Investments [Abstract]
Revenues	$ 193,521	$ 141,705	$ 141,664
Operating income	97,954	93,324	118,566
Net income	93,215	93,005	118,602
Current assets	39,754	25,352	18,620
Total assets	591,761	594,645	602,413
Current liabilities	11,012	6,434	415
Total liabilities	$ 27,163	$ 19,695	$ 734

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 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 2: 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 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph bb
-Article 1

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph w
-Article 1

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Article 4
-Section 08
-Paragraph g
-Subparagraph 1, 2

Reference 6: 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 7: 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 8: 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 9: 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

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

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

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

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

Kommandor LLC (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
Kommandor LLC (Details) - USD ($) $ in Thousands	Apr. 30, 2009	Dec. 31, 2011	Dec. 31, 2010
Noncontrolling Interest [Line Items]
Oil and gas processing equipment, percentage of cost	100.00%
Property and equipment		$ 4,391,064	$ 4,486,077
Estimated cash outlay		$ 19,000
Kommandor LLC [Member]
Noncontrolling Interest [Line Items]
Working interest percentage		81.00%
Phoenix Field [Member]
Noncontrolling Interest [Line Items]
Working interest	70.00%
Conversion Of The Vessel [Member] \| Kommandor LLC [Member]
Noncontrolling Interest [Line Items]
Property and equipment		$ 148,700
Topside Oil And Gas Processing Facilities [Member] \| Kommandor LLC [Member]
Noncontrolling Interest [Line Items]
Property and equipment		$ 196,200

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

1 Months Ended

12 Months Ended

Feb. 28, 2010

Jan. 31, 2010

Dec. 31, 2005

Sep. 30, 2005

Mar. 31, 2005

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Aug. 31, 2011

Jun. 30, 2011

May 31, 2011

Jun. 30, 2009

Dec. 21, 2007

Jul. 31, 2006

$ 1,147,444,000

$ 1,347,753,000

Aggregate amount of debt payment

1,164,876,000

1,376,460,000

77,394,000

Payment on senior unsecured notes

300,000,000

Accrued interest paid on notes

800,000

Loss on early extinguishment of Senior Unsecured Notes

$ 2,354,000

Original borrowing capacity

$ 600,000,000

$ 435,000,000

Leverage ratio

2.00 to 1.00

Debt instrument proceeds from sale of oil and gas properties percentage

60.00%

Debt instrument proceeds reinvested into collateral percentage

40.00%

Revolving credit facility available

$ 600,000,000

Repayments of Lines of Credit

$ 109,400,000

$ 349,500,000

Interest rate swap

$ 200,000,000

Interest rate swap maximum term in years

two

Per share conversion price

$ 38.56

Payments of debt issuance costs

$ 9,300,000

2,900,000

Amortization of deferred financing costs

8,910,000

7,703,000

$ 6,693,000

Deferred financing costs

26,483,000

$ 25,697,000

Helix Term Loan [Member]

$ 276,750,000

Debt instrument, interest rate terms

$ 835,000,000

Margin increase

0.25%

Average interest rate

3.80%

2.90%

one-, three- or six-month LIBOR at our current election plus a <font class="_mt">2.00</font>% margin (as amended in February 2010, the margin was increased up to <font class="_mt">2.50</font>% depending on current leverage ratios, as defined).

Revolving Credit Facility [Member]

Debt instrument, interest rate terms

Leverage ratio

4.50 to 1.00

one-, three- or six-month LIBOR rates or on Base Rates at our current election plus an applicable margin as discussed below. Margins on the Revolving Loans will fluctuate in relation to the consolidated leverage ratio as provided in the Credit Agreement.

Revolving credit facility available

$ 558,600,000

Helix Revolving Loans [Member]

Original borrowing capacity

$ 300,000,000

Average interest rate

3.40%

Senior Unsecured Notes [Member]

474,960,000

Debt instrument purchase price percentage of principal amount

^[1]

$ 474,960,000

550,000,000

101.00%

Debt instrument interest rate

9.50%

Stated maturity year

January 15, 2016

Premium on senior unsecured notes

$ 2,400,000

Extinguishment of Notes

75,000,000

Cash and cash equivalents plus available capacity under Revolving Credit Facility

500,000,000

Amortization of deferred financing costs

900,000

Convertible Senior Notes [Member]

^[2]

290,445,000

Debt instrument purchase price percentage of principal amount

$ 300,000,000

^[1],[3]

300,000,000

^[1],[3]

1000.00%

Debt instrument interest rate

3.25%

Contingent interest

0.25%

Conversion percentage threshold of the convertible senior notes

120.00%

Issuance of notes percentage

100.00%

Stated maturity year

2025

Cash and cash equivalents plus available capacity under Revolving Credit Facility

$ 400,000,000

Convertible Senior Notes, shares of common stock

15.56

31.12

Effective interest rate

6.60%

Per share conversion price

$ 64.27

$ 32.14

Conversion rate

103.00%

Convertible Senior Notes are convertible into shares

13,303,770

MARAD Debt [Member]

$ 105,289,000

Debt instrument interest rate

^[4]

$ 110,166,000

114,811,000

4.93%

Stated maturity year

February 2027

Debt percentage guaranteed

50.00%

Letters Of Credit [Member]

Unsecured letters of credit

$ 41,400,000

Other [Member]

Unsecured letters of credit

41,400,000

Deferred financing costs

$ 26,500,000

$ 25,700,000

Senior Credit Facility [Member]

Leverage ratio

4.00 to 1.00

Maximum [Member]

Investments in subsidiaries permitted by credit agreement, excluding loan party subsidiaries and subsidiaries with pledged equity interests

$ 200,000,000

Maximum [Member] | Helix Term Loan [Member]

Maximum [Member] | Helix Revolving Loans [Member]

Margin increase

2.50%

Repurchases and redemptions permitted under credit agreement, common stock, value

50,000,000

Minimum [Member]

Investments in subsidiaries permitted by credit agreement, excluding loan party subsidiaries and subsidiaries with pledged equity interests

$ 100,000,000

Minimum [Member] | Helix Term Loan [Member]

Margin increase

2.00%

[1]	The fair values of these instruments were based on quoted market prices as of December 31, 2011 and 2010. The fair values were estimated using level 1 inputs using the market approach.
[2]	Beginning in December 2012, we may at our option repurchase the notes or the holders may require us to repurchase the notes. The notes will increase to the $300 million face amount through accretion of non-cash interest charges through December 2012.
[3]	Carrying amounts exclude the $9.6 million and $18.5 million of unamortized discount on the Convertible Senior Notes at December 31, 2011 and 2010, respectively.
[4]	The fair value of the MARAD debt was determined by a third-party evaluation of the remaining average life and outstanding principal balance of the MARAD indebtedness as compared to other government guaranteed obligations in the market place with similar terms. The fair value of the MARAD debt was estimated using Level 2 fair value inputs using the market approach.

Long-Term Debt (Redemption Price) (Details)	12 Months Ended
Long-Term Debt (Redemption Price) (Details)	Dec. 31, 2011
2012 [Member]
Debt Instrument [Line Items]
Debt instrument redemption price, percentage of principal amount	104.75%
2013 [Member]
Debt Instrument [Line Items]
Debt instrument redemption price, percentage of principal amount	102.375%
2014 And Thereafter [Member]
Debt Instrument [Line Items]
Debt instrument redemption price, percentage of principal amount	100.00%

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

Dec. 31, 2011

Dec. 31, 2010

Jan. 31, 2009

$ 7,877,000

8,120,000

8,376,000

276,394,000

480,885,000

383,224,000

1,164,876,000

(7,877,000)

$ (10,179,000)

Unamortized debt Discount

1,156,999,000

(9,555,000)

$ (60,200,000)

Face amount notes will increase to through accretion of non-cash interest charges

1,147,444,000

1,347,753,000

300,000,000

Helix Term Loan [Member]

3,000,000

3,000,000

3,000,000

270,750,000

279,750,000

(3,000,000)

276,750,000

Helix Revolving Loans [Member]

276,750,000

Unamortized debt Discount

Senior Unsecured Notes [Member]

Four to five years

474,960,000

Total debt

474,960,000

474,960,000

Convertible Senior Notes [Member]

474,960,000

Over five years

^[1]

300,000,000

Total debt

^[1]

300,000,000

Unamortized debt Discount

^[1]

300,000,000

(9,555,000)

^[1]

$ (18,500,000)

^[1]

290,445,000

MARAD Debt [Member]

4,877,000

5,120,000

5,376,000

5,644,000

5,925,000

83,224,000

110,166,000

(4,877,000)

105,289,000

$ 105,289,000

[1]	Beginning in December 2012, we may at our option repurchase the notes or the holders may require us to repurchase the notes. The notes will increase to the $300 million face amount through accretion of non-cash interest charges through December 2012.

Long-Term Debt (Interest Expense And Capitalized Interest) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Long-Term Debt [Abstract]
Interest expense	$ 99,152	$ 99,184	$ 105,775
Interest income	(2,079)	(1,407)	(923)
Capitalized interest	(1,277)	(12,474)	(48,119)
Interest expense, net	$ 95,796	$ 85,303	$ 56,733

Income Taxes (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
Income Taxes (Narrative) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Income Taxes [Line Items]
Effective income tax rate	35.00%	35.00%	35.00%
Operating loss carryforward	$ 17,600
Tax credit carryforward, amount	$ 9,700
Operating loss carryforwards, expiration dates	2030
Tax credit carryforward, expiration dates	2020
Valuation allowance related to certain non-U.S. deferred assets	$ 14,310	$ 8,497
Long term liability related to an uncertain tax position	2,800
Unrecognized tax benefits, income tax penalties and interest expense	200
Unrecognized tax benefits that would impact effective tax rate	6,200	3,400	$ 3,400
Income tax benefit	14,903	(39,598)	95,822
Uncertain tax positions	7,100
Income tax, accrued interest and penalties	900
Helix [Member]
Income Taxes [Line Items]
Income tax benefit	(63,242)	(9,175)	$ 43,417
Australian Subsidiary [Member]
Income Taxes [Line Items]
Income tax benefit	31,300
Non-U.S. Subsidiaries [Member]
Income Taxes [Line Items]
Accumulated earnings and profits	$ 113,400	$ 28,200

Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Income Taxes [Abstract]
Statutory rate	35.00%	35.00%	35.00%
Foreign provision	(2.00%)	(4.30%)	(1.10%)
Effect of Australian reorganization	(21.20%)
IRC Section 199 deduction			(1.20%)
CDI equity pick up in excess of tax basis			3.00%
Nondeductible goodwill impairment (Note 2)		(4.40%)
Valuation allowance on certain deferred tax assets		(3.10%)
Other	(1.70%)	1.00%	0.90%
Effective rate	10.10%	24.20%	36.60%

Income Taxes (Schedule Of Components Of Income Tax Expense (Benefit)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Income Taxes [Abstract]
Current	$ 16,306	$ 7,238	$ 160,829
Deferred	(1,403)	(46,836)	(65,007)
Provision for income taxes	14,903	(39,598)	95,822
Domestic	119	(57,165)	94,388
Foreign	$ 14,784	$ 17,567	$ 1,434

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 SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Reference 2: 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 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.(h))
-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
-Glossary Current Tax Expense (or Benefit)
-URI http://asc.fasb.org/extlink&oid=6509736

Reference 5: 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 6: 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 7: 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.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 6
-Section I
-Subsection 7

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 SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Reference 2: 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 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.(h))
-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 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 Accounting Standards Codification
-Glossary Deferred Tax Expense (or Benefit)
-URI http://asc.fasb.org/extlink&oid=6510177

Reference 6: 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 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 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.

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Income Taxes [Abstract]
Depreciation and depletion	$ 396,355	$ 384,313
OID on Convertible Notes	37,067	34,169
Equity investments in production facilities	76,911	69,495
Prepaid and other	14,779	15,616
Total deferred tax liabilities	525,112	503,593
Net operating loss carryforward	(34,987)	(38,718)
Asset retirement obligations	(88,279)	(81,345)
Reserves, accrued liabilities and other	(39,995)	(27,588)
Total deferred tax assets	(163,261)	(147,651)
Valuation allowance	14,310	8,497
Current deferred tax asset	(41,449)	(49,200)
Noncurrent deferred tax liabilities	417,610	413,639
Net deferred tax liability	$ 376,161	$ 364,439

Income Taxes (Reconciliation Of Beginning And Ending Amount Of Unrecognized Tax Benefits) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Income Taxes [Abstract]
Balance at January 1,	$ 4,085	$ 3,417	$ 5,183
Additions based on tax positions related to current year	2,785
Additions for tax positions of prior years	215	668	773
Reductions for tax positions of prior years			(2,539)
Balance at December 31,	$ 7,085	$ 4,085	$ 3,417

Convertible Preferred Stock (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended			3 Months Ended		12 Months Ended
	May 31, 2010	Feb. 28, 2009	Jan. 31, 2009	Sep. 30, 2009	Mar. 31, 2009	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Temporary Equity [Line Items]
Cumulative convertible preferred stock						$ 1.0
Common stock issued and delivered						361,402
Reset price per share		$ 2.767
Convertible preferred stock outstanding							$ 1.0
Preferred stock, dividend rate						4.00%	4.00%	4.00%
Series A-2 Cumulative Convertible Preferred Stock [Member]
Temporary Equity [Line Items]
Cumulative convertible preferred stock			$ 30.0
Common stock issued and delivered			5,938,776
Beneficial conversion charges					$ 29.3
Shares to be issued upon a conversion			1,964,058
Additional shares			3,974,718
Net proceeds received from the issuance cumulative convertible preferred stock			$ 29.3
Series A-1 Cumulative Convertible Preferred Stock [Member]
Temporary Equity [Line Items]
Cumulative convertible preferred stock		$ 25.0
Cumulative convertible preferred stock	$ 5.0			$ 19.0
Common stock issued and delivered	1,807,011			6,866,641
Beneficial conversion charges		$ 24.1
Shares to be issued upon a conversion		1,666,668
Additional shares delivered		7,368,388
Reset price per share		$ 2.767
Shares to be received in future conversions		9,035,056
Minimum [Member]
Temporary Equity [Line Items]
Preferred stock, dividend rate						4.00%

Employee Benefit Plans (Narrative) (Details) $ / shares in Units, $ in Millions	1 Months Ended		12 Months Ended
	Jan. 31, 2012 USD ($) $ / shares shares	Jan. 31, 2011	Dec. 31, 2011 USD ($) years $ / shares shares	Dec. 31, 2010 USD ($) $ / shares shares	Dec. 31, 2009 USD ($) $ / shares shares	Jan. 03, 2012 USD ($)	Dec. 31, 2008 shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation, employer subscription rate			50.00%
Share-based compensation, maximum employee subscription rate			5.00%
Deferred compensation plan expense			$ 1.4	$ 1.6	$ 1.5
Maximum percentage of common stock that can be granted			10.00%
Stock split			two-for-one stock split
Forfeitures on restricted stock (in percentage)			17.00%
Stock options granted maximum exercise life, in years \| years			10
Options outstanding, shares \| shares			192,800	432,918	501,318		521,654
Exercised, weighted average exercise price \| $ / shares			$ 10.92	$ 10.52	$ 8.67
Weighted average remaining contractual life of stock options			1.4
Stock options compensation expense				$ 0.0
Intrinsic value of stock options exercised			$ 1.1	0.1	$ 0.1
Intrinsic value of options exercisable			1.0	0.6	0.5
Restricted stock expense			8.4	9.0	9.4
Compensation cost of unvested restricted stock awards			$ 23.4	29.7	21.8
Weighted average vesting period related to nonvested restricted stock \| years			2.7
Share-based payment award, method of measuring cost of award			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 50% (75% for 2012 grants) of the base price, no payout will be made at the applicable anniversary date.
Stock-based liability paid						$ 4.0
2005 Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for grant \| shares			920,748
Aggregate number of shares granted \| shares			6,000,000
Awards granted to employees typically vest (in percentage)	33.00%		20.00%
Awards vesting period, years	3		five
Restricted share grants, shares \| shares	132,910
Market price per share of restricted share \| $ / shares	$ 15.80
1995 Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted to employees typically vest (in percentage)			20.00%
Awards vesting period, years			5
2009 Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share based payment award value	$ 4.2		$ 5.2	10.2	14.7
Restricted stock expense			7.9	8.6	3.7
Liability long-term incentive compensation plan			$ 8.5
Stock Options [Member] \| 2005 Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate number of shares granted \| shares			2,000,000
Stock Options [Member] \| 1995 Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted to employees typically vest (in percentage)			33.00%
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted to employees typically vest (in percentage)	33.00%
Market price per share of restricted share \| $ / shares	$ 15.80
Market value of restricted shares	$ 2.2
Restricted Stock Units (RSUs) [Member] \| 2005 Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate number of shares granted \| shares			4,000,000
Stock Option One [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options outstanding, shares \| shares			98,000
Exercised, weighted average exercise price \| $ / shares			$ 8.57
Stock Option Two [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options outstanding, shares \| shares			14,000
Exercised, weighted average exercise price \| $ / shares			$ 10.59
Stock Option Three [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options outstanding, shares \| shares			28,000
Exercised, weighted average exercise price \| $ / shares			$ 10.92
Stock Option Four [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options outstanding, shares \| shares			52,800
Exercised, weighted average exercise price \| $ / shares			$ 13.91
Performance Share Units (PSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted to employees typically vest (in percentage)		100.00%
Executive Officer [Member] \| 2005 Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Market value of restricted shares	$ 2.1
Executive Officer [Member] \| 2009 Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share based payment award value				6.0	8.1
Restricted stock expense			$ 6.5	$ 6.9	$ 2.6
Executive Officer [Member] \| Performance Share Units (PSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted shares issued, shares \| shares	132,910
Non-Executive Employees [Member] \| Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted share grants, shares \| shares	139,243
Maximum [Member] \| Performance Share Units (PSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock performance awards percentage	200.00%
Minimum [Member] \| Performance Share Units (PSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock performance awards percentage	0.00%

Employee Benefit Plans (Schedule Of Stock Options Activity) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Employee Benefit Plans [Abstract]
Options outstanding at beginning of year, Shares	432,918	501,318	521,654
Exercised, Shares	(181,670)	(68,400)	(20,336)
Terminated, Shares	(58,448)
Options outstanding at end of year, Shares	192,800	432,918	501,318
Options exercisable end of year, Shares	192,800	432,918	501,318
Options outstanding at beginning of year, Weighted Average Exercise Price	$ 10.78	$ 10.74	$ 10.66
Exercised, Weighted Average Exercise Price	10.92	10.52	8.67
Terminated, Weighted Average Exercise Price	11.20
Options outstanding at end of year, Weighted Average Exercise Price	10.52	10.78	10.74
Options exercisable end of year, Weighted Average Exercise Price	$ 10.52	$ 10.78	$ 10.74

Employee Benefit Plans (Schedule Of Restricted Stock And Restricted Stock Units Activity) (Details) - Restricted Stock Units RSU And Restricted Stock Shares [Member] - $ / shares

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Restricted shares outstanding at beginning of year, Shares

1,463,298

1,443,265

1,206,526

Granted, Shares

571,163

599,996

656,887

Vested, Shares

(504,813)

(444,905)

(327,777)

Forfeited, Shares

(266,430)

(135,058)

(92,371)

Restricted shares outstanding at end of year, Shares

1,263,218

1,463,298

1,443,265

Restricted shares outstanding at beginning of year, Grant Date Fair Value

^[1]

$ 16.93

$ 21.55

$ 31.73

Granted, Grant Date Fair Value

^[1]

12.77

12.01

7.12

Vested, Grant Date Fair Value

^[1]

19.87

25.10

33.69

Forfeited, Grant Date Fair Value

^[1]

12.55

17.48

8.90

Restricted shares outstanding at end of year, Grant Date Fair Value

^[1]

$ 14.80

$ 16.93

$ 21.55

[1]	Represents the average grant date market value, which is based on the quoted market price of the common stock on the business day prior to the date of grant.

Shareholders' Equity (Narrative) (Details) - $ / shares	Dec. 31, 2011	Dec. 31, 2010
Shareholders' Equity [Abstract]
Common stock, authorized (in shares)	240,000,000	240,000,000
Common stock, no par value
Preferred stock, shares issued	5,000,000
Preferred stock, par value	$ 0.01

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

Dec. 31, 2011

Dec. 31, 2010

Shareholders' Equity [Abstract]

Cumulative foreign currency translation adjustment

$ (22,958)

$ (21,956)

Unrealized losses on hedges, net

^[1]

12,941

(17,102)

Accumulated other comprehensive loss

(10,017)

(39,058)

Deferred income tax asset (liabilities), net

$ 7,000

$ (9,200)

[1]	Amounts are net of deferred income tax asset (liabilities) totaling $7.0 million and $(9.2) million at December 31, 2011 and 2010, respectively.

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.

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.

Stock Buyback Program (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended
	Oct. 31, 2011	Dec. 31, 2011	Jun. 30, 2009
Stock Buyback Program [Abstract]
Repurchase of common stock			1,500,000
Total stock repurchase, shares		2,473,730
Repurchase of common stock, shares	497,412
Repurchase of common stock, value	$ 6.5
Total stock repurchase, value		$ 30.5
Repurchase of common stock, value per share	$ 13.07
Average stock repurchase, value per share		$ 12.34

Related Party Transactions (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Apr. 30, 2000	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Percentage of working interests acquired	20.00%
Financing exploratory costs		$ 5,840	$ 3,252	$ 3,059	$ 2,105
Financing exploratory costs	$ 20,000
Royalty interest	25.00%
Related party payments		$ 8,300	11,200	11,300
Partnership interests		80.70%
Weatherford International, Ltd [Member]
Related party payments		$ 3,600	$ 6,900	$ 3,300

Commitments And Contingencies (Details) $ in Millions		1 Months Ended	3 Months Ended				9 Months Ended	12 Months Ended
Commitments And Contingencies (Details) $ in Millions	Sep. 30, 2010 USD ($)	Apr. 30, 2010 AUD ($)	Mar. 31, 2011 USD ($)	Jun. 30, 2010 USD ($)	Mar. 31, 2010 USD ($)	Mar. 31, 2009 USD ($)	Sep. 30, 2010 USD ($)	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)	Dec. 31, 2008 USD ($)	Mar. 31, 2009 AUD ($)
Loss Contingencies [Line Items]
Future minimum rentals								$ 54,400,000
Future minimum rent due in 2012								42,800,000
Future minimum rent due in 2013								7,600,000
Future minimum rent due in 2014								1,800,000
Future minimum rent due in 2015								1,200,000
Future minimum rent due in 2016								400,000
Future minimum rent thereafter								600,000
Rental expense								62,200,000	$ 66,200,000	$ 89,900,000
Insurance annual aggregate deductible								1,250,000
Insurance liability limits								500,000,000
Self-insured retention for employees								250,000
Liability for damages												$ 32
Approximate actual damages						$ 12,000,000
Damage claims paid		$ 15
Settlement of claims					$ 17,500,000
Payments for litigation settlements					13,800,000
Remaining trade receivable write off					$ 3,700,000				3,700,000
Trade receivables collected								303,000,000
Trade receivable allowance	$ 4,000,000
Value added tax assessment								28,000,000
Estimated loss under the contract										15,800,000	$ 9,000,000
Settlement of obligation under the contract										12,700,000
Previously accrued loss			$ 200,000				$ 12,000,000		$ 30,000,000	$ 3,700,000
Loss on contract termination				$ 5,500,000							$ 7,200,000
Q4000, Helix Producer I And Well Enhancer [Member]
Loss Contingencies [Line Items]
Insurance deductibles								1,000,000
Intrepid, Seawell And Express [Member]
Loss Contingencies [Line Items]
Insurance deductibles								500,000
Caesar [Member]
Loss Contingencies [Line Items]
Insurance deductibles								375,000
P&I And General Liability [Member]
Loss Contingencies [Line Items]
Insurance deductibles								100,000
Maritime Employers Liability [Member]
Loss Contingencies [Line Items]
Insurance deductibles								100,000
Insurance annual aggregate deductible								$ 1,000,000

Business Segment Information (Summary Of Financial Data By Segment) (Details) - USD ($)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2010

Sep. 30, 2010

Jun. 30, 2010

Mar. 31, 2010

Sep. 30, 2009

Jun. 30, 2009

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

$ 396,185

$ 372,496

$ 338,319

$ 291,607

$ 306,337

$ 392,669

$ 299,262

$ 201,570

$ 1,398,607

$ 1,199,838

$ 1,461,687

^[1]

235,528

(94,656)

203,815

Equity in earnings of equity investments

99,953

86,324

51,495

22,215

19,469

32,329

147,980

(163,751)

261,992

14,903

(39,598)

95,822

3,582,347

3,592,020

3,582,347

3,592,020

3,779,533

219,769

206,772

423,373

311,103

317,116

262,617

16,700

16,743

^[2]

Contracting Services [Member]

107,500

$ 2,400

$ 22,700

$ 0

9,200

$ 900

$ 159,900

$ 11,100

$ 64,600

$ 48,200

132,603

181,083

120,550

738,235

780,339

796,158

107,013

77,391

118,176

765

1,299

(2,280)

97,798

72,459

120,456

29,235

42,828

43,334

2,006,065

1,856,016

2,006,065

1,856,016

1,738,005

69,259

65,949

204,228

Shelf Contracting [Member]

73,291

66,333

53,411

404,709

59,077

6,642

52,435

16,275

39,569

34,243

Oil And Gas [Member]

696,607

425,369

385,338

129,936

(160,206)

91,668

25,833

18,886

20,152

104,103

(179,092)

71,516

35,858

(62,954)

23,352

1,041,506

1,223,014

1,041,506

1,223,014

1,541,153

119,614

84,554

137,168

Production Facilities [Member]

219,915

235,290

168,101

^[3]

75,460

117,300

3,395

^[3]

38,404

63,863

(3,918)

442

865

2,011

^[3]

58,064

86,100

18,300

19,233

29,049

6,198

$ 534,776

$ 512,990

534,776

512,990

499,497

30,896

56,269

42,408

14,935

9,907

3,295

Corporate [Member]

Intercompany Elimination [Member]

(39,918)

(56,609)

(47,734)

(111,695)

(123,170)

(127,913)

Corporate And Eliminations [Member]

(19,095)

(13,454)

72,913

65,274

24,970

(111,985)

(143,218)

(715)

(69,423)

(48,521)

6,663

Discontinued Operations [Member]

$ 2,962

$ 5,586

3,567

Valuation and Qualifying Accounts Disclosure [Line Items]

$ 878

[1]	Includes $16.7 million of goodwill impairment charge for year ending December 31, 2010 related to our contracting services segment. Also includes approximately $132.6 million, $181.1 million and $120.6 million of asset impairment charges for certain oil and gas properties for the years ended December 31, 2011, 2010 and 2009 respectively.
[2]	Amount reflects full write off of goodwill associated with our WOSEA operations.
[3]	In April 2009, Kommandor LLC commenced leasing the HP I to us under terms of a charter arrangement following the completion of the initial conversion of the vessel (Note 8). The HP I was certified as a floating oil and gas production unit in June 2010 following the completion of installation of oil and gas processing facilities on the vessel. The HP I participated in the BP oil spill and containment response efforts and is currently being utilized as the processing unit for our Phoenix field.

Business Segment Information (Summary Of Intercompany Segment Revenues) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Segment Reporting Information [Line Items]
Intercompany segment revenues	$ 111,695	$ 123,170	$ 127,913
Contracting Services [Member]
Segment Reporting Information [Line Items]
Intercompany segment revenues	65,638	109,012	120,048
Production Facilities [Member]
Segment Reporting Information [Line Items]
Intercompany segment revenues	$ 46,057	$ 14,158
Shelf Contracting [Member]
Segment Reporting Information [Line Items]
Intercompany segment revenues			$ 7,865

Business Segment Information (Intercompany Segment Gross Profit (Loss)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Segment Reporting Information [Line Items]
Gross profit (loss) with other operating segments of same entity	$ (93)	$ 19,112	$ 13,454
Contracting Services [Member]
Segment Reporting Information [Line Items]
Gross profit (loss) with other operating segments of same entity	104	15,655	13,205
Production Facilities [Member]
Segment Reporting Information [Line Items]
Gross profit (loss) with other operating segments of same entity	$ (197)	$ 3,457	(116)
Shelf Contracting [Member]
Segment Reporting Information [Line Items]
Gross profit (loss) with other operating segments of same entity			$ 365

Business Segment Information (Revenue By Geographical Region) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Segment Reporting Information [Line Items]
Total net revenues	$ 396,185	$ 372,496	$ 338,319	$ 291,607	$ 306,337	$ 392,669	$ 299,262	$ 201,570	$ 1,398,607	$ 1,199,838	$ 1,461,687
United States [Member]
Segment Reporting Information [Line Items]
Total net revenues									1,013,476	827,597	923,481
United Kingdom [Member]
Segment Reporting Information [Line Items]
Total net revenues									275,499	198,011	124,896
India [Member]
Segment Reporting Information [Line Items]
Total net revenues									44,772	56,311	233,466
Other [Member]
Segment Reporting Information [Line Items]
Total net revenues									$ 64,860	$ 117,919	$ 179,844

Business Segment Information (Property Plant And Equipment Net Of Depreciation By Geographic Region) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Segment Reporting Information [Line Items]
Property and equipment, net	$ 2,331,327	$ 2,527,080	$ 2,863,706
United States [Member]
Segment Reporting Information [Line Items]
Property and equipment, net	2,034,978	2,236,455	2,564,673
United Kingdom [Member]
Segment Reporting Information [Line Items]
Property and equipment, net	281,430	275,012	284,637
Other [Member]
Segment Reporting Information [Line Items]
Property and equipment, net	$ 14,919	$ 15,613	$ 14,396

Allowance Accounts (Schedule Of Allowance Accounts) (Details) - USD ($)
$ in Thousands

1 Months Ended

3 Months Ended

12 Months Ended

Jun. 30, 2009

Mar. 31, 2010

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Dec. 31, 2007

Bad debt allowance

$ 4,067

$ 4,527

Valuation allowance

$ 7,300

Percentage Of Oil And Gas Field Working Interest

50.00%

25.00%

100.00%

Bad debt allowance related to a large international construction contract

$ 4,000

Bad debt expense related to settlement of third party claims

$ 3,700

3,700

Allowance For Uncollectible Accounts [Member]

Valuation and Qualifying Accounts Disclosure [Line Items]

$ 5,172

4,527

5,172

$ 5,905

^[1]

4,108

^[2]

9,220

Deductions

$ 5,900

(521)

(4,753)

^[3]

(9,953)

^[4]

Deferred Tax Asset Valuation Allowance [Member]

4,067

4,527

5,172

Valuation and Qualifying Accounts Disclosure [Line Items]

8,497

3,317

5,813

^[1]

8,497

^[2]

Deductions

$ 3,300

$ (3,317)

^[4]

Valuation and Qualifying Accounts Disclosure [Line Items]

14,310

$ 8,497

WOSEA [Member]

Oil And Gas Operations In United Kingdom [Member]

4,900

Valuation and Qualifying Accounts Disclosure [Line Items]

Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]

$ 900

[1]	The valuation allowance includes $4.9 million related to our WOSEA operations and $0.9 million to our oil and gas operations in the United Kingdom. WOSEA has a full valuation allowance against its deferred tax asset balance.
[2]	Amounts include a $4.0 million bad debt allowance related to a large international construction contract and the valuation allowance includes a $7.3 million 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.
[3]	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 16).
[4]	Amounts include reductions of $5.9 million to the allowance for uncollectible accounts and $3.3 million to the deferred tax valuation allowance to reflect the deconsolidation of Cal Dive in June 2009 (Note 3).

Supplemental Oil And Gas Disclosures (Capitalized Costs) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Supplemental Oil and Gas Disclosures [Abstract]
Unproved oil and gas properties	$ 50,389	$ 56,093
Proved oil and gas properties	2,524,304	2,691,802
Total oil and gas properties	2,574,693	2,747,895
Accumulated depletion, depreciation and amortization	(1,703,046)	(1,673,740)
Net capitalized costs	871,647	1,074,155
Oil and gas asset retirement obligations	$ 254,391	$ 234,936	$ 248,128

Supplemental Oil And Gas Disclosures (Costs Incurred In Oil And Gas Producing Activities) (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Proved properties

$ 56

Unproved properties

$ 41

$ 364

1,829

Total property acquisition costs

364

1,885

Exploration costs

2,513

1,362

39,225

Development costs

^[1]

126,196

53,002

71,489

Asset retirement cost

46,446

25,356

69,112

Total costs incurred

175,196

80,084

181,711

United States [Member]

Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]

Proved properties

Unproved properties

364

1,829

Total property acquisition costs

364

1,885

Exploration costs

2,513

1,362

39,225

Development costs

^[1]

126,196

53,002

71,489

Asset retirement cost

26,523

18,814

66,468

Total costs incurred

155,273

73,542

179,067

Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]

Proved properties

Unproved properties

Total property acquisition costs

Exploration costs

Development costs

^[1]

Asset retirement cost

19,923

6,542

2,644

Total costs incurred

$ 19,923

$ 6,542

$ 2,644

[1]	Development costs include costs incurred to obtain access to proved reserves to drill and equip development wells. Development costs also include costs of developmental dry holes.

Supplemental Oil And Gas Disclosures (Results Of Operations For Oil And Gas Producing Activities) (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]

Production (lifting) costs

$ 696,607

$ 425,369

$ 385,338

180,243

135,685

119,836

Hurricane repair expense

(4,838)

4,699

(23,332)

Exploration expenses

^[1]

10,914

8,276

24,383

Depreciation, depletion, amortization and accretion

219,915

235,290

169,256

Proved property impairment charges and other

^[2]

133,406

182,133

73,407

Gain on sale or acquisition of oil and gas properties

(4,531)

(6,246)

(1,949)

Gain on oil and gas derivative contracts

(1,088)

(89,485)

Selling and administrative expenses

31,562

26,826

21,554

Pretax income (loss) from producing activities

129,936

(160,206)

91,668

Income tax expense (benefit)

35,858

(62,954)

23,252

Results of oil and gas producing activities

^[3]

94,078

(97,252)

68,416

United States [Member]

Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]

Production (lifting) costs

696,607

425,369

384,375

176,269

131,156

117,565

Hurricane repair expense

(4,838)

4,699

(23,332)

Exploration expenses

^[1]

10,914

8,276

24,383

Depreciation, depletion, amortization and accretion

219,915

235,243

167,812

Proved property impairment charges and other

^[2]

113,439

177,138

73,407

Gain on sale or acquisition of oil and gas properties

(4,531)

(287)

(1,949)

Gain on oil and gas derivative contracts

(1,088)

(89,485)

Selling and administrative expenses

31,455

26,714

21,495

Pretax income (loss) from producing activities

153,984

(156,482)

94,479

Income tax expense (benefit)

45,233

(62,526)

24,280

Results of oil and gas producing activities

^[3]

108,751

(93,956)

70,199

Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]

Production (lifting) costs

963

3,974

4,529

2,271

Depreciation, depletion, amortization and accretion

1,444

Proved property impairment charges and other

^[2]

19,967

4,995

Gain on sale or acquisition of oil and gas properties

(5,959)

Selling and administrative expenses

107

112

Pretax income (loss) from producing activities

(24,048)

(3,724)

(2,811)

Income tax expense (benefit)

(9,375)

(428)

(1,028)

Results of oil and gas producing activities

^[3]

$ (14,673)

$ (3,296)

$ (1,783)

[1]	See Note 5 for additional information related to the components of our exploration costs, including impairment charges for expiring unproved leases.
[2]	Other amounts represent additional asset retirement expense recorded upon completion of a field's abandonment.
[3]	Excludes net interest expense and other.

Supplemental Oil And Gas Disclosures (Estimated Quantities Of Proved Oil And Gas Reserves) (Details)

1 Months Ended

12 Months Ended

Jun. 30, 2010

Feb. 28, 2010

Aug. 31, 2006

Dec. 31, 2011

MMcf

MBbls

Dec. 31, 2010

MMcf

MBbls

Dec. 31, 2009

MMcf

MBbls

Dec. 31, 2008

MMcf

MBbls

Reclassification of estimate proved reserves

50.00%

100.00%

50.00%

87,000,000,000

Oil Reserves [Member]

24,818

29,727

32,012

(1.8)

3,475

^[1]

(1,555)

^[2]

232

(5,785)

(3,354)

(2,741)

(205)

(1)

386

225

Total proved developed reserves | MBbls

22,689

24,818

29,727

12,754

11,796

14,850

12,809

Natural Gas Liquids Reserves [Member]

227,264

399,315

473,406

131,000,000,000

(108,947)

^[3]

(144,954)

^[4]

(45,370)

^[5]

(17,458)

(27,097)

(27,334)

(4,109)

(7,933)

271

6,546

Total proved developed reserves | MMcf

97,021

227,264

399,315

59,859

75,664

124,763

257,744

United States [Member] | Oil Reserves [Member]

24,818

29,727

32,012

3,475

^[1]

(1,555)

^[2]

232

(5,785)

(3,354)

(2,741)

(205)

(1)

386

225

Total proved developed reserves | MBbls

22,689

24,818

29,727

12,754

11,796

14,850

12,809

United States [Member] | Natural Gas Liquids Reserves [Member]

227,264

387,315

460,456

(108,947)

^[3]

(132,954)

^[4]

(44,615)

^[5]

(17,458)

(27,097)

(27,139)

(4,109)

(7,933)

271

6,546

Total proved developed reserves | MMcf

97,021

227,264

387,315

59,859

75,664

124,763

256,794

United Kingdom [Member] | Oil Reserves [Member]

^[1]

^[2]

Purchases of reserves in place

Total proved developed reserves | MBbls

United Kingdom [Member] | Natural Gas Liquids Reserves [Member]

^[6]

12,000

12,950

^[6]

^[3]

(12,000)

^[4]

(755)

^[5]

Purchases of reserves in place

^[6]

(195)

^[6]

^[6]

^[6]

Total proved developed reserves | MMcf

^[6]

12,000

^[6]

950

Camelot Field [Member]

Additional ownership percentage acquired

Ownership percentage

50.00%

50.00%

Bushwood Field [Member] | Natural Gas Liquids Reserves [Member]

50.00%

Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]

38,000,000,000

[1]	The positive revision reflects the better than expected production volumes primarily from our Phoenix field at Green Canyon Blocks 236, 237, 238 and 282 since it began production in October 2010.
[2]	Includes an approximate 1.8 MMBbls decrease 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 of our producing fields, most notably our Bushwood field at Garden Banks Blocks 462/463/506/507, as well as changes in the field economics of some of our other oil and gas properties. The changes in field economics primarily affected properties that were either close to the end of their production life or in which we had proved undeveloped reserves, which would have been required to be developed in the near term. The decision not to develop these properties in light of these economic changes was also driven by our desire to pursue potential alternatives to divest 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 oil spill from the Macondo well.
[3]	Decrease primarily represents a reclassification of estimate 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 our Bushwood field, where we reclassified approximately 87 Bcf at December 31, 2011.
[4]	Includes an approximate 131 Bcf decrease 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 of our producing fields, most notably our Bushwood field at Garden Banks Blocks 462/463/506/507, as well as changes in the field economics of some of our other oil and gas properties. The changes in field economics primarily affected properties that were either close to the end of their production life or in which we had proved undeveloped reserves, which would have been required to be developed in the near term. The decision not to develop these properties in light of these economic changes was also driven by our desire to pursue potential alternatives to divest 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 oil spill from the Macondo well.
[5]	Includes a 38 Bcfe reduction of the proved reserves at Bushwood field reflecting certain reservoir issues for our Noonan Gas wells subsequent to their reestablishing sustained production in January 2009 and new geologic data collected throughout 2009.
[6]	Reflects 50% ownership in the Camelot field's reserves in 2009 and 2008. In February 2010 we acquired the other 50% ownership interest in the Camelot field. We no longer have any development plans for the field and we intend to fully abandon the field in 2012 in accordance with the applicable regulations in the United Kingdom. See Note 5 for additional information regarding our Camelot field.

Supplemental Oil And Gas Disclosures (Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves) (Details) - USD ($)
$ in Thousands

1 Months Ended

12 Months Ended

Feb. 28, 2010

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Future cash inflows

$ 2,811,956

$ 2,925,744

$ 3,227,146

Development and abandonment

(419,617)

(583,050)

(637,466)

(584,623)

(603,070)

(789,533)

Future net cash flows before income taxes

1,807,716

1,739,624

1,800,147

Future income tax expense

(477,630)

(430,153)

(418,602)

Future net cash flows

1,330,086

1,309,471

1,381,545

Discount at 10% annual rate

(266,954)

(318,404)

(390,485)

Standardized measure of discounted future net cash flows

1,063,132

991,067

991,060

United States [Member]

Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]

Future cash inflows

2,811,956

2,925,744

3,166,306

Development and abandonment

(419,617)

(583,050)

(618,391)

(557,323)

(590,870)

(755,726)

Future net cash flows before income taxes

1,835,016

1,751,824

1,792,189

Future income tax expense

(477,630)

(430,153)

(417,042)

Future net cash flows

1,357,386

1,321,671

1,375,147

Discount at 10% annual rate

(266,954)

(318,404)

(387,036)

Standardized measure of discounted future net cash flows

1,090,432

1,003,267

988,111

Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]

Future cash inflows

^[1]

60,840

Development and abandonment

^[1]

(19,075)

^[1]

(27,300)

(12,200)

(33,807)

Future net cash flows before income taxes

^[1]

(27,300)

(12,200)

7,958

Future income tax expense

^[1]

(1,560)

Future net cash flows

^[1]

(27,300)

(12,200)

6,398

Discount at 10% annual rate

^[1]

(3,449)

Standardized measure of discounted future net cash flows

^[1]

$ (27,300)

$ (12,200)

$ 2,949

Camelot Field [Member]

Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]

Ownership percentage

50.00%

Additional ownership percentage acquired

50.00%

[1]	Reflects 50% ownership in the Camelot field's reserves in 2009. In February 2010 we acquired the other 50% ownership interest in the Camelot field (Note 5).

Supplemental Oil And Gas Disclosures (Schedule Of Base Prices Used In Determining The Standardized Measure) (Details)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Oil Price Per Bbl [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Base prices, Barrel	105.35	77.55	58.05
Oil Price Per Bbl [Member] \| United States [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Base prices, Barrel	105.35	77.55	58.05
Oil Price Per Bbl [Member] \| United Kingdom [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Base prices, Barrel
Natural Gas Prices Per Mcf [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Base prices, Mcf	4.34	4.40	3.76
Natural Gas Prices Per Mcf [Member] \| United States [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Base prices, Mcf	4.34	4.40	3.72
Natural Gas Prices Per Mcf [Member] \| United Kingdom [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Base prices, Mcf			5.07

Supplemental Oil And Gas Disclosures (Changes In Standardized Measure Of Discounted Future Net Cash Flows) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Supplemental Oil and Gas Disclosures [Abstract]
Standardized measure, beginning of year	$ 991,067	$ 991,060	$ 1,312,155
Sales, net of production costs	(516,895)	(294,212)	(265,501)
Net change in prices and production costs	414,426	577,687	(245,883)
Changes in future development costs	(108,007)	84,907	(16,905)
Development costs incurred	168,005	55,646	74,133
Accretion of discount	131,464	129,083	161,254
Net change in income taxes	(54,613)	(41,115)	257,919
Purchases of reserves in place
Extensions and discoveries	29,479		10,457
Sales of reserves in place	(14,324)		(30,124)
Net change due to revision in quantity estimates	(186,197)	(422,987)	(85,450)
Changes in production rates (timing) and other	208,727	(89,002)	(180,995)
Total	72,065	7	(321,095)
Standardized measure, end of year	$ 1,063,132	$ 991,067	$ 991,060

Derivative Instruments And Hedging Activities (Derivatives Designated As Hedging Instruments) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Derivatives, Fair Value [Line Items]
Asset derivatives designated as hedging instruments	$ 22,708	$ 5,324
Liability derivatives designated as hedging instruments	2,799	31,634
Other Current Assets [Member] \| Oil Contracts [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	5,324
Other Assets [Member] \| Natural Gas Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives designated as hedging instruments	857
Other Assets [Member] \| Interest Rate Swaps [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives designated as hedging instruments	327
Other Long-Term Liabilities [Member] \| Oil Contracts [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives designated as hedging instruments	1,711
Other Long-Term Liabilities [Member] \| Natural Gas Contracts [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives designated as hedging instruments		913
Other Long-Term Liabilities [Member] \| Interest Rate Swaps [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives designated as hedging instruments		115
Accrued Liabilities [Member] \| Oil Contracts [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives designated as hedging instruments	886	28,855
Accrued Liabilities [Member] \| Interest Rate Swaps [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives designated as hedging instruments	$ 202	$ 1,751

Derivative Instruments And Hedging Activities (Derivatives Not Designated As Hedging Instruments) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Derivatives, Fair Value [Line Items]
Asset derivatives not designated as hedging instruments	$ 55	$ 190
Liability derivatives not designated as hedging instruments	159
Other Current Assets [Member] \| Foreign Exchange Forwards [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives not designated as hedging instruments	55	148
Other Assets [Member] \| Foreign Exchange Forwards [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives not designated as hedging instruments		42
Accrued Liabilities [Member] \| Foreign Exchange Forwards [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives not designated as hedging instruments	$ 159

Derivative Instruments And Hedging Activities (Impact Of Derivative Instruments On Accumulated Comprehensive Income (Loss)) (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Unrealized gains (losses)

$ 30,043

^[1]

$ (7,699)

$ (18,918)

(382)

(1,568)

5,237

Oil And Natural Gas Commodity Contracts [Member]

Unrealized gains (losses)

28,749

^[1]

(6,486)

(19,092)

13,400

Foreign Exchange Forwards [Member]

Interest Rate Swaps [Member]

(538)

Unrealized gains (losses)

1,294

^[1]

$ (1,213)

$ 712

$ (100)

[1]

Derivative Instruments And Hedging Activities (Gain (Loss) Reclassified From Accumulated OCI Into Income) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Derivatives, Fair Value [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income	$ (23,669)	$ 23,726	$ 15,876
Oil And Natural Gas Commodity Contracts [Member] \| Gain On Oil And Gas Derivative Contracts [Member]
Derivatives, Fair Value [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income	(21,659)	25,575	16,972
Interest Rate Swaps [Member] \| Net Interest Expense [Member]
Derivatives, Fair Value [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income	$ (2,010)	$ (1,849)	$ (1,096)

Derivative Instruments And Hedging Activities (Impact Of Non-Designated Derivative Instruments On Income Statement) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Derivatives, Fair Value [Line Items]
Gain (Loss) Recognized in Income on Derivatives	$ 249	$ (1,472)	$ 92,296
Natural Gas Contracts [Member] \| Gain On Oil And Gas Derivative Contracts [Member]
Derivatives, Fair Value [Line Items]
Gain (Loss) Recognized in Income on Derivatives		1,088	89,485
Interest Rate Swaps [Member] \| Other Income (Expense) [Member]
Derivatives, Fair Value [Line Items]
Gain (Loss) Recognized in Income on Derivatives			(468)
Foreign Exchange Forwards [Member] \| Other Income (Expense) [Member]
Derivatives, Fair Value [Line Items]
Gain (Loss) Recognized in Income on Derivatives	$ 249	$ (2,560)	$ 3,279

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

6 Months Ended

12 Months Ended

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2010

Sep. 30, 2010

Jun. 30, 2010

Mar. 31, 2010

Sep. 30, 2009

Jun. 30, 2009

Jun. 30, 2010

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Net income applicable to common shareholders

$ 396,185

$ 372,496

$ 338,319

$ 291,607

$ 306,337

$ 392,669

$ 299,262

$ 201,570

$ 1,398,607

$ 1,199,838

$ 1,461,687

Gross profit

31,023

^[1]

122,295

^[1]

100,198

^[1]

77,076

^[1]

16,082

^[2]

86,552

^[2]

(94,818)

^[2]

25,856

^[2]

330,592

33,672

243,162

Net income

16,763

^[3]

46,026

^[3]

41,323

^[3]

25,867

^[3]

(49,811)

^[4]

26,171

^[4]

(85,517)

^[4]

(17,831)

^[4]

129,979

(126,988)

156,054

$ 16,753

$ 46,016

$ 41,313

$ 25,857

$ (49,821)

$ 26,161

$ (85,551)

$ (17,891)

$ 129,939

$ (127,102)

$ 101,867

Basic earnings per common share

$ 0.16

$ 0.43

$ 0.39

$ 0.24

$ (0.48)

$ 0.25

$ (0.82)

$ (0.17)

$ 1.23

$ (1.22)

$ 1.01

Diluted earnings per common share

$ 0.16

$ 0.43

$ 0.39

$ 0.24

$ (0.48)

$ 0.25

$ (0.82)

$ (0.17)

$ 1.22

$ (1.22)

$ 0.96

$ 16,700

$ 16,743

^[5]

Other than temporary impairment non-cash

$ 107,500

$ 2,400

$ 22,700

$ 0

9,200

$ 900

$ 159,900

$ 11,100

$ 64,600

$ 48,200

132,603

181,083

$ 120,550

$ 2,200

10,563

2,240

Reserve Impairment [Member]

28,200

20,000

Australian Well Invention Equipment [Member]

79,300

Tax benefit related to reorganization

6,600

31,300

275,499

198,011

$ 124,896

$ 5,000

$ 20,000

$ 5,000

15,900

Sapura [Member]

Other than temporary impairment non-cash

$ 10,600

[1]	Includes oil and gas property impairment charges totaling $22.7 million in the second quarter of 2011 and $2.4 million in the third quarter of 2011. Our fourth quarter of 2011 includes a total of $107.5 million of impairment charges, including $79.3 million related to eight oil and gas properties to reduce them to their estimated fair value at December 31, 2011 and $28.2 million to increase certain non-producing properties estimated asset retirement obligations, including $15.9 million related to our one U.K. oil and gas property (Note 5). The fourth quarter also includes a $6.6 million impairment charge to reduce our Australian well intervention equipment to is estimated fair value at December 31, 2011. There were no asset impairment charges in the first quarter of 2011.
[2]	Includes oil and gas property impairment charges totaled $11.1 in the first quarter of 2010, $159.9 million in the second quarter of 2010, $0.9 million in the third quarter of 2010 and $9.2 million in the fourth quarter of 2010.
[3]	Our fourth quarter 2011 includes a $10.6 million other than temporary impairment loss on our equity investment in our Australian joint venture (Note 7). The fourth quarter also includes a $31.3 million tax benefit related to reorganization of our Australian well intervention business.
[4]	Includes an impairment charges of $16.7 million to reduce goodwill associated with our Australia well intervention business in the fourth quarter of 2010 (Note 2).
[5]	Amount reflects full write off of goodwill associated with our WOSEA operations.

Subsequent Event (Details) $ in Millions	Feb. 21, 2012 USD ($)
Subsequent Event [Line Items]
Amortization of the principal balance	$ 5
Term Loan A [Member]
Subsequent Event [Line Items]
Long Term Debt	$ 100

Condensed Consolidated Guarantor And Non-Guarantor Financial Information (Schedule Of Condensed Consolidating Balance Sheets) (Details) - USD ($)
$ in Thousands

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Dec. 31, 2008

$ 546,465

$ 391,085

$ 270,673

$ 223,613

238,781

177,293

37,375

49,411

6,099

121,621

116,966

944,242

740,854

Equity investments in unconsolidated affiliates

2,331,327

2,527,080

2,863,706

175,656

187,031

Goodwill, net

62,215

62,494

78,643

^[1]

704,300

68,907

74,561

3,582,347

3,592,020

3,779,533

147,043

159,381

239,963

198,237

1,293

7,877

10,179

396,176

367,797

1,147,444

1,347,753

Asset retirement obligations

417,610

413,639

161,208

170,410

9,368

5,777

Convertible preferred stock

2,131,806

2,305,376

1,000

1,449,541

1,285,644

1,427,462

1,513,776

3,582,347

3,592,020

Helix [Member]

495,484

376,434

258,742

148,704

79,290

61,846

10,530

11,990

80,388

19,334

68,627

63,306

734,319

532,910

(147,187)

1,906

Equity investments in affiliates

230,946

217,153

1,952,392

1,998,289

Due from subsidiaries/parent

53,425

43,971

64,655

95,398

2,888,550

2,889,627

39,280

60,308

115,921

58,074

3,000

4,326

158,201

122,708

1,042,155

1,237,587

231,255

185,453

4,150

1,421

Convertible preferred stock

1,435,761

1,547,169

1,000

1,451,789

1,341,458

2,888,550

2,889,627

Guarantors [Member]

2,434

3,294

2,522

4,983

117,767

91,659

155

48,661

49,557

169,017

144,510

315,821

263,920

Equity investments in affiliates

1,422,326

1,605,906

37,239

29,899

Goodwill, net

45,107

Due from subsidiaries/parent

36,453

38,324

430,496

105,434

2,456,459

2,233,100

82,750

56,107

97,692

107,874

97,692

36,678

278,134

200,659

Asset retirement obligations

88,625

135,101

161,208

170,410

4,647

3,691

532,614

509,861

1,923,845

1,723,239

2,456,459

2,233,100

Non-Guarantors [Member]

48,547

11,357

$ 9,409

$ 69,926

41,724

23,788

26,690

37,421

7,195

10,159

12,889

127,120

92,650

(102,826)

(171,513)

Equity investments in unconsolidated affiliates

682,899

709,082

175,656

187,031

Goodwill, net

17,108

17,387

16,809

21,900

916,766

856,537

25,013

42,966

26,350

32,289

217

10,377

14,301

61,957

89,556

105,289

110,166

103,552

98,968

571

665

Due to parent

98,285

120,884

369,654

420,239

547,112

436,298

Consolidating Entries [Member]

916,766

856,537

(80,388)

(20,430)

(5,826)

(8,786)

(86,214)

(29,216)

(65,808)

(94,313)

Equity investments in affiliates

(4,844)

(5,061)

(1,989,631)

(2,028,188)

Due from subsidiaries/parent

(37,780)

(29,634)

(495,151)

(200,832)

(2,679,428)

(2,387,244)

(96,616)

(36,678)

(5,500)

(8,448)

(102,116)

(45,126)

(5,822)

(5,883)

Due to parent

(98,285)

(120,884)

(206,223)

(171,893)

(2,473,205)

(2,215,351)

$ (2,679,428)

$ (2,387,244)

[1]	Prior to 2009, we fully impaired our oil and gas related goodwill ($704.3 million) as well as the $8.3 million of goodwill associated with our former reservoir consulting business.

Condensed Consolidated Guarantor And Non-Guarantor Financial Information (Schedule Of Condensed Consolidating Statements Of Operations) (Details) - USD ($)
$ in Thousands

1 Months Ended

3 Months Ended

12 Months Ended

Jan. 31, 2009

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2010

Sep. 30, 2010

Jun. 30, 2010

Mar. 31, 2010

Sep. 30, 2009

Jun. 30, 2009

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

$ 396,185

$ 372,496

$ 338,319

$ 291,607

$ 306,337

$ 392,669

$ 299,262

$ 201,570

$ 1,398,607

$ 1,199,838

$ 1,461,687

924,498

976,807

1,073,592

107,500

2,400

22,700

9,200

900

159,900

11,100

$ 64,600

$ 48,200

132,603

181,083

120,550

Exploration expense

^[1]

10,914

8,276

24,383

31,023

^[2]

122,295

^[2]

100,198

^[2]

77,076

^[2]

16,082

^[3]

86,552

^[3]

(94,818)

^[3]

25,856

^[3]

330,592

33,672

243,162

Gain on oil and gas derivative commodity contracts

(16,700)

(16,743)

^[4]

1,088

89,485

4,525

9,405

2,019

(99,589)

(122,078)

(130,851)

Equity in earnings of unconsolidated affiliates

^[5]

235,528

(94,656)

203,815

22,215

19,469

32,329

$ (2,900)

753

77,343

(2,200)

(10,563)

(2,240)

(99,953)

(86,324)

(51,495)

147,980

(163,751)

261,992

14,903

(39,598)

95,822

Discontinued operations, net of tax

133,077

(124,153)

166,170

9,581

Net income (loss), including noncontrolling interests

133,077

(124,153)

175,751

Net income applicable to noncontrolling interests

(3,098)

(2,835)

(19,697)

Preferred stock dividends

16,763

^[6]

46,026

^[6]

41,323

^[6]

25,867

^[6]

(49,811)

^[7]

26,171

^[7]

(85,517)

^[7]

(17,831)

^[7]

129,979

(126,988)

156,054

(40)

(114)

(54,187)

Net income (loss) applicable to Helix common shareholders

$ 16,753

$ 46,016

$ 41,313

$ 25,857

$ (49,821)

$ 26,161

$ (85,551)

$ (17,891)

129,939

(127,102)

101,867

Helix [Member]

84,748

183,147

211,222

72,902

124,722

162,225

11,846

58,425

48,997

(6)

3,159

(74,205)

(67,165)

(52,101)

Equity in earnings (losses) of affiliates

(62,365)

(5,581)

(3,104)

262,990

(60,443)

145,340

753

77,343

(2,240)

(158,299)

(59,522)

(18,188)

43,079

(127,786)

201,391

(63,242)

(9,175)

43,417

Discontinued operations, net of tax

157,974

Net income (loss), including noncontrolling interests

106,321

(118,611)

158,073

Preferred stock dividends

106,321

(118,611)

158,073

(40)

(114)

(54,187)

Net income (loss) applicable to Helix common shareholders

106,281

(118,725)

103,886

Guarantors [Member]

1,059,255

801,503

701,706

673,415

659,859

484,802

112,636

176,088

120,550

Exploration expense

10,914

8,276

24,383

Gain on oil and gas derivative commodity contracts

262,290

(42,720)

71,971

1,088

89,485

4,531

287

2,019

(38,915)

(34,233)

(28,520)

Equity in earnings (losses) of affiliates

227,906

(75,578)

134,955

7,340

8,473

(1,725)

(32,345)

(21,677)

(16,978)

202,901

(88,782)

116,252

69,890

(35,299)

39,855

Net income (loss), including noncontrolling interests

76,397

133,011

(53,483)

76,397

Net income (loss) applicable to Helix common shareholders

133,011

(53,483)

76,397

133,011

(53,483)

76,397

Non-Guarantors [Member]

367,114

334,726

648,705

289,462

297,056

521,689

19,967

4,995

57,685

32,675

127,016

(16,743)

5,959

12,101

(22,482)

(53,919)

Equity in earnings of unconsolidated affiliates

69,786

(591)

73,097

22,215

19,469

33,229

(10,563)

67,181

(5,125)

(15,341)

148,619

13,753

90,985

8,186

9,405

13,571

Discontinued operations, net of tax

77,414

9,482

Net income (loss), including noncontrolling interests

140,433

4,348

86,896

Net income (loss) applicable to Helix common shareholders

140,433

4,348

86,896

140,433

4,348

86,896

Consolidating Entries [Member]

(112,510)

(119,538)

(99,946)

(111,281)

(104,830)

(95,124)

(1,229)

(14,708)

(4,822)

1,430

1,802

3,689

Equity in earnings of unconsolidated affiliates

201

(12,906)

(1,133)

(900)

Equity in earnings (losses) of affiliates

(270,330)

51,970

(143,615)

23,510

(988)

(246,619)

39,064

(146,636)

(4,529)

(1,021)

Net income (loss), including noncontrolling interests

(145,615)

(246,688)

43,593

(145,615)

Net income applicable to noncontrolling interests

(3,098)

(2,835)

(19,697)

Net income (loss) applicable to Helix common shareholders

(249,786)

40,758

(165,312)

$ (249,786)

$ 40,758

$ (165,312)

[1]	See Note 5 for additional information related to the components of our exploration costs, including impairment charges for expiring unproved leases.
[2]	Includes oil and gas property impairment charges totaling $22.7 million in the second quarter of 2011 and $2.4 million in the third quarter of 2011. Our fourth quarter of 2011 includes a total of $107.5 million of impairment charges, including $79.3 million related to eight oil and gas properties to reduce them to their estimated fair value at December 31, 2011 and $28.2 million to increase certain non-producing properties estimated asset retirement obligations, including $15.9 million related to our one U.K. oil and gas property (Note 5). The fourth quarter also includes a $6.6 million impairment charge to reduce our Australian well intervention equipment to is estimated fair value at December 31, 2011. There were no asset impairment charges in the first quarter of 2011.
[3]	Includes oil and gas property impairment charges totaled $11.1 in the first quarter of 2010, $159.9 million in the second quarter of 2010, $0.9 million in the third quarter of 2010 and $9.2 million in the fourth quarter of 2010.
[4]	Amount reflects full write off of goodwill associated with our WOSEA operations.
[5]	Includes $16.7 million of goodwill impairment charge for year ending December 31, 2010 related to our contracting services segment. Also includes approximately $132.6 million, $181.1 million and $120.6 million of asset impairment charges for certain oil and gas properties for the years ended December 31, 2011, 2010 and 2009 respectively.
[6]	Our fourth quarter 2011 includes a $10.6 million other than temporary impairment loss on our equity investment in our Australian joint venture (Note 7). The fourth quarter also includes a $31.3 million tax benefit related to reorganization of our Australian well intervention business.
[7]	Includes an impairment charges of $16.7 million to reduce goodwill associated with our Australia well intervention business in the fourth quarter of 2010 (Note 2).

Condensed Consolidated Guarantor And Non-Guarantor Financial Information (Schedule Of Condensed Consolidating Statements Of Cash Flows) (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended	12 Months Ended
	Jan. 31, 2009	Mar. 31, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Net income (loss), including noncontrolling interests			$ 133,077	$ (124,153)	$ 175,751
Equity in earnings of investments, net of distributions					(6,321)
Other adjustments			434,079	455,607	254,508
Cash provided by operating activities			567,156	331,454	423,938
Net cash used in discontinued operations					(6,261)
Net cash provided by operating activities			567,156	331,454	417,677
Capital expenditures			(219,769)	(206,772)	(423,373)
Acquisition of businesses, net of cash acquired
Investments in equity investments			(2,699)	(8,253)	(1,657)
Distributions from equity investments, net			3,965	10,539	6,742
Increases in restricted cash			1,598	(70)	(6)
Proceeds from insurance reimbursement				16,106
Proceeds from sale of Cal Dive common stock	$ 86,000	$ 3,600	3,588		418,168
Proceeds from sale of Cal Dive common stock					305,173
Proceeds from sales of property			31,000	6,894	23,717
Other, net			32,598
Net cash provided by (used in) investing activities			(182,317)	(181,556)	(89,404)
Net cash provided by discontinued operations					20,872
Net cash used in investing activities			(182,317)	(181,556)	(68,532)
Borrowings on revolvers			109,400		100,000
Repayments on revolvers			(109,400)		(349,500)
Repayments of debt			(212,730)	(8,750)	(28,540)
Loan notes repayment			(1,215)	(2,517)	(2,130)
Deferred financing costs			(9,311)	(2,947)	(6,970)
Preferred stock dividends paid			(40)	(114)	(645)
Repurchases of common stock			(7,604)	(11,680)	(13,995)
Excess tax benefit from stock-based compensation			(1,013)	(3,945)	895
Exercise of stock options, net			2,018	674	176
Net cash used in financing activities			(229,895)	(29,279)	(300,709)
Effect of exchange rate changes on cash and cash equivalents			436	(207)	(1,376)
Net increase in cash and cash equivalents			155,380	120,412	47,060
Balance, beginning of year	223,613	391,085	391,085	270,673	223,613
Balance, end of year			546,465	391,085	270,673
Helix [Member]
Net income (loss), including noncontrolling interests			106,321	(118,611)	158,073
Equity in earnings of affiliates			(262,990)	60,443	(145,340)
Other adjustments			39,860	94,376	26,633
Cash provided by operating activities				36,208	39,366
Net cash provided by operating activities			(116,809)		39,366
Capital expenditures			(32,417)	(56,650)	(35,657)
Acquisition of businesses, net of cash acquired
Proceeds from insurance reimbursement				7,020
Proceeds from sale of Cal Dive common stock			3,588
Proceeds from sale of Cal Dive common stock					504,168
Proceeds from sales of property				6,042
Net cash provided by (used in) investing activities					468,511
Net cash used in investing activities			(28,829)	(43,588)	468,511
Borrowings on revolvers			109,400
Repayments on revolvers			(109,400)		(349,500)
Repayments of debt			(208,085)	(4,326)	(4,326)
Deferred financing costs			(9,311)	(2,947)	(6,970)
Preferred stock dividends paid			(40)	(114)	(645)
Repurchases of common stock			(7,604)	(11,680)	(13,995)
Excess tax benefit from stock-based compensation			(1,013)	(3,945)	895
Exercise of stock options, net			2,018	674	176
Intercompany financing			488,723	147,410	(23,474)
Net cash used in financing activities			264,688	125,072	(397,839)
Net increase in cash and cash equivalents			119,050	117,692	110,038
Balance, beginning of year	148,704	376,434	376,434	258,742	148,704
Balance, end of year			495,484	376,434	258,742
Guarantors [Member]
Net income (loss), including noncontrolling interests			133,011	(53,483)	76,397
Equity in earnings of affiliates			(7,340)	(8,473)	1,725
Other adjustments			353,728	305,649	163,451
Cash provided by operating activities				243,693	241,573
Net cash provided by operating activities			479,399		241,573
Capital expenditures			(174,739)	(121,709)	(245,354)
Acquisition of businesses, net of cash acquired
Increases in restricted cash				(70)	(6)
Proceeds from insurance reimbursement				9,086
Proceeds from sale of Cal Dive common stock
Proceeds from sales of property				852	23,717
Other, net			32,598
Net cash provided by (used in) investing activities					(221,643)
Net cash used in investing activities			(142,141)	(111,841)	(221,643)
Intercompany financing			(338,118)	(131,080)	(22,391)
Net cash used in financing activities			(338,118)	(131,080)	(22,391)
Net increase in cash and cash equivalents			(860)	772	(2,461)
Balance, beginning of year	4,983	3,294	3,294	2,522	4,983
Balance, end of year			2,434	3,294	2,522
Non-Guarantors [Member]
Net income (loss), including noncontrolling interests			140,433	4,348	86,896
Equity in earnings of investments, net of distributions					(7,220)
Other adjustments			40,293	76,865	82,411
Cash provided by operating activities				81,213	162,087
Net cash used in discontinued operations					(6,261)
Net cash provided by operating activities			180,726		155,826
Capital expenditures			(12,613)	(28,413)	(142,362)
Acquisition of businesses, net of cash acquired
Investments in equity investments			(2,699)	(8,253)	(1,657)
Distributions from equity investments, net			3,965	10,539	6,742
Proceeds from sale of Cal Dive common stock
Proceeds from sale of Cal Dive common stock					(112,995)
Net cash provided by (used in) investing activities					(250,272)
Net cash provided by discontinued operations					20,872
Net cash used in investing activities			(11,347)	(26,127)	(229,400)
Borrowings on revolvers					100,000
Repayments of debt			(4,645)	(4,424)	(24,214)
Loan notes repayment			(1,215)	(2,517)	(2,130)
Repurchases of common stock					(86,000)
Intercompany financing			(126,765)	(45,990)	26,777
Net cash used in financing activities			(132,625)	(52,931)	14,433
Effect of exchange rate changes on cash and cash equivalents			436	(207)	(1,376)
Net increase in cash and cash equivalents			37,190	1,948	(60,517)
Balance, beginning of year	$ 69,926	$ 11,357	11,357	9,409	69,926
Balance, end of year			48,547	11,357	9,409
Consolidating Entries [Member]
Net income (loss), including noncontrolling interests			(246,688)	43,593	(145,615)
Equity in earnings of investments, net of distributions					899
Equity in earnings of affiliates			270,330	(51,970)	143,615
Other adjustments			198	(21,283)	(17,987)
Cash provided by operating activities				(29,660)	(19,088)
Net cash provided by operating activities			23,840		(19,088)
Acquisition of businesses, net of cash acquired
Proceeds from sale of Cal Dive common stock
Proceeds from sale of Cal Dive common stock					(86,000)
Net cash provided by (used in) investing activities					(86,000)
Net cash used in investing activities					(86,000)
Repurchases of common stock					86,000
Intercompany financing			(23,840)	29,660	19,088
Net cash used in financing activities			$ (23,840)	$ 29,660	$ 105,088

Label	Element	Value
Reservoir Consulting Business [Member]
Goodwill	us-gaap_Goodwill	$ 8,300,000