Edgar Filing: HELIX ENERGY SOLUTIONS GROUP INC

form10-q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

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

Commission File Number 001-32936

HELIX ENERGY SOLUTIONS GROUP, INC.

(Exact name of registrant as specified in its charter)

Minnesota (State or other jurisdiction of incorporation or organization)		95–3409686 (I.R.S. Employer Identification No.)

400 North Sam Houston Parkway East Suite 400 Houston, Texas (Address of principal executive offices)		77060 (Zip Code)

(281) 618–0400

(Registrant's telephone number, including area code)

NOT APPLICABLE

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

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

Yes

[ √ ]

[ ]

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

Yes

[ √ ]

[ ]

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

Large accelerated filer

[ √ ]

Accelerated filer

[ ]

Non-accelerated filer

[ ]

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

Yes

[ ]

[ √ ]

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

TABLE OF CONTENTS


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

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

	June 30,			December 31,
	2011			2010
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	414,189		$	391,085
Accounts receivable — Trade, net of allowance for uncollectible accounts of $4,395 and $4,527, respectively		212,406			177,293
Unbilled revenue		18,325			33,712
Costs in excess of billing		1,978			15,699
Other current assets		110,334			123,065
Total current assets		757,232			740,854
Property and equipment		4,586,583			4,486,077
Less — accumulated depreciation		(2,111,273	)		(1,958,997	)
		2,475,310			2,527,080
Other assets:
Equity investments		188,772			187,031
Goodwill		62,902			62,494
Other assets, net		76,421			74,561
Total assets	$	3,560,637		$	3,592,020

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	148,142		$	159,381
Accrued liabilities		190,226			198,237
Current maturities of long-term debt		7,759			10,179
Total current liabilities		346,127			367,797
Long-term debt		1,239,893			1,347,753
Deferred income taxes		431,821			413,639
Asset retirement obligations		166,458			170,410
Other long-term liabilities		5,432			5,777
Total liabilities		2,189,731			2,305,376

Convertible preferred stock		1,000			1,000

Commitments and contingencies
Shareholders’ equity:
Common stock, no par, 240,000 shares authorized, 105,948 and 105,592 shares issued, respectively		911,393			906,957
Retained earnings		459,875			392,705
Accumulated other comprehensive loss		(27,956	)		(39,058	)
Total controlling interest shareholders’ equity		1,343,312			1,260,604
Noncontrolling interests		26,594			25,040
Total equity		1,369,906			1,285,644
Total liabilities and shareholders’ equity	$	3,560,637		$	3,592,020

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

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

(in thousands, except per share amounts)

		Three Months Ended
		June 30,
		2011			2010

Net revenues:
Contracting services	$	165,861		$	196,676
Oil and gas		172,458			102,586
		338,319			299,262

Cost of sales:
Contracting services		116,521			140,126
Oil and gas		98,879			94,092
Oil and gas property impairments		22,721			159,862
		238,121			394,080

Gross profit (loss)		100,198			(94,818	)

Gain on oil and gas derivative contracts		—			2,482
Gain (loss) on the sale or acquisition of assets, net		(22	)		(14	)
Selling and administrative expenses		(23,758	)		(24,546	)
Income (loss) from operations		76,418			(116,896	)
Equity in earnings of investments		5,887			1,656
Net interest expense		(25,278	)		(20,523	)
Other income (expense)		1,253			(1,676	)
Income (loss) before income taxes		58,280			(137,439	)
Provision (benefit) for income taxes		16,171			(52,366	)
Net income (loss), including noncontrolling interests		42,109			(85,073	)
Less net income applicable to noncontrolling interests		(786	)		(444	)
Net income (loss) applicable to Helix		41,323			(85,517	)
Preferred stock dividends		(10	)		(34	)
Net income (loss) applicable to Helix common shareholders	$	41,313		$	(85,551	)

Earnings (loss) per share of common stock:
Basic	$	0.39		$	(0.82	)
Diluted	$	0.39		$	(0.82	)

Weighted average common shares outstanding:
Basic		104,673			104,125
Diluted		105,140			104,125

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

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

(in thousands, except per share amounts)

		Six Months Ended
		June 30,
		2011			2010

Net revenues:
Contracting services	$	288,609		$	307,531
Oil and gas		341,317			193,301
		629,926			500,832

Cost of sales:
Contracting services		223,428			226,374
Oil and gas		206,503			172,446
Oil and gas property impairments		22,721			170,974
		452,652			569,794

Gross profit (loss)		177,274			(68,962	)

Gain on oil and gas derivative contracts		—			2,482
Gain (loss) on sale or acquisition of assets, net		(6	)		6,233
Selling and administrative expenses		(48,739	)		(65,047	)
Income (loss) from operations		128,529			(125,294	)
Equity in earnings of investments		11,537			6,711
Gain on sale of Cal Dive common stock		753			—
Net interest expense		(49,514	)		(36,158	)
Other income (expense)		3,160			(7,261	)
Income (loss) before income taxes		94,465			(162,002	)
Provision (benefit) for income taxes		25,721			(59,927	)
Net income (loss), including noncontrolling interests		68,744			(102,075	)
Less net income applicable to noncontrolling interests		(1,554	)		(1,273	)
Net income (loss) applicable to Helix		67,190			(103,348	)
Preferred stock dividends		(20	)		(94	)
Net income (loss) applicable to Helix common shareholders	$	67,170		$	(103,442	)

Earnings (loss) per share of common stock:
Basic	$	0.63		$	(1.00	)
Diluted	$	0.63		$	(1.00	)

Weighted average common shares outstanding:
Basic		104,573			103,610
Diluted		105,024			103,610

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

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(in thousands)

		Six Months Ended
		June 30,
		2011			2010
Cash flows from operating activities:
Net income (loss), including noncontrolling interests	$	68,744		$	(102,075	)
Adjustments to reconcile net income (loss), including noncontrolling interests to net cash provided by operating activities
Depreciation and amortization		167,170			146,268
Asset impairment charge and dry hole expense		29,352			170,784
Amortization of deferred financing costs		4,777			3,768
Stock compensation expense		4,938			4,589
Amortization of debt discount		4,414			4,136
Deferred income taxes		23,864			(54,749	)
Excess tax benefit from stock-based compensation		1,196			2,163
Gain on investment in Cal Dive common stock		(753	)		—
(Gain) loss on sale or acquisition of assets		6			(6,233	)
Unrealized (gain) loss on derivative contracts		(34	)		2,813
Changes in operating assets and liabilities:
Accounts receivable, net		(18,207	)		(30,591	)
Other current assets		12,712			16,477
Income tax payable		(4,154	)		(10,811	)
Accounts payable and accrued liabilities		(27,070	)		28,027
Oil and gas asset retirement costs		(16,073	)		(28,727	)
Other noncurrent, net		(309	)		(9,439	)
Net cash provided by operating activities		250,573			136,400

Cash flows from investing activities:
Capital expenditures		(106,122	)		(135,612	)
Investments in equity investments		(2,699	)		(6,307	)
Distributions from equity investments, net		1,593			8,132
Proceeds from sale of Cal Dive common stock		3,588			—
Insurance recovery for capital items		—			16,106
Decrease in restricted cash		863			109
Net cash used in investing activities		(102,777	)		(117,572	)

Cash flows from financing activities:
Borrowing under revolving credit facility		109,400			—
Repayment of revolving credit facility		(109,400	)		—
Repayment of Helix Term Loan		(111,191	)		(2,163	)
Repayment of MARAD borrowings		(2,294	)		(2,403	)
Loan notes repayment		(1,213	)		(1,167	)
Deferred financing costs		(9,014	)		(2,792	)
Preferred stock dividends paid		(20	)		(94	)
Repurchases of common stock		(1,012	)		(9,127	)
Excess tax benefit from stock-based compensation		(1,196	)		(2,163	)
Exercise of stock options, net		1,672			163
Net cash used in financing activities		(124,268	)		(19,746	)

Effect of exchange rate changes on cash and cash equivalents		(424	)		246
Net increase (decrease) in cash and cash equivalents		23,104			(672	)
Cash and cash equivalents:
Balance, beginning of year		391,085			270,673
Balance, end of period	$	414,189		$	270,001

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

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 – Basis of Presentation

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

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

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

Note 2 – Company Overview

We are an international offshore energy company that provides reservoir development solutions and other contracting services to the energy market as well as to our own oil and gas properties. Our Contracting Services segment utilizes our vessels, offshore equipment and methodologies to deliver services that may reduce finding and development costs and encompass the complete lifecycle of an offshore oil and gas field. Our Contracting Services are located primarily in the Gulf of Mexico, North Sea, Asia Pacific and West Africa regions. Our Oil and Gas segment engages in exploration, development and production activities. Our oil and gas operations are exclusively located in the Gulf of Mexico.

Contracting Services Operations

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

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Oil and Gas Operations

Events in Gulf of Mexico

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

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

New Accounting Pronouncement

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

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Note 3 – Details of Certain Accounts

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

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

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

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

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

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

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

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Note 4 – Oil and Gas Properties

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

Depletion expense is determined on a field-by-field basis using the units-of-production method, with depletion rates for leasehold acquisition costs based on estimated total remaining proved reserves. Depletion rates for well and related facility costs are based on estimated total remaining proved developed reserves associated with each individual field. The depletion rates are changed whenever there is an indication of the need for a revision but, at a minimum, are evaluated annually. Any such revisions are accounted for prospectively as a change in accounting estimate.

Impairments

During the three-month period ended June 30, 2011, we recorded impairment charges totaling $22.7 million, including $4.1 million for our only non-domestic oil and gas property (see “United Kingdom Property” below), and for six of our Gulf of Mexico oil and gas properties. These impairment charges primarily reflect a premature end of these fields’ production life either through actual depletion or as a result of capital allocation decisions affecting our third party operated fields. We did not have any impairment of our oil and gas properties in the first quarter of 2011. Following the determination of a significant reduction in our estimates of proved reserves at June 30, 2010, we recorded oil and gas property impairment charges totaling $159.9 million which affected the carrying value of 15 of our Gulf of Mexico oil and gas properties.

In the first quarter of 2010, we recorded $7.0 million of impairment charges primarily resulting from natural gas price declines since year end 2009. The three properties subject to these impairment charges produce natural gas almost entirely. Separately, we also recorded a $4.1 million impairment charge for our U.K oil and gas property.

Exploration and Other

As of June 30, 2011, we capitalized approximately $3.6 million of costs associated with ongoing exploration and/or appraisal activities. Such capitalized costs may be charged against earnings in future periods if management determines that commercial quantities of hydrocarbons have not been discovered or that future appraisal drilling or development activities are not likely to occur.

The following table details the components of exploration expense for the three and six month periods ended June 30, 2011 and 2010 (in thousands):

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

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

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United Kingdom Property

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

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

Asset retirement obligations

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

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

Insurance

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

Note 5 – Statement of Cash Flow Information

We define cash and cash equivalents as cash and all highly liquid financial instruments with original maturities of less than three months. We had restricted cash totaling $34.5 million at June 30, 2011 and $35.3 million at December 31, 2010, all of which was related to funds required to be escrowed to cover the future asset retirement obligations associated with our South Marsh Island Block 130 field. We have fully satisfied the escrow requirements under the escrow agreement. We have used a small portion of these escrowed funds to pay for the initial reclamation activities at the South Marsh Island Block 130 field. Reclamation activities at the field will occur over many years and will be funded with these escrowed amounts. These amounts are reflected in other assets, net in the accompanying condensed consolidated balance sheets.

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

		Six Months Ended
		June 30,
		2011		2010

Interest paid, net of capitalized interest(1)	$	40,220	$	27,847
Income taxes paid	$	7,236	$	6,642

Non-cash investing activities for the six-month periods ended June 30, 2011 and 2010 included $33.7 million and $32.0 million, respectively, of accruals for capital expenditures. The accruals have been reflected in the condensed consolidated balance sheet as an increase in property and equipment and accounts payable.

Note 6 – Equity Investments

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

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

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

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

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Note 7 – Long-Term Debt

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

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

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

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

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

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

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

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

Senior Unsecured Notes

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

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Credit Agreement

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Convertible Senior Notes

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

The Convertible Senior Notes can be converted prior to the stated maturity (March 2025) under certain triggering events specified in the indenture governing the Convertible Senior Notes. To the extent we do not have long-term financing secured to cover the conversion, the Convertible Senior Notes would be classified as a current liability in the accompanying condensed consolidated balance sheet. No conversion triggers were met during either the three or six-month periods ended June 30, 2011 or June 30, 2010. The first dates for early redemption of the Convertible Senior Notes are in December 2012, with the holders of the Convertible Senior Notes being able to put them to us on December 15, 2012 and our being able to call the Convertible Senior Notes at any time after December 20, 2012 (see Note 9 of our 2010 Form 10-K). Effective January 1, 2009 we adopted certain new required accounting standards that required us to discount the principal amount of our Convertible Senior Notes. Following adoption of these accounting standards, the effective interest rate for the Convertible Senior Notes is 6.6%.

Our average share price was below the $32.14 per share conversion price for all the periods presented in this Quarterly Report on Form 10-Q. As a result of our share price being lower than the $32.14 per share conversion price for these periods there are no shares included in our diluted earnings per share calculation associated with the assumed conversion of our Convertible Senior Notes. In the event our average share price exceeds the conversion price, there would be a premium, payable in shares of common stock, in addition to the principal amount, which is paid in cash, and such shares would be issued on conversion. The Convertible Senior Notes are convertible into a maximum 13,303,770 shares of our common stock.

MARAD Debt

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

Other

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

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

Note 8 – Income Taxes

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

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

Note 9 – Comprehensive Income (Loss)

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

		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2011			2010			2011		2010

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

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

	June 30,			December 31,
	2011			2010

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

Note 10 – Earnings Per Share

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

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

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

Three Months Ended

June 30, 2011

June 30, 2010

Income

Diluted:

Net income (loss) per common share – Basic

40,799

104,673

(85,551

)

104,125

Effect of dilutive securities:

Stock options

─

106

─

Undistributed earnings reallocated to participating securities

─

Convertible Senior Notes

─

Convertible preferred stock

361

─

Net income (loss) per common share – Diluted

40,812

105,140

(85,551

)

104,125

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

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

We had a net loss from continuing operations for both the three- and six-month periods ended June 30, 2010. Accordingly, we had no dilutive securities during these reporting periods as their inclusion would have had an anti-dilutive effect on our EPS calculation, meaning it would have increased our reported EPS amount. The following table provides the effect the excluded securities would have had on our diluted shares calculation for the three- and six-month periods ended June 30, 2010 assuming we had earnings from continuing operations (in thousands):

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	Three Months		Six Months
Diluted shares (as reported)		104,125		103,610
Stock options		94		80
Convertible preferred stock		1,195		1,689
Total		105,414		105,379

Note 11 – Stock-Based Compensation Plans

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

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

Date of Grant	Shares		Market Value Per Share		Vesting Period

January 4, 2011		475,804	$	12.14	20% per year over five years
January 4, 2011		4,427		12.14	100% on January 1, 2013
April 1, 2011		2,907		17.20	100% on January 1, 2013
May 11, 2011		21,608		16.14	20% per year over five years

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

For the three- and six-month periods ended June 30, 2011, $2.0 million and $4.9 million, respectively, was recognized as compensation expense related to restricted shares as compared with $2.1 million and $4.6 million during the three- and six-month periods ended June 30, 2010, respectively.

In January 2009, we adopted the 2009 Long-Term Incentive Cash Plan (the “2009 LTI Plan”) to provide long term cash based compensation to eligible employees. Under the terms of the 2009 LTI Plan, the majority of the cash awards are fixed sum amounts payable over a five year vesting period. Some of the cash awards are indexed to our Company common stock and the payment amount at each vesting date will fluctuate based on the common stock’s performance as a result, the compensation expense associated with those awards is re-measured to fair value each reporting period with corresponding changes being recorded as a charge to earnings as appropriate.

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

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

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Note 12 – Business Segment Information

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

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

		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2011			2010			2011			2010
		(in thousands)
Revenues ─
Contracting Services	$	171,353		$	202,317		$	302,890		$	356,517
Production Facilities		20,545			21,391			36,115			22,711
Oil and Gas		172,458			102,586			341,317			193,301
Intercompany elimination		(26,037	)		(27,032	)		(50,396	)		(71,697	)
Total	$	338,319		$	299,262		$	629,926		$	500,832

Income (loss) from operations ─
Contracting Services	$	30,565		$	43,781		$	33,831		$	71,267
Production Facilities (1)		11,920			12,977			17,876			12,940
Oil and Gas		43,064			(154,943	)		96,304			(155,607	)
Corporate (2)		(9,112	)		(12,597	)		(19,553	)		(35,475	)
Intercompany elimination		(19	)		(6,114	)		71			(18,419	)
Total	$	76,418		$	(116,896	)	$	128,529		$	(125,294	)

Equity in earnings of equity investments (Note 6)	$	5,887		$	1,656		$	11,537		$	6,711

(1)

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

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

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

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

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

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

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

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

Note 13 – Related Party Transactions

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

Note 14 – Commitments and Contingencies

Litigation and Claims

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

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Loss Contract

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

Contingencies and Claims

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

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

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

Note 15 – Fair Value Measurements

Fair Value Measurements

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

•		Level 1. Observable inputs such as quoted prices in active markets;
•		Level 2. Inputs, other than the quoted prices in active markets, that are observable either directly or indirectly; and
•		Level 3. Unobservable inputs in which there is little or no market data, which require the reporting entity to develop its own assumptions.

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

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

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

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

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

	Level 1		Level 2 (1)		Level 3		Total		Valuation Technique

Assets:
Oil and gas swaps and collars	$	–	$	7,531	$	–	$	7,531	(c)
Foreign currency forwards		–		305		–		305	(c)

Liabilities:
Oil and gas swaps and collars		–		16,680		–		16,680	(c)
Fair value of long term debt(2)		1,182,173		122,417		–		1,304,590	(a), (b)
Interest rate swaps		–		1,157		–		1,157	(c)
Total net liability	$	1,182,173	$	132,418	$	–	$	1,314,591

(1)

Unless otherwise indicated, the fair value of our Level 2 derivative instruments reflects our best estimate and is based upon exchange or over-the-counter quotations whenever they are available. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, we utilize other valuation techniques or models to estimate market values. These modeling techniques require us to make estimations of future prices, price correlation and market volatility and liquidity. Our actual results may differ from our estimates, and these differences can be positive or negative.

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

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

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

(b)

The estimated fair value of all debt, other than MARAD Debt, was determined using level 1 inputs using the market approach. The fair value of the MARAD debt was determined using a third party evaluation of the remaining average life and outstanding principal balance of the MARAD indebtedness as compared to other governmental obligations in the market place with similar terms. The fair value of the MARAD debt was estimated using level 2 fair value inputs using the cost approach.

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

In the second quarter of 2011, we recorded impairment charge on seven of our oil and gas properties. These impairment charges reduced these oil and gas properties to their estimated fair value, which, for six of the properties, including our only U.K. oil and gas property, was zero and for the remaining property its estimated fair value was $2.9 million at June 30, 2011. At June 30, 2010 we impaired 15 of our Gulf of Mexico properties as a result of reductions in estimates of proved reserves. The total amounts of these impairment charges were $159.9 million, which reduced the carrying value of these properties to their aggregate fair value of $62.5 million. In the first quarter of 2010, we impaired three of our natural gas producing properties following a significant drop in natural gas prices during the period. The total amounts of the impairment charges were $7.0 million, which reduced these properties to their aggregate fair value of $28.2 million. See Note 4 for additional information regarding our oil and gas property impairment charges.

Note 16 – Derivative Instruments and Hedging Activities

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

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

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

Commodity Price Risks

We currently manage commodity price risk through various financial costless collars and swap instruments covering a portion of our anticipated oil and natural gas production for 2011 and 2012. All of our current commodity derivative contracts qualify for hedge accounting. In June 2010 some of our oil contracts for 480 MBbl covering portions of our anticipated production during the third quarter of 2010 ceased to qualify for hedge accounting as a result of our decision to contract the HP I to BP to assist in the oil spill containment response rather than commencing production from our Phoenix field.

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

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Production Period	Instrument Type	Average Monthly Volumes	Weighted Average Price
Crude Oil:			(per barrel)
July 2011 — December 2011	Swap	175.8 MBbl	$	82.49
July 2011 — December 2011	Collar	53.3 MBbl	$	95.00 — $124.70
October 2011 — December 2011	Collar	12.5 MBbl	$	100.00 — $122.80	a
January 2012 — December 2012	Collar	75.0 MBbl	$	96.67 — $118.57
January 2012 — December 2012	Collar	91.7 MBbl	$	100.00 — $120.25	a

Natural Gas:			(per Mcf)
July 2011 — December 2011	Swap	725.8 Mmcf	$	4.97
January 2012 — December 2012	Swap	250.0 Mmcf	$	4.77
January 2012 — December 2012	Collar	166.7 Mmcf	$	4.75 — $5.09

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

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

Variable Interest Rate Risks

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

Foreign Currency Exchange Risks

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

Quantitative Disclosures Related to Derivative Instruments

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

Derivatives designated as hedging instruments are as follows:

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

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

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

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

Liability Derivatives:
		$	—		$	—

The following tables present the impact that derivative instruments designated as cash flow hedges had on our accumulated comprehensive loss and our condensed consolidated statements of operations for the three and six month periods ended June 30, 2011 and 2010.

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

(1)

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

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	Location of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)		Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
			Three Months Ended June 30,						Six Months Ended June 30,
			2011			2010			2011			2010

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

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

	Location of Gain (Loss) Recognized in Income on Derivatives		Gain (Loss) Recognized in Income on Derivatives
			Three Months Ended June 30,					Six Months Ended June 30,
			2011		2010			2011		2010
			(in thousands)
Natural gas contracts	Gain on oil and gas derivative contracts	$	—	$	2,482		$	—	$	2,482
Foreign exchange forwards	Other income (expense)		6		(398	)		614		(3,305	)
		$	6	$	2,084		$	614	$	(823	)

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

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

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HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(in thousands)

(Unaudited)

	As of June 30, 2011
			Helix		Guarantors		Non-Guarantors			Consolidating Entries			Consolidated
ASSETS:
Current assets:
Cash and cash equivalents		$	387,772	$	2,413	$	24,004		$	—		$	414,189
Accounts receivable, net			54,325		106,506		51,575			—			212,406
Unbilled revenue			2,219		—		18,084			—			20,303
Income taxes receivable			63,514		—		13,075			(67,530	)		9,059
Other current assets			47,610		42,191		12,712			(1,238	)		101,275
Total current assets			555,440		151,110		119,450			(68,768	)		757,232
Intercompany			1,294		294,433		(212,007	)		(83,720	)		—
Property and equipment, net			221,300		1,554,186		704,756			(4,932	)		2,475,310
Equity investments in unconsolidated affiliates			—		—		188,772			—			188,772
Equity investments in affiliates			1,947,501		28,432		—			(1,975,933	)		—
Goodwill, net			—		45,107		17,795			—			62,902
Other assets, net			48,499		38,119		19,639			(29,836	)		76,421
Due from subsidiaries/parent			90,965		275,900		—			(366,865	)		—
		$	2,864,999	$	2,387,287	$	838,405		$	(2,530,054	)	$	3,560,637

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable		$	41,121	$	82,403	$	24,618		$	—		$	148,142
Accrued liabilities			58,787		96,184		35,255			—			190,226
Income taxes payable			—		84,684		—			(84,684	)		—
Current maturities of long-term debt			3,000		—		4,759			—			7,759
Total current liabilities			102,908		263,271		64,632			(84,684	)		346,127
Long-term debt			1,132,136		—		107,757			—			1,239,893
Deferred income taxes			213,232		126,992		97,650			(6,053	)		431,821
Asset retirement obligations			—		166,458		—			—			166,458
Other long-term liabilities			1,335		3,480		617			—			5,432
Due to parent			—		—		116,451			(116,451	)		—
Total liabilities			1,449,611		560,201		387,107			(207,188	)		2,189,731
Convertible preferred stock			1,000		—		—			—			1,000
Total equity			1,414,388		1,827,086		451,298			(2,322,866	)		1,369,906
		$	2,864,999	$	2,387,287	$	838,405		$	(2,530,054	)	$	3,560,637

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HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(in thousands)

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

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

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HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(in thousands)

(Unaudited)

	Three Months Ended June 30, 2011
	Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated

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

	Three Months Ended June 30, 2010
	Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated

Net revenues	$	33,670		$	186,247		$	100,086		$	(20,741	)	$	299,262
Cost of sales		18,158			317,157			72,345			(13,580	)		394,080
Gross profit (loss)		15,512			(130,910	)		27,741			(7,161	)		(94,818	)
Gain on oil & gas derivative contracts		—			2,482			—			—			2,482
Gain (loss) on sale or acquisition of assets		—			—			(14	)		—			(14	)
Selling, general and administrative expenses		(13,583	)		(7,834	)		(3,531	)		402			(24,546	)
Income (loss) from operations		1,929			(136,262	)		24,196			(6,759	)		(116,896	)
Equity in earnings of investments		(69,604	)		3,612			1,656			65,992			1,656
Net interest expense and other		(15,319	)		(5,002	)		(1,878	)		—			(22,199	)
Income (loss) before income taxes		(82,994	)		(137,652	)		23,974			59,233			(137,439	)
Provision (benefit) for income taxes		(1,872	)		(49,351	)		1,221			(2,364	)		(52,366	)
Net income (loss), including noncontrolling interests		(81,122	)		(88,301	)		22,753			61,597			(85,073	)
Less net income applicable to noncontrolling interests		—			—			—			(444	)		(444	)
Preferred stock dividends		(34	)		—			—			—			(34	)
Net income (loss) applicable to Helix common shareholders	$	(81,156	)	$	(88,301	)	$	22,753		$	61,153		$	(85,551	)

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HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(in thousands)

(Unaudited)

	Six Months Ended June 30, 2011
	Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated

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

	Six Months Ended June 30, 2010
	Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated

Net revenues	$	54,692		$	355,970		$	145,058		$	(54,888	)	$	500,832
Cost of sales		31,492			457,199			122,302			(41,199	)		569,794
Gross profit (loss)		23,200			(101,229	)		22,756			(13,689	)		(68,962	)
Gain on oil & gas derivative contracts		—			2,482			—			—			2,482
Gain (loss) on sale or acquisition of assets		—			287			5,946			—			6,233
Selling, general and administrative expenses		(37,458	)		(17,915	)		(10,576	)		902			(65,047	)
Income (loss) from operations		(14,258	)		(116,375	)		18,126			(12,787	)		(125,294	)
Equity in earnings of investments		(64,736	)		3,105			6,711			61,631			6,711
Net interest expense and other		(22,708	)		(12,568	)		(8,143	)		—			(43,419	)
Income (loss) before income taxes		(101,702	)		(125,838	)		16,694			48,844			(162,002	)
Provision (benefit) for income taxes		(6,668	)		(45,136	)		(3,650	)		(4,473	)		(59,927	)
Net income (loss), including noncontrolling interests		(95,034	)		(80,702	)		20,344			53,317			(102,075	)
Less net income applicable to noncontrolling interests		—			—			—			(1,273	)		(1,273	)
Preferred stock dividends		(94	)		—			—			—			(94	)
Net income (loss) applicable to Helix common shareholders	$	(95,128	)	$	(80,702	)	$	20,344		$	52,044		$	(103,442	)

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HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

Six Months Ended June 30, 2011
	Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated

Cash flow from operating activities:
Net income (loss), including noncontrolling interests	$	67,117		$	76,691		$	30,448		$	(105,512	)	$	68,744
Adjustments to reconcile net income (loss), including noncontrolling interests to net cash provided by (used in) operating activities:
Equity in earnings of affiliates		(107,036	)		1,468			—			105,568			—
Other adjustments		21,261			180,193			(14,149	)		(5,476	)		181,829
Net cash provided by (used in) operating
activities		(18,658	)		258,352			16,299			(5,420	)		250,573

Cash flows from investing activities:
Capital expenditures		(15,699	)		(76,331	)		(14,092	)		—			(106,122	)
Investments in equity investments		—			—			(2,699	)		—			(2,699	)
Distributions from equity investments, net		—			—			1,593			—			1,593
Proceeds from sale of Cal Dive common stock		3,588			—			—			—			3,588
Decrease (increase) in restricted cash		—			863			—			—			863
Net cash used in investing activities		(12,111	)		(75,468	)		(15,198	)		—			(102,777	)

Cash flows from financing activities:
Repayments of debt		(111,191	)		—			(3,507	)		—			(114,698	)
Deferred financing costs		(9,014	)		—			—			—			(9,014	)
Preferred stock dividends paid		(20	)		—			—			—			(20	)
Repurchase of common stock		(1,012	)		—			—			—			(1,012	)
Excess tax benefit from stock-based compensation		(1,196	)		—			—			—			(1,196	)
Exercise of stock options, net		1,672			—			—			—			1,672
Intercompany financing		162,868			(183,765	)		15,477			5,420			—
Net cash provided by (used in) financing activities		42,107			(183,765	)		11,970			5,420			(124,268	)
Effect of exchange rate changes on cash and cash equivalents		—			—			(424	)		—			(424	)
Net increase (decrease) in cash and cash equivalents		11,338			(881	)		12,647			—			23,104
Cash and cash equivalents:
Balance, beginning of year		376,434			3,294			11,357			—			391,085
Balance, end of period	$	387,772		$	2,413		$	24,004		$	—		$	414,189

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HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(in thousands)

Six Months Ended June 30, 2010
	Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated

Cash flow from operating activities:
Net income (loss), including noncontrolling interests	$	(95,034	)	$	(80,702	)	$	20,344		$	53,317		$	(102,075	)
Adjustments to reconcile net income (loss), including noncontrolling interests to net cash provided by (used in) operating activities:
Equity in earnings of affiliates		64,736			(3,105	)		—			(61,631	)		—
Other adjustments		17,776			243,919			(13,101	)		(10,119	)		238,475
Net cash provided by (used in) operating
activities		(12,522	)		160,112			7,243			(18,433	)		136,400

Cash flows from investing activities:
Capital expenditures		(47,963	)		(80,203	)		(7,446	)		—			(135,612	)
Investments in equity investments		—			—			(6,307	)		—			(6,307	)
Distributions from equity investments, net		—			—			8,132			—			8,132
Insurance recovery		7,020			9,086			—			—			16,106
Decrease (increase) in restricted cash		—			109			—			—			109
Net cash used in investing activities		(40,943	)		(71,008	)		(5,621	)		—			(117,572	)

Cash flows from financing activities:
Repayments of debt		(2,163	)		—			(3,570	)		—			(5,733	)
Deferred financing costs		(2,792	)		—			—			—			(2,792	)
Preferred stock dividends paid		(94	)		—			—			—			(94	)
Repurchases of common stock		(9,127	)		—			—						(9,127	)
Excess tax benefit from stock-based compensation		(2,163	)		—			—			—			(2,163	)
Exercise of stock options, net		163			—			—			—			163
Intercompany financing		62,654			(86,591	)		5,504			18,433			—
Net cash provided by (used in) financing activities		46,478			(86,591	)		1,934			18,433			(19,746	)
Effect of exchange rate changes on cash and cash equivalents		—			—			246			—			246
Net increase (decrease) in cash and cash equivalents		(6,987	)		2,513			3,802			—			(672	)
Cash and cash equivalents:
Balance, beginning of year		258,742			2,522			9,409			—			270,673
Balance, end of period	$	251,755		$	5,035		$	13,211		$	—		$	270,001

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

FORWARD-LOOKING STATEMENTS AND ASSUMPTIONS

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

	•		statements regarding our business strategy, including the potential sale of assets and/or other investments in our subsidiaries and facilities, or any other business plans, forecasts or objectives, any or all of which is subject to change;
	•		statements regarding our anticipated production volumes, results of exploration, exploitation, development, acquisition or operations expenditures, and current or prospective reserve levels with respect to any oil and gas property or well;
	•		statements related to commodity prices for oil and gas or with respect to the supply of and demand for oil and gas;
	•		statements relating to our proposed exploration, development and/or production of oil and gas properties, prospects or other interests and any anticipated costs related thereto;
	•		statements related to environmental risks, exploration and development risks, or drilling and operating risks;
	•		statements regarding projections of revenues, gross margin, expenses, earnings or losses, working capital or other financial items;
	•		statements regarding any financing transactions or arrangements, or ability to enter into such transactions;
	•		statements regarding anticipated legislative, governmental, regulatory, administrative or other public body actions, requirements, permits or decisions;
	•		statements regarding the collectability of our trade receivables;
	•		statements regarding anticipated developments, industry trends, performance or industry ranking;
	•		statements regarding general economic or political conditions, whether international, national or in the regional and local market areas in which we do business;
	•		statements related to our ability to retain key members of our senior management and key employees;
	•		statements related to the underlying assumptions related to any projection or forward-looking statement; and
	•		any other statements that relate to non-historical or future information.

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

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	•		impact of the weak economic conditions and the future impact of such conditions on the oil and gas industry and the demand for our services;
	•		uncertainties inherent in the development and production of oil and gas and in estimating reserves;
	•		the geographic concentration of our oil and gas operations;
	•		the effect of new regulations on the offshore Gulf of Mexico oil and gas operations;
	•		uncertainties regarding our ability to replace depletion;
	•		unexpected future capital expenditures (including the amount and nature thereof);
	•		impact of oil and gas price fluctuations and the cyclical nature of the oil and gas industry;
	•		the effects of indebtedness, which could adversely restrict our ability to operate, could make us vulnerable to general adverse economic and industry conditions, could place us at a competitive disadvantage compared to our competitors that have less debt and could have other adverse consequences to us;
	•		the effectiveness of our hedging activities;
	•		the results of our continuing efforts to control or reduce costs, and improve performance;
	•		the success of our risk management activities;
	•		the effects of competition;
	•		the availability (or lack thereof) of capital (including any financing) to fund our business strategy and/or operations and the terms of any such financing;
	•		the impact of current and future laws and governmental regulations including tax and accounting developments;
	•		the effect of adverse weather conditions or other risks associated with marine operations;
	•		the effect of environmental liabilities that are not covered by an effective indemnity or insurance;
	•		the potential impact of a loss of one or more key employees; and
	•		the impact of general, market, industry or business conditions.

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

EXECUTIVE SUMMARY

Our Business

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

Our Strategy

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

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

Economic Outlook and Industry Influences

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

	•		worldwide economic activity, including available access to global capital and capital markets;
	•		demand for oil and natural gas, especially in the United States, Europe, China and India;
	•		economic and political conditions in the Middle East and other oil-producing regions;
	•		the effect of new regulations on the offshore Gulf of Mexico oil and gas operations;
	•		actions taken by the Organization of Petroleum Exporting Countries (“OPEC”) ;
	•		the availability and discovery rate of new oil and natural gas reserves in offshore areas;
	•		the cost of offshore exploration for and production and transportation of oil and gas;
	•		the ability of oil and natural gas companies to generate funds or otherwise obtain external capital for exploration, development and production operations;
	•		the sale and expiration dates of offshore leases in the United States and overseas;
	•		technological advances affecting energy exploration production transportation and consumption;
	•		weather conditions;
	•		environmental and other governmental regulations; and
	•		tax policies.

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

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

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

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

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

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

Helix Fast Response System

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

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RESULTS OF OPERATIONS

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

Contracting Services Operations

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

Oil and Gas Operations

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

Impairments

During the three-month period ended June 30, 2011, we recorded impairment charges totaling $22.7 million, including $4.1 million for our only U.K. oil and gas property, and for six of our Gulf of Mexico oil and gas properties. These impairment changes primarily reflect a premature end of these fields’ production life either through actual depletion or capital allocation decisions affecting our third party operated fields. We did not have any impairment of our properties in the first quarter of 2011. Following the determination of a significant reduction in our estimates of proved reserves at June 30, 2010, we recorded oil and gas property impairment charges totaling $159.9 million which affected the carrying value of 15 of our Gulf of Mexico oil and gas properties. See Note 4 for more information regarding our impairment charges recorded in the first half of 2011 and 2010.

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Non-GAAP Financial Measures

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

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

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

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

		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2011			2010			2011			2010
		(in thousands)

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

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Comparison of Three Months Ended June 30, 2011 and 2010

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

		Three Months Ended
		June 30,						Increase/
		2011			2010			(Decrease)

Revenues (in thousands) –
Contracting Services	$	171,353		$	202,317		$	(30,964	)
Production Facilities		20,545			21,391			(846	)
Oil and Gas		172,458			102,586			69,872
Intercompany elimination		(26,037	)		(27,032	)		995
	$	338,319		$	299,262		$	39,057

Gross profit (loss) (in thousands) –
Contracting Services	$	38,049		$	50,333		$	(12,284	)
Production Facilities		12,070			13,078			(1,008	)
Oil and Gas		50,858			(151,368	)		202,226
Corporate		(760	)		(747	)		(13	)
Intercompany elimination		(19	)		(6,114	)		6,095
	$	100,198		$	(94,818	)	$	195,016

Gross Margin –
Contracting Services		22	%		25	%		(3) pts
Production Facilities		59	%		61	%		(2) pts
Oil and Gas		30	%		(148	)%		178 pts
Total company		30	%		(32	)%		62 pts

Number of vessels(1)/ Utilization(2) –
Contracting Services:
Construction vessels		8/71	%		10/74	%
Well operations		3/89	%		3/98	%
ROVs		46/54	%		46/61	%

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

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

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

		Three Months Ended
		June 30,				Increase/
		2011		2010		(Decrease)

Contracting Services	$	14,295	$	24,426	$	(10,131	)
Production Facilities		11,742		2,606		9,136
	$	26,037	$	27,032	$	(995	)

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

		Three Months Ended
		June 30,					Increase/
		2011			2010		(Decrease)

Contracting Services	$	63		$	3,701	$	(3,638	)
Production Facilities		(44	)		2,413		(2,457	)
	$	19		$	6,114	$	(6,095	)

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

		Three Months Ended
		June 30,					Increase/
		2011			2010		(Decrease)

Oil and Gas information–
Oil production volume (MBbls)		1,430			790		640
Oil sales revenue (in thousands)	$	145,074		$	57,366	$	87,708
Average oil sales price per Bbl (excluding hedges)	$	111.23		$	75.39	$	35.84
Average realized oil price per Bbl (including hedges)	$	101.43		$	72.59	$	28.84
Increase in oil sales revenue due to:
Change in prices (in thousands)	$	22,794
Change in production volume (in thousands)		64,914
Total increase in oil sales revenue (in thousands)	$	87,708

Gas production volume (MMcf)		4,075			7,147		(3,072	)
Gas sales revenue (in thousands)	$	25,121		$	43,591	$	(18,470	)
Average gas sales price per mcf (excluding hedges)	$	5.63		$	4.44	$	1.19
Average realized gas price per mcf (including hedges)	$	6.17		$	6.10	$	0.07
Increase (decrease) in gas sales revenue due to:
Change in prices (in thousands)	$	472
Change in production volume (in thousands)		(18,942	)
Total decrease in gas sales revenue (in thousands)	$	(18,470	)

Total production (MMcfe)		12,656			11,889		767
Price per Mcfe	$	13.45		$	8.49	$	4.96

Oil and Gas revenue information (in thousands)–
Oil and gas sales revenue	$	170,195		$	100,957	$	69,238
Other revenues(1)		2,263			1,629		634
	$	172,458		$	102,586	$	69,872

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

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

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	Three Months Ended June 30,
	2011						2010
	Total			Per Mcfe			Total		Per Mcfe
	(in thousands, except per Mcfe amounts)
Oil and gas operating expenses(1):
Direct operating expenses(2)	$	29,390		$	2.32		$	15,763	$	1.33
Workover		2,236			0.18			3,504		0.29
Transportation		1,391			0.11			1,036		0.09
Repairs and maintenance		2,980			0.24			1,730		0.15
Overhead and company labor		3,296			0.26			1,579		0.13
	$	39,293		$	3.11		$	23,612	$	1.99

Depletion expense	$	48,526		$	3.83		$	63,330	$	5.33
Abandonment		227			0.02			401		0.03
Accretion expense		3,844			0.30			4,012		0.34
Net hurricane costs (reimbursements)		(950	)		(0.08	)		1,563		0.13
Impairment		22,721			1.80			159,862		13.45
		74,368			5.87			229,168		19.28
Total	$	113,661		$	8.98		$	252,780	$	21.27

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

(2)	Includes production taxes.

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

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

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

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

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

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

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

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

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

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

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

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Comparison of Six Months Ended June 30, 2011 and 2010

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

		Six Months Ended
		June 30,						Increase/
		2011			2010			(Decrease)

Revenues (in thousands) –
Contracting Services	$	302,890		$	356,517		$	(53,627	)
Production Facilities		36,115			22,711			13,404
Oil and Gas		341,317			193,301			148,016
Intercompany elimination		(50,396	)		(71,697	)		21,301
	$	629,926		$	500,832		$	129,094

Gross profit (loss) (in thousands) –
Contracting Services	$	48,561		$	87,955		$	(39,394	)
Production Facilities		18,206			13,099			5,107
Oil and Gas		112,093			(150,119	)		262,212
Corporate		(1,657	)		(1,461	)		(196	)
Intercompany elimination		71			(18,436	)		18,507
	$	177,274		$	(68,962	)	$	246,236

Gross Margin –
Contracting Services		16	%		25	%		(9) pts
Production Facilities		50	%		58	%		(8) pts
Oil and Gas		33	%		(78	)%		111 pts
Total company		28	%		(14	)%		42 pts

Number of vessels(1)/ Utilization(2) –
Contracting Services:
Construction vessels		8/61	%		10/78	%
Well operations		3/83	%		3/79	%
ROVs		46/52	%		46/60	%

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

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

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

		Six Months Ended
		June 30,				Increase/
		2011		2010		(Decrease)

Contracting Services	$	27,164	$	68,167	$	(41,003	)
Production Facilities		23,232		3,530		19,702
	$	50,396	$	71,697	$	(21,301	)

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

		Six Months Ended
		June 30,					Increase/
		2011			2010		(Decrease)

Contracting Services	$	39		$	15,143	$	(15,104	)
Production Facilities		(110	)		3,293		(3,403	)
	$	(71	)	$	18,436	$	(18,507	)

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

		Six Months Ended
		June 30,					Increase/
		2011			2010		(Decrease)

Oil and Gas information–
Oil production volume (MBbls)		2,931			1,445		1,486
Oil sales revenue (in thousands)	$	280,910		$	104,374	$	176,536
Average oil sales price per Bbl (excluding hedges)	$	103.92		$	75.53	$	28.39
Average realized oil price per Bbl (including hedges)	$	95.83		$	72.24	$	23.59
Increase in oil sales revenue due to:
Change in prices (in thousands)	$	34,086
Change in production volume (in thousands)		142,450
Total increase in oil sales revenue (in thousands)	$	176,536

Gas production volume (MMcf)		9,477			14,490		(5,013	)
Gas sales revenue (in thousands)	$	56,282		$	85,775	$	(29,493	)
Average gas sales price per mcf (excluding hedges)	$	5.35		$	4.87	$	0.48
Average realized gas price per mcf (including hedges)	$	5.94		$	5.92	$	0.02
Increase (decrease) in gas sales revenue due to:
Change in prices (in thousands)	$	277
Change in production volume (in thousands)		(29,770	)
Total decrease in gas sales revenue (in thousands)	$	(29,493	)

Total production (MMcfe)		27,065			23,159		3,906
Price per Mcfe	$	12.46		$	8.21	$	4.25

Oil and Gas revenue information (in thousands)–
Oil and gas sales revenue	$	337,192		$	190,149	$	147,043
Other revenues(1)		4,125			3,152		973
	$	341,317		$	193,301	$	148,016

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

	Six Months Ended June 30,
	2011						2010
	Total			Per Mcfe			Total		Per Mcfe
	(in thousands, except per Mcfe amounts)
Oil and gas operating expenses(1):
Direct operating expenses(2)	$	60,050		$	2.22		$	30,321	$	1.31
Workover		4,804			0.18			15,117		0.65
Transportation		3,802			0.14			2,329		0.10
Repairs and maintenance		5,247			0.19			3,532		0.15
Overhead and company labor		6,613			0.24			3,473		0.15
	$	80,516		$	2.97		$	54,772	$	2.36

Depletion expense	$	114,239		$	4.22		$	103,607	$	4.47
Abandonment		385			0.01			1,166		0.05
Accretion expense		7,630			0.28			7,943		0.34
Net hurricane costs (reimbursements)		(4,552	)		(0.17	)		3,618		0.16
Impairment		22,721			0.84			170,974		7.38
		140,423			5.18			287,308		12.40
Total	$	220,939		$	8.15		$	342,080	$	14.76

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

(2)	Includes production taxes.

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

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

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

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

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

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

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

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

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

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

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

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

LIQUIDITY AND CAPITAL RESOURCES

Overview

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

10-K).

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

Working Capital

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

Investing Activities

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

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

(1)

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

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

Restricted Cash

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

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Equity Investments

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

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

Outlook

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

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

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

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

(2)

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

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

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

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

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Contingencies

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

Item 3. Quantitative and Qualitative Disclosure about Market Risk

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

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

Production Period	Instrument Type	Average Monthly Volumes	Weighted Average Price
Crude Oil:			(per barrel)
July 2011 — December 2011	Swap	175.8 MBbl	$	82.49
July 2011 — December 2011	Collar	53.3 MBbl	$	95.00 — $124.70
October 2011 — December 2011	Collar	12.5 MBbl	$	100.00 — $122.80	a
January 2012 — December 2012	Collar	75.0 MBbl	$	96.67 — $118.57
January 2012 — December 2012	Collar	91.7 MBbl	$	100.00 — $120.25	a

Natural Gas:			(per Mcf)
July 2011 — December 2011	Swap	725.8 Mmcf	$	4.97
January 2012 — December 2012	Swap	250.0 Mmcf	$	4.77
January 2012 — December 2012	Collar	166.7 Mmcf	$	4.75 — $5.09

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

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

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Item 4. Controls and Procedures

(a)

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

(b)

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

Part II. OTHER INFORMATION

Item 1. Legal Proceedings

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

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

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

Issuer Purchases of Equity Securities

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

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

Item 6. Exhibits

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

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SIGNATURES

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

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

Date: July 27, 2011	By:	/s/ Anthony Tripodo
		Anthony Tripodo Executive Vice President and Chief Financial Officer (Principal Financial Officer)

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INDEX TO EXHIBITS

HELIX ENERGY SOLUTIONS GROUP, INC.


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

		(1) Filed herewith
		(2) Furnished herewith

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