UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

þ		Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended June 30, 2008

or

o		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.

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     þ                    No     o

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

Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company o

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

Yes     o                    No     þ

As of July 28, 2008, 91,857,500 shares of common stock were outstanding.

 

 

TABLE OF CONTENTS

				PAGE
PART I. FINANCIAL INFORMATION
Item 1.		Financial Statements:
		Condensed Consolidated Balance Sheets – June 30, 2008 (Unaudited) and December 31, 2007			1
		Condensed Consolidated Statements of Operations (Unaudited) – Three months ended June 30, 2008 and 2007			2
		Six months ended June 30, 2008 and 2007			3
		Condensed Consolidated Statements of Cash Flows (Unaudited) – Six months ended June 30, 2008 and 2007			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			47
Item 4.		Controls and Procedures			48
PART II. OTHER INFORMATION
Item 1.		Legal Proceedings			49
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds			49
Item 4.		Other Information			49
Item 6.		Exhibits			49
		Signatures			50
		Index to Exhibits			51
Guaranty Facility Agreement
Consulting Agreement
Independent Registered Accounting Firm's Acknowledgement Letter
Certification of Owen Kratz, CEO, Pursuant to Rule 13a-14(a)
Certification of Anthony Tripodo, CFO, Pursuant to Rule 13a-14(a)
Certification of CEO and CFO Pursuant to Section 906
Report of Independent Registered Public Accounting Firm

PART I. FINANCIAL INFORMATION

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

		June 30,				December 31,
		2008				2007
		(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	23,148			$	89,555
Accounts receivable —
Trade, net of allowance for uncollectible accounts of $4,321 and $2,874, respectively			402,936				447,502
Unbilled revenue			34,431				10,715
Costs in excess of billing			75,370				53,915
Other current assets			162,199				125,582
Total current assets			698,084				727,269
Property and equipment			4,530,881				4,088,561
Less — accumulated depreciation			(994,829	)			(843,873	)
			3,536,052				3,244,688
Other assets:
Equity investments			202,501				213,429
Goodwill			1,084,711				1,089,758
Other assets, net			213,097				177,209
		$	5,734,445			$	5,452,353
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	324,961			$	382,767
Accrued liabilities			246,567				221,366
Income taxes payable			95,688				—
Current maturities of long-term debt			163,656				74,846
Total current liabilities			830,872				678,979
Long-term debt			1,697,797				1,725,541
Deferred income taxes			599,458				625,508
Decommissioning liabilities			185,828				193,650
Other long-term liabilities			68,550				63,183
Total liabilities			3,382,505				3,286,861
Minority interest			275,121				263,926
Convertible preferred stock			55,000				55,000
Commitments and contingencies			—				—
Shareholders’ equity:
Common stock, no par, 240,000 shares authorized, 91,867 and 91,385 shares issued, respectively			769,834				755,758
Retained earnings			1,234,783				1,069,546
Accumulated other comprehensive income			17,202				21,262
Total shareholders’ equity			2,021,819				1,846,566
		$	5,734,445			$	5,452,353

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

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

		Three Months Ended
		June 30,
		2008				2007
Net revenues:
Contracting services		$	346,333			$	268,492
Oil and gas			194,161				142,082
			540,494				410,574
Cost of sales:
Contracting services			252,269				182,464
Oil and gas			95,811				86,345
			348,080				268,809
Gross profit			192,414				141,765
Gain on sale of assets, net			18,803				5,684
Selling and administrative expenses			43,921				33,388
Income from operations			167,296				114,061
Equity in earnings (losses) of investments			6,155				(4,748	)
Net interest expense and other			18,668				14,286
Income before income taxes			154,783				95,027
Provision for income taxes			55,925				33,261
Minority interest			7,076				3,119
Net income			91,782				58,647
Preferred stock dividends			880				945
Net income applicable to common shareholders		$	90,902			$	57,702
Earnings per common share:
Basic		$	1.00			$	0.64
Diluted		$	0.96			$	0.61
Weighted average common shares outstanding:
Basic			90,519				90,047
Diluted			95,928				95,991

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

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(in thousands, except per share amounts)

		Six Months Ended
		June 30,
		2008				2007
Net revenues:
Contracting services		$	626,019			$	533,580
Oil and gas			365,212				273,049
			991,231				806,629
Cost of sales:
Contracting services			472,455				360,519
Oil and gas			205,483				168,730
			677,938				529,249
Gross profit			313,293				277,380
Gain on sale of assets, net			79,916				5,684
Selling and administrative expenses			91,705				63,988
Income from operations			301,504				219,076
Equity in earnings of investments			17,078				1,356
Net interest expense and other			44,714				27,298
Income before income taxes			273,868				193,134
Provision for income taxes			99,557				66,384
Minority interest			7,313				11,338
Net income			166,998				115,412
Preferred stock dividends			1,761				1,890
Net income applicable to common shareholders		$	165,237			$	113,522
Earnings per common share:
Basic		$	1.83			$	1.26
Diluted		$	1.75			$	1.21
Weighted average common shares outstanding:
Basic			90,511				90,021
Diluted			95,652				95,262

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

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

		Six Months Ended
		June 30,
		2008				2007
Cash flows from operating activities:
Net income		$	166,998			$	115,412
Adjustments to reconcile net income to net cash provided by (used in) operating activities —
Depreciation, depletion and amortization			170,820				143,462
Asset impairment charge			17,028				904
Equity in losses of investments, inclusive of impairment charge			2,304				10,865
Amortization of deferred financing costs			2,503				1,522
Stock compensation expense			13,552				7,472
Deferred income taxes			(23,064	)			36,477
Excess tax benefit from stock-based compensation			(2,567	)			(432	)
Gain on sale of assets			(79,916	)			(5,684	)
Minority interest			7,313				11,338
Changes in operating assets and liabilities:
Accounts receivable, net			14,342				3,501
Other current assets			3,141				93
Margin deposits			(73,200	)			—
Income tax payable			107,142				(162,044	)
Accounts payable and accrued liabilities			(74,889	)			3,655
Other noncurrent, net			(61,178	)			(42,850	)
Net cash provided by operating activities			190,329				123,691
Cash flows from investing activities:
Capital expenditures			(554,800	)			(431,482	)
Sale of short-term investments			—				275,395
Investments in equity investments			(708	)			(15,265	)
Distributions from equity investments, net			9,118				6,279
Proceeds from sales of property			229,243				4,339
Other			(400	)			(687	)
Net cash used in investing activities			(317,547	)			(161,421	)
Cash flows from financing activities:
Repayment of Helix Term Notes			(2,163	)			(4,200	)
Borrowings on Helix Revolver			541,500				—
Repayments on Helix Revolver			(444,500	)			—
Repayment of MARAD borrowings			(1,982	)			(1,888	)
Borrowings on CDI Revolver			32,500				6,600
Repayments on CDI Revolver			(23,000	)			(67,600	)
Repayments on CDI Term Notes			(40,000	)			—
Deferred financing costs			(1,709	)			(88	)
Capital lease payments			—				(1,249	)
Preferred stock dividends paid			(1,761	)			(1,890	)
Repurchase of common stock			(3,223	)			(3,969	)
Excess tax benefit from stock-based compensation			2,567				432
Exercise of stock options, net			2,138				802
Net cash provided by (used in) financing activities			60,367				(73,050	)
Effect of exchange rate changes on cash and cash equivalents			444				906
Net decrease in cash and cash equivalents			(66,407	)			(109,874	)
Cash and cash equivalents:
Balance, beginning of year			89,555				206,264
Balance, end of period		$	23,148			$	96,390

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

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

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 condensed consolidated financial statements are unaudited, 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 Annual Report on Form 10-K for the year ended December 31, 2007 (“2007 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. Operating results for the period ended June 30, 2008 are not necessarily indicative of the results that may be expected for the year ending December 31, 2008. Our balance sheet as of December 31, 2007 included herein has been derived from the audited balance sheet as of December 31, 2007 included in our 2007 Form 10-K. These condensed consolidated financial statements should be read in conjunction with the annual consolidated financial statements and notes thereto included in our 2007 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.

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 proprietary technologies to deliver services that reduce finding and development costs and cover the complete lifecycle of an offshore oil and gas field. Our Oil and Gas segment engages in prospect generation, exploration, development and production activities. We operate primarily in the Gulf of Mexico, North Sea, Asia/Pacific and Middle East regions.

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, particularly from marginal fields. By “marginal”, we mean reservoirs that are no longer wanted by major operators or are too small to be material to them. Our “life of field” services are organized in five disciplines: construction, well operations, production facilities, reservoir and well technology services, and drilling. We have disaggregated our contracting services operations into three reportable segments in accordance with Financial Accounting Standards Board (“FASB”) Statement No. 131, Disclosures about Segments of an Enterprise and Related Information (“SFAS No. 131”): Contracting Services (which currently includes subsea construction, well operations and reservoir and well technology services and in the future, drilling); Shelf Contracting; and Production Facilities. Within our contracting services operations, we operate primarily in the Gulf of Mexico, the North Sea, Asia/Pacific and Middle East regions, with services that cover the lifecycle of an offshore oil or gas field. The assets of our Shelf Contracting segment are the

assets of Cal Dive International, Inc. and its subsidiaries (“Cal Dive” or “CDI”). Our ownership in CDI was approximately 58.2% as of June 30, 2008.

Oil and Gas Operations

     In 1992 we began our oil and gas operations to provide a more efficient solution to offshore abandonment, to expand our off-season asset utilization of our contracting services assets and to achieve incremental returns to our contracting services. Over the last 16 years 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. This has led to the assembly of services that allows us to create value at key points in the life of a reservoir from exploration through development, life of field management and operating through abandonment.

Note 3 — 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. As of June 30, 2008 and December 31, 2007, we had $35.2 million and $34.8 million, respectively, of restricted cash. Almost all of our restricted cash was related to funds required to be escrowed to cover decommissioning liabilities associated with the South Marsh Island 130 (“SMI 130”) acquisition in 2002 by our Oil and Gas segment. These amounts were reported in Others Assets, Net. We had fully satisfied the escrow requirement as of June 30, 2008. We may use the restricted cash for decommissioning the related field.

     The following table provides supplemental cash flow information for the six months ended June 30, 2008 and 2007 (in thousands):

		Six Months Ended
		June 30,
		2008				2007
Interest paid		$	33,747			$	49,709
Income taxes paid		$	15,480			$	191,950

     Non-cash investing activities for the six months ended June 30, 2008 included $19.5 million of accruals for capital expenditures. Non-cash investing activities for the six months ended June 30, 2007 were immaterial. The accruals have been reflected in the condensed consolidated balance sheet as an increase in property and equipment and accounts payable.

Note 4 — Acquisition of Horizon Offshore, Inc.

     On December 11, 2007, CDI acquired 100% of Horizon Offshore, Inc. (“Horizon”), a marine construction services company headquartered in Houston, Texas. Upon consummating the merger of Horizon into a subsidiary of CDI, each share of Horizon common stock, par value $0.00001 per share, was converted into the right to receive $9.25 in cash and 0.625 shares of CDI’s common stock. All shares of Horizon restricted stock that had been issued but had not vested prior to the effective time of the merger became fully vested at such time and converted into the right to receive the merger consideration. CDI issued approximately 20.3 million shares of common stock and paid approximately $300 million in cash to the former Horizon stockholders upon completion of the acquisition. The cash portion of the merger consideration was paid from cash on hand and from borrowings of $375 million under CDI’s $675 million credit facility, which consists of a $375 million senior secured term loan and a $300 million senior secured revolving credit facility (see “—Note 9—Long-Term Debt” below).

     We recognized a non-cash pre-tax gain of $151.7 million ($98.6 million net of taxes of $53.1 million) in December 2007 as the value of our interest in CDI’s underlying equity increased as a result of CDI’s issuance of 20.3 million shares of common stock to former Horizon stockholders. The gain was

calculated as the difference in the value of our investment in CDI immediately before and after CDI’s stock issuance.

     The aggregate purchase price, including transaction costs of $7.7 million, was approximately $630 million, consisting of $308 million of cash and $322 million of CDI stock. CDI also assumed and repaid approximately $104 million in Horizon’s debt, including accrued interest and prepayment penalties, and acquired $171 million of cash. Through the acquisition, CDI acquired nine construction vessels, including four pipelay/pipebury barges, one dedicated pipebury barge, one dive support vessel, one combination derrick/pipelay barge and two derrick barges. The acquisition was accounted for as a business combination with the acquisition price allocated to the assets acquired and liabilities assumed based upon their estimated fair values.

     The following table summarizes the estimated preliminary fair values of the assets acquired and liabilities assumed at the date of acquisition (in thousands):

Cash		$	170,607
Other current assets			157,137
Property and equipment			351,147
Goodwill			258,083
Intangible assets(1)			9,510
Other long-term assets			15,270
Total assets acquired		$	961,754
Current liabilities		$	176,388
Long-term debt			87,641
Deferred income taxes			67,501
Other non-current liabilities			100
Total liabilities assumed		$	331,630
Net assets acquired		$	630,124

						Amortization
		Fair Value				Period
Customer relationships		$	3,060			5 years
Contract backlog			2,960			1.5 years
Non-compete			3,000			1 year
Trade name			490			7 years
Total		$	9,510

At June 30, 2008, the net carrying amount for these intangible assets was $6.6 million.

     The allocation of the purchase price was based upon preliminary valuations. Estimates and assumptions are subject to change upon the receipt and CDI management’s review of the final valuations. The primary area of the purchase price allocation that is not yet finalized relates to post-closing purchase price adjustments and the receipt of final valuations. The final valuation of net assets is expected to be completed no later than one year from the acquisition date. The results of Horizon are included in our Shelf Contracting segment in the accompanying condensed consolidated statements of operations since the date of purchase.

     The following unaudited pro forma combined operating results of us and Horizon for the three and six months ended June 30, 2007 are presented as if the acquisition had occurred on January 1, 2007 (in thousands, except per share data):

		Three Months				Six Months
		Ended				Ended
		June 30, 2007				June 30, 2007
Net revenues		$	523,465			$	1,002,087
Income before income taxes			82,395				179,251
Net income			51,729				103,757
Net income applicable to common shareholders			50,784				101,867
Earnings per common share:
Basic		$	0.56			$	1.13
Diluted		$	0.54			$	1.09

     The pro forma operating results reflect adjustments for the increases in depreciation related to the “step-up” of the acquired assets to their fair value and to reflect depreciation calculations under the straight-line method instead of the units-of-production method used by Horizon. Pro forma results include the amortization of identifiable intangible assets. We estimated interest expense based upon increases in CDI’s long-term debt to fund the cash portion of the purchase price at an estimated annual interest rate of 7.55% for the three and six months ended June 30, 2007, based upon the interest rate of CDI’s new term loan of three month LIBOR plus 2.25%. The pro forma adjustment to income tax reflects the statutory federal and state income tax impacts of the pro forma adjustments to our pretax income with an applied tax rate of 35%. The unaudited pro forma combined results of operations are not indicative of the actual results had the acquisition occurred on January 1, 2007 or of future operations of the combined companies. All material intercompany transactions between us and Horizon were eliminated.

Note 5 — Well Ops SEA Pty Ltd. Acquisition

     In October 2006, we acquired a 58% interest in Seatrac Pty Ltd. (“Seatrac”) for total consideration of approximately $12.7 million (including $0.2 million of transaction costs), with approximately $9.1 million paid to existing Seatrac shareholders and $3.4 million for subscription of new Seatrac shares. We renamed this entity Well Ops SEA Pty Ltd. (“WOSEA”). WOSEA is a subsea well intervention and engineering services company located in Perth, Australia. Under the terms of the purchase agreement, we had an option to purchase the remaining 42% of the entity for approximately $10.1 million. On July 1, 2007, we exercised this option and now own 100% of the entity. In addition, the agreement with the existing shareholders provides for an earnout period of five years from July 1, 2007. If during this five-year period WOSEA achieves certain financial performance objectives, the shareholders will be entitled to additional consideration of approximately $5.8 million. For the period from July 1, 2007 to June 30, 2008, the performance objectives were not reached, hence no additional consideration was paid. This purchase was accounted for as a business combination with the acquisition price allocated to the assets acquired and liabilities assumed based upon their estimated fair value, with the excess being recorded as goodwill. The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at July 1, 2007 (in thousands):

Cash and cash equivalents		$	2,307
Other current assets			3,730
Property and equipment			7,937
Goodwill			13,682
Total assets acquired		$	27,656
Accounts payable and accrued liabilities		$	3,723
Deferred income taxes			960
Other non-current liabilities			241
Total liabilities assumed		$	4,924
Net assets acquired		$	22,732

     The allocation of the purchase price was finalized on June 30, 2008. The results of WOSEA have been included in the accompanying consolidated statements of operations in our Contracting Services segment since the date of our respective purchases. Pro forma combined operating results for the six months ended June 30, 2007 are not provided because the pre-acquisition results related to WOSEA were immaterial to the historical results of the Company.

Note 6 — Oil and Gas Properties

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

     As of June 30, 2008, we capitalized approximately $19.1 million of exploratory drilling 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 provides a detail of our capitalized exploratory project costs at June 30, 2008 and December 31, 2007 (in thousands):

		June 30,				December 31,
		2008				2007
Huey		$	11,556			$	11,556
Castleton (part of Gunnison)			7,071				7,071
Other			486				469
Total		$	19,113			$	19,096

     As of June 30, 2008, the exploratory well costs for Castleton and Huey had been capitalized for longer than one year. We are not the operator of Castleton.

     The following table reflects net changes in suspended exploratory well costs during the six months ended June 30, 2008 (in thousands):

		2008
Beginning balance at January 1,		$	19,096
Additions pending the determination of proved reserves			735
Reclassifications to proved properties			(734	)
Credit to dry hole expense			16
Ending balance at June 30,		$	19,113

     Further, the following table details the components of exploration expense for the three and six months ended June 30, 2008 and 2007 (in thousands):

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
Delay rental and geological and geophysical costs		$	1,438			$	2,988			$	3,378			$	4,052
Dry hole expense			36				(10	)			(16	)			116
Total exploration expense		$	1,474			$	2,978			$	3,362			$	4,168

     On March 31, 2008, we agreed to sell a 30% working interest in the Bushwood discoveries (Garden Banks Blocks 463, 506 and 507) and other Outer Continental Shelf oil and gas properties (East Cameron blocks 371 and 381), in two separate transactions to affiliates of a private independent oil and gas company for total cash consideration of approximately $181.2 million (which includes the purchasers’ share of incurred capital expenditures on these fields), and additional potential cash payments of up to $20 million based upon certain field production milestones. The new co-owners will also pay their pro rata share of all future capital expenditures related to the exploration and development of these fields. The assumption of certain decommissioning liabilities will be satisfied on a pro rata share basis between the new co-owners and us. We received $120.8 million related to the sale of a 20% working interest and related to the reimbursement of capital expenditures on these fields from the purchasers. We have also received $60.4 million for the 10% sale in the second quarter 2008. Proceeds from the sale of these properties were used to pay down our outstanding revolving loans in April 2008. As a result of these sales, we recognized a pre-tax gain of $91.6 million (of which $61.1 million was recognized in first quarter 2008).

     In May 2008, we sold all our interests in our onshore proved and unproved oil and gas properties located in the states of Texas, Mississippi, Louisiana, Oklahoma, New Mexico and Wyoming (“Onshore Properties”) to an unrelated investor. We sold these Onshore Properties for cash proceeds of $47.2 million and recorded a related loss of $11.9 million in the second quarter of 2008. Included in the cost basis of the Onshore Properties was an $8.1 million allocation of goodwill from our Oil and Gas segment. Following the allocation of goodwill, we performed an impairment test for the remaining goodwill of $704.3 million related to our Oil and Gas segment and no impairment was indicated.

     As a result of our unsuccessful development well in January 2008 on Devil’s Island (Garden Banks 344), we recognized impairment expense of $14.6 million in the first half of 2008. Costs incurred as of December 31, 2007 of $20.9 million related to this well were charged to income in 2007.

Note 7 — Details of Certain Accounts (in thousands)

     Other Current Assets consisted of the following as of June 30, 2008 and December 31, 2007:

		June 30,				December 31,
		2008				2007
Other receivables		$	10,824			$	6,733
Prepaid insurance			2,281				21,133
Other prepaids			26,104				14,922
Current deferred tax assets			14,359				13,810
Insurance claims to be reimbursed			7,018				10,173
Gas imbalance			7,036				6,654
Inventory			36,445				29,925
Income tax receivable			—				8,838
Margin deposits			50,563				—
Other			7,569				13,394
		$	162,199			$	125,582

     Other Assets, Net, consisted of the following as of June 30, 2008 and December 31, 2007:

		June 30,				December 31,
		2008				2007
Restricted cash		$	35,198			$	34,788
Margin deposits			22,637				—
Deposits			3,419				8,417
Deferred drydock expenses, net			83,970				47,964
Deferred financing costs			38,793				39,290
Intangible assets with definite lives, net			18,568				22,216
Intangible asset with indefinite life			7,043				7,022
Contract receivables			—				14,635
Other			3,469				2,877
		$	213,097			$	177,209

     Accrued Liabilities consisted of the following as of June 30, 2008 and December 31, 2007:

		June 30,				December 31,
		2008				2007
Accrued payroll and related benefits		$	31,494			$	50,389
Royalties payable			36,880				21,974
Current decommissioning liability			23,829				23,829
Unearned revenue			8,500				1,140
Billings in excess of costs			6,861				20,403
Insurance claims to be reimbursed			7,018				14,173
Accrued interest			34,637				7,090
Accrued severance(1)			2,561				14,786
Deposit			17,000				13,600
Hedge liability			28,054				10,308
Other			49,733				43,674
		$	246,567			$	221,366

Note 8 — Equity Investments

     As of June 30, 2008, we have the following material investments that are accounted for under the equity method of accounting:

	•		Deepwater Gateway, L.L.C. In June 2002, we, along with Enterprise Products Partners L.P. (”Enterprise”), formed Deepwater Gateway, L.L.C. (“Deepwater Gateway”) (each with a 50% interest) to design, construct, install, own and operate a tension leg platform (“TLP”) production hub primarily for Anadarko Petroleum Corporation’s Marco Polo field in the Deepwater Gulf of Mexico. Our investment in Deepwater Gateway totaled $108.6 million and $112.8 million as of June 30, 2008 and December 31, 2007, respectively, and was included in our Production Facilities segment.
	•		Independence Hub, LLC. In December 2004, we acquired a 20% interest in Independence Hub, LLC (“Independence”), an affiliate of Enterprise. Independence owns the “Independence Hub” platform

located in Mississippi Canyon block 920 in a water depth of 8,000 feet. First production began in July 2007. Our investment in Independence was $90.6 million and $95.7 million as of June 30, 2008 and December 31, 2007, respectively (including capitalized interest of $6.0 million and $6.2 million at June 30, 2008 and December 31, 2007, respectively), and was included in our Production Facilities segment.

Note 9 — Long-Term Debt

Senior Unsecured Notes

     On December 21, 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 all of our existing restricted domestic subsidiaries, except for CDI and its subsidiaries and Cal Dive I-Title XI, Inc. In addition, any future restricted domestic subsidiaries that guarantee any of our and/or our restricted subsidiaries’ indebtedness are required to guarantee the Senior Unsecured Notes. CDI, the subsidiaries of CDI, Cal Dive I -Title XI, Inc., and our foreign subsidiaries are not guarantors. We used the proceeds from the Senior Unsecured Notes to repay outstanding indebtedness under our senior secured credit facilities (see below).

Senior Credit Facilities

     On July 3, 2006, we entered into a credit agreement (the “Senior Credit Facilities”) under which we borrowed $835 million in a term loan (the “Term Loan”) and were initially able to borrow up to $300 million (the “Revolving Loans”) under a revolving credit facility (the “Revolving Credit Facility”). The proceeds from the Term Loan were used to fund the cash portion of the Remington Oil and Gas Corporation (“Remington”) acquisition. This facility was subsequently amended on November 27, 2007, and as part of that amendment, an accordion feature was added that allows for increases in the Revolving Credit Facility up to $150 million, subject to availability of borrowing capacity provided by new or existing lenders. On May 29, 2008, we completed a $120 million increase in the Revolving Credit Facility utilizing this accordion feature. Total borrowing capacity under the Revolving Credit Facility now totals $420 million. The full amount of the Revolving Credit Facility may be used for issuances of letters of credit.

     The Term Loan matures on July 1, 2013 and is subject to quarterly scheduled principal payments. As a result of a $400 million prepayment made in December 2007, the quarterly scheduled principal payment was reduced from $2.1 million to $1.1 million. The Revolving Loans mature on July 1, 2011. At June 30, 2008, we had outstanding $115.0 million in borrowings under our Revolving Loans and $28.8 million of unsecured letters of credit, and there were $276.2 million available under the Revolving Loans.

     The Term Loan currently bears interest at the one-, three- or six-month LIBOR at our election plus a 2.00% margin. Our average interest rate on the Term Loan for the six months ended June 30, 2008 and 2007 was approximately 5.7% and 7.3%, respectively, including the effects of our interest rate swaps (see below). The Revolving Loans bear interest based on one-, three- or six-month LIBOR at our election plus a margin ranging from 1.00% to 2.25%. Margins on the Revolving Loans will fluctuate in relation to the consolidated leverage ratio as provided in the Senior Credit Facilities. Our average interest rate on the Revolving Loans for the six months ended June 30, 2008 was approximately 5.8%.

     As the rates for our Term Loan are subject to market influences and will vary over the term of the Senior Credit Facilities, we entered into various interest rate swaps to stabilize cash flows relating to a portion of our interest payments for our Term Loan. See detailed description related to these swaps in “—Note 11 — Hedging Activities” below.

Cal Dive International, Inc. Revolving Credit Facility

     In December 2007, CDI entered into a secured credit facility with certain financial institutions, consisting of a $375 million term loan, and a $300 million revolving credit facility. This credit facility replaced the credit facility CDI entered into in November 2006 prior to its initial public offering. On December 11, 2007, CDI borrowed $375 million under the term loan to fund the cash portion of the merger consideration in connection with CDI’s acquisition of Horizon and to retire Horizon’s existing debt. At June 30, 2008, CDI had $335.0 million of term loan outstanding and $9.5 million in borrowings under its revolving credit facility. In addition, CDI had $22.1 million of unsecured letters of credit outstanding with $268.4 million available under its revolving credit facility.

     Loans under this facility are non-recourse to Helix. The term loan and the revolving loans bear interest in relation to the LIBOR. During the six months ended June 30, 2008 and 2007, CDI’s average interest rate was 6.2%.

     As the rates for CDI’s term loan are subject to market influences and will vary over the term of the loan, CDI entered into an interest rate swap to stabilize cash flows relating to a portion of its interest payments for the CDI term loan. See detailed description related to this swap in “—Note 11 — Hedging Activities” below.

Convertible Senior Notes

     On March 30, 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 under certain triggering events specified in the indenture governing the Convertible Senior Notes. In second quarter 2008, the closing sale price of our common stock for at least 20 trading days in the period of 30 consecutive trading days ending on June 30, 2008 exceeded 120% of the conversion price (i.e., exceeded $38.56 per share). As a result, pursuant to the terms of the indenture, the Convertible Senior Notes can be converted during the third quarter of 2008. We expect to have approximately $210 million available capacity under our Revolving Loans to cover the conversion during the third quarter 2008 (the conversion period). As a result, $210 million of the Convertible Senior Notes remained in long-term debt and $90 million was reclassified to current maturities of long-term debt. If in future quarters the conversion price trigger is met and we do not have alternative long-term financing or commitments available to cover the conversion (or a portion thereof), the portion uncovered would be classified as a current liability in the accompanying balance sheet.

     Approximately 1.2 million and 965,000 shares underlying the Convertible Senior Notes were included in the calculation of diluted earnings per share for the three and six months ended June 30, 2008, respectively, and approximately 1.6 million shares and 977,000 shares for the three and six months ended June 30, 2007, respectively, because our average share price for the respective periods was above the conversion price of approximately $32.14 per share. 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 maximum number of shares of common stock which may be issued upon conversion of the Convertible Senior Notes is 13,303,770.

MARAD Debt

     At June 30, 2008 and December 31, 2007, $125.5 million and $127.5 million was outstanding on our long-term financing for construction of the Q4000. This U.S. government guaranteed financing (“MARAD Debt”) is pursuant to Title XI of the Merchant Marine Act of 1936 which is administered by the Maritime Administration. The MARAD Debt is payable in equal semi-annual installments which began in August 2002

and matures 25 years from such date. The MARAD Debt is collateralized by the Q4000, with us guaranteeing 50% of the debt. In September 2005, we fixed the interest rate on the debt through the issuance of a 4.93% fixed-rate note with the same maturity date (February 2027).

     In accordance with the Senior Unsecured Notes, amended Senior Credit Facilities, Convertible Senior Notes, MARAD Debt agreements and CDI’s credit facility, we are required to comply with certain covenants and restrictions, including the maintenance of minimum net worth, annual working capital and debt-to-equity requirements. As of June 30, 2008, we were in compliance with these covenants and restrictions. The Senior Unsecured Notes and Senior Credit Facilities contain provisions that limit our ability to incur certain types of additional indebtedness.

Other

     On June 19, 2007, Kommandor LLC entered into a term loan agreement (“Nordea Loan Agreement”) with Nordea Bank Norge ASA. Pursuant to the Nordea Loan Agreement, the lenders will make available to Kommandor LLC up to $45.0 million pursuant to a secured term loan facility. Kommandor LLC will use all amounts borrowed under the facility to repay its existing subordinated indebtedness for the long-term financing of the Vessel and to fund expenses and fees related to the conversion of such Vessel to operate as a floating production unit. Kommandor LLC expects this borrowing to occur in the fourth quarter of 2008 upon the delivery of the Vessel after its initial conversion, and at such time, in accordance with the provisions of FIN 46, the entire obligation will be included in our consolidated balance sheet. The funding of the amount set forth in the draw request is subject to certain customary conditions.

     On June 30, 2008, we entered into a Guaranty Facility Agreement with Nordea and its affiliate, Nordea Bank Finland Plc (together, the “Guarantee Provider”). This facility provides us with $20 million of capacity for issuances of letters of credit that are required from time to time in our business for performance guarantees or warranty requirements. The facility has a maturity date of 364 days, and may be renewed annually for successive 364-day periods at the lenders’ option. Fees for letters of credit issued under the facility are 1.00% of the face amount of the letter of credit. As of June 30, 2008, we had $7.2 million of unsecured letters of credit outstanding under this facility. This facility is unsecured; however, in the event that the facility is not renewed and letters of credits remain outstanding, we may be required to provide cash collateral for 105% of the face amount of the letters of credit.

     Deferred financing costs of $38.8 million and $39.3 million are included in Other Assets, Net as of June 30, 2008 and December 31, 2007, respectively, and are being amortized over the life of the respective loan agreements.

     Scheduled maturities of long-term debt and capital lease obligations outstanding as of June 30, 2008 were as follows (in thousands):

		Helix				Helix				CDI				CDI				Senior				Convertible
		Term				Revolving				Term				Revolving				Unsecured				Senior				MARAD
		Loan				Loans				Loan				Loans				Notes				Notes(2)				Debt				Other(1)				Total
Less than one year		$	4,326			$	—			$	60,000			$	—			$	—			$	90,000			$	4,112			$	5,218			$	163,656
One to two years			4,326				—				80,000				—				—				—				4,318				—				88,644
Two to three years			4,326				—				80,000				—				—				—				4,533				—				88,859
Three to four years			4,326				115,000				80,000				—				—				210,000				4,760				—				414,086
Four to five years			4,326				—				35,000				9,500				—				—				4,997				—				53,823
Over five years			399,625				—				—				—				550,000				—				102,760				—				1,052,385
Long-term debt			421,255				115,000				335,000				9,500				550,000				300,000				125,480				5,218				1,861,453
Current maturities			(4,326	)			—				(60,000	)			—				—				(90,000	)			(4,112	)			(5,218	)			(163,656	)
Long-term debt, less current maturities		$	416,929			$	115,000			$	275,000			$	9,500			$	550,000			$	210,000			$	121,368			$	—			$	1,697,797

     Our total exposure under letters of credit outstanding at June 30, 2008 was approximately $53.3 million. These letters of credit primarily guarantee various contract bidding, contractual performance and insurance activities and shipyard commitments. The following table details our interest expense and capitalized interest for the three and six months ended June 30, 2008 and 2007 (in thousands):

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
Interest expense		$	29,692			$	23,153			$	64,575			$	46,246
Interest income			(586	)			(1,933	)			(1,628	)			(6,575	)
Capitalized interest			(9,602	)			(6,396	)			(20,573	)			(11,799	)
Interest expense, net		$	19,504			$	14,824			$	42,374			$	27,872

Note 10 — Income Taxes

     The effective tax rate for the six months ended June 30, 2008 and June 30, 2007 was 36.4% and 34.4%, respectively. The effective tax rate for the first half of 2008 increased as compared to the same prior year period because of the following factors:

	§		additional deferred tax expense was recorded as a result of the increase in the equity earnings of CDI in excess of our tax basis in CDI; and
	§		the allocation of goodwill to the cost basis for the Onshore Properties sale is not allowable for tax purposes.

These increases were partially offset by the increased benefit derived from the Internal Revenue Code §199 manufacturing deduction as it primarily related to oil and gas production and the effect of lower tax rates in certain foreign jurisdictions.

     We believe our recorded assets and liabilities are reasonable; however, tax laws and regulations are subject to interpretation and tax litigation is inherently uncertain; therefore our assessments can involve a series of complex judgments about future events and rely heavily on estimates and assumptions. See detailed description related to a tax assessment in “—Note 19 – Commitments and Contingencies” below.

Note 11 — 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 include the use of derivative financial instruments to hedge the impact of market price risk exposures primarily related to our oil and gas production, variable interest rate exposure and foreign currency exchange rate exposure, as well as non-derivative forward sale contracts to reduce commodity price risk on sales of hydrocarbons.

Commodity Hedges

     We have entered into various cash flow hedging costless collar and swap contracts to stabilize cash flows relating to a portion of our expected oil and gas production. All of these qualify for hedge accounting. The aggregate fair value of the hedge instruments was a net liability of $23.7 million and $8.1 million as of June 30, 2008 and December 31, 2007, respectively. We recorded unrealized losses of approximately $6.6 million and $10.1 million, net of tax benefit of $3.5 million and $5.5 million during the three and six months ended June 30, 2008, respectively, in accumulated other comprehensive income, a component of shareholders’ equity, as these hedges were highly effective. For the three and six months ended June 30, 2007, we recorded unrealized gains (losses) of approximately $4.7 million and $(3.6)

million, net of tax expense (benefit) of $2.5 million and $(1.9) million during the three and six months ended June 30, 2007, respectively, During the three and six months ended June 30, 2008, we reclassified approximately $15.1 million and $19.1 million of losses from other comprehensive income to net revenues upon the sale of the related oil and gas production. For the three and six months ended June 30, 2007, we reclassified approximately $0.2 million and $2.3 million of gains from other comprehensive income to net revenues.

     As of June 30, 2008, we had the following volumes under derivative and forward sale contracts related to our oil and gas producing activities totaling 2,475 MBbl of oil and 29,605,800 MMbtu of natural gas:

Average

Weighted

Production Period

Instrument Type

Monthly Volumes

Average Price

Crude Oil:

July 2008 – December 2008

Collar

30 MBbl

$60.00 — $82.38

July 2008 – December 2008

Swap

40 MBbl

$107.02

July 2008 – December 2009

Forward Sale

114,167 MBbl

$71.84

Natural Gas:

July 2008 – December 2008

Collar

375,000 MMBtu

$7.50 — $11.22

July 2008 – December 2009

Forward Sale

1,519,767 MMBtu

$8.26

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

Interest Rate Hedges

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

     We formally document all relations between hedging instruments and hedged items, as well as our risk management objectives, strategies for undertaking various hedge transactions and our methods for assessing and testing correlation and hedge ineffectiveness. We also assess, both at inception of the hedge and on an on-going basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows of the hedged items. Changes in the assumptions used could impact whether the fair value change in the interest rate swap is charged to earnings or accumulated other comprehensive income.

     In September 2006, we entered into various interest rate swaps to stabilize cash flows relating to a portion of our interest payments on our Term Loan. The interest rate swaps were effective as of October 3, 2006. These interest rate swaps qualified for hedge accounting. See “-Note 9 — Long-Term Debt” above for a detailed description of our Term Loan. On December 21, 2007, we prepaid a portion of our Term Loan which reduced the notional amount of our interest rate swaps and caused our hedges to become ineffective. As a result, the interest rate swaps no longer qualified for hedge accounting treatment under FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, (“SFAS No. 133”). On January 31, 2008, we re-designated these swaps as cash flow hedges with respect to our outstanding LIBOR-based debt. During the three months ended March 31, 2008, we recognized $1.8 million of unrealized losses as other expense, net of taxes of $1.0 million as a result of the change in fair value of our interest rate swaps from January 1, 2008 to January 31, 2008, the date of re-designation. As of June 30, 2008, these swaps continued to be highly effective. Immaterial ineffectiveness was

recorded in income related to the period from February 1, 2008 to June 30, 2008. No ineffectiveness was recognized during the three and six months ended June 30, 2007. As of June 30, 2008 and December 31, 2007, the aggregate fair value of the derivative instruments was a net liability of $5.9 million and $4.7 million, respectively. During the three and six months ended June 30, 2008 and 2007, we reclassified approximately $0.3 million and $0.7 million of losses, respectively, from other comprehensive income to interest expense. During the three and six months ended June 30, 2007, we reclassified approximately $0.1 million and $0.2 million of gains, respectively.

     In addition, in April 2008, CDI entered into a two-year interest rate swap to stabilize cash flows relating to a portion of its variable interest payments on the CDI term loan. As of June 30, 2008, these interest rate swaps were highly effective and qualified for hedge accounting. The fair value of the hedge instrument was an asset of $1.3 million as of June 30, 2008.

Foreign Currency Hedge

     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 a shipyard contract where the contractual payments are denominated in euros and expected cash outflows relating to certain vessel charters denominated in British pounds. The following table provides details related to the remaining forward contracts at June 30, 2008 (amounts in thousands):

							Exchange
Forecasted Settlement Date			Amount				Rate
July 31, 2008			£	581				1.9263	(a)(b)
August 27, 2008			€	698				1.5593	(c)(d)
August 29, 2008			£	581				1.9225	(a)(b)
September 26, 2008			€	1,344				1.5569	(c)(b)
September 29, 2008			€	465				1.5567	(c)(d)
December 15, 2008			€	3,500				1.5508	(c)(b)
March 2, 2009			€	1,075				1.5456	(c)(b)

     The aggregate fair value of the foreign currency forwards described above was a net asset of $0.2 million and $1.4 million as of June 30, 2008 and December 31, 2007, respectively.

Note 12 — Fair Value Measurements

     In September 2006, the FASB issued Statement No. 157, Fair Value Measurements (“SFAS No. 157”). SFAS No. 157 was originally effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. The FASB agreed to defer the effective date of SFAS No. 157 for all nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. We adopted the provisions of SFAS No. 157 on January 1, 2008 for assets and liabilities not subject to the deferral and expect to adopt this standard for all other assets and liabilities by January 1, 2009. The adoption of SFAS No. 157 had immaterial impact on our results of operations, financial condition and liquidity.

     SFAS No. 157, among other things, defines fair value, establishes a consistent framework for measuring fair value and expands disclosure for each major asset and liability category measured at fair value on either a recurring or nonrecurring basis. SFAS No. 157 clarifies that fair value is an exit price, representing the amount that would be received to sell an asset, or paid to transfer a liability, in an orderly transaction between market participants. SFAS No. 157 establishes a three-tier fair value hierarchy,

which prioritizes the inputs used in measuring fair value as follows:

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

     Assets and liabilities measured at fair value are based on one or more of three valuation techniques noted in SFAS No. 157. The valuation techniques are as follows:

	(a)		Market Approach. Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.
	(b)		Cost Approach. Amount that would be required to replace the service capacity of an asset (replacement cost).
	(c)		Income Approach. Techniques to convert expected future cash flows to a single present 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, 2008 (in thousands):

																		Valuation
		Level 1				Level 2				Level 3				Total				Technique
Assets:
Foreign currency forwards			—				154				—				154				(c)
Interest rate swap			—				1,311				—				1,311				(c)
Total			—				1,465				—				1,465
Liabilities:
Oil and gas swaps and collars			—				23,712				—				23,712				(c)
Interest rate swaps			—				5,916				—				5,916				(c)
Total			—				29,628				—				29,628

Note 13 — Comprehensive Income

     The components of total comprehensive income for the three and six months ended June 30, 2008 and 2007 were as follows (in thousands):

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
Net income		$	91,782			$	58,647			$	166,998			$	115,412
Foreign currency translation gain			1,985				4,078				2,792				4,715
Unrealized gain (loss) on hedges, net			(4,405	)			6,098				(6,852	)			(2,091	)
Total comprehensive income		$	89,362			$	68,823			$	162,938			$	118,036

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

		June 30,				December 31,
		2008				2007
Cumulative foreign currency translation adjustment		$	31,052			$	28,260
Unrealized loss on hedges, net			(13,850	)			(6,998	)
Accumulated other comprehensive income		$	17,202			$	21,262

Note 14 — Earnings Per Share

     Basic earnings per share (“EPS”) 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 computation of basic and diluted EPS for the three and six months ended June 30, 2008 and 2007 were as follows (in thousands):

		Three Months Ended								Three Months Ended
		June 30, 2008								June 30, 2007
		Income				Shares				Income				Shares
Earnings applicable per common share – Basic		$	90,902				90,519			$	57,702				90,047
Effect of dilutive securities:
Stock options			—				367				—				383
Restricted shares			—				210				—				284
Employee stock purchase plan			—				2				—				19
Convertible Senior Notes			—				1,199				—				1,627
Convertible preferred stock			880				3,631				945				3,631
Earnings applicable per common share – Diluted		$	91,782				95,928			$	58,647				95,991

		Six Months Ended								Six Months Ended
		June 30, 2008								June 30, 2007
		Income				Shares				Income				Shares
Earnings applicable per common share – Basic		$	165,237				90,511			$	113,522				90,021
Effect of dilutive securities:
Stock options			—				384				—				375
Restricted shares			—				161				—				227
Employee stock purchase plan			—				—				—				32
Convertible Senior Notes			—				965				—				976
Convertible preferred stock			1,761				3,631				1,890				3,631
Earnings applicable per common share – Diluted		$	166,998				95,652			$	115,412				95,262

     There were no antidilutive stock options in the three and six months ended June 30, 2008 and 2007 as the option strike price was below the average market price for the applicable periods. Net income for the diluted EPS calculation for the three and six months ended June 30, 2008 and 2007 was adjusted to add back the preferred stock dividends as if the convertible preferred stock were converted into 3.6 million shares of common stock.

Note 15 — Stock-Based Compensation Plans

     We have three stock-based compensation plans: the 1995 Long-Term Incentive Plan, as amended (the “1995 Incentive Plan”), the 2005 Long-Term Incentive Plan, as amended (the “2005 Incentive Plan”) and the 1998 Employee Stock Purchase Plan, as amended (the “ESPP”). In addition, CDI has two stock-based compensation plans, the 2006 Long-Term Incentive Plan (the “CDI Incentive Plan”) and the CDI Employee Stock Purchase Plan (the “CDI ESPP”) available only to the employees of CDI and its subsidiaries.

     During the first half of 2008, we granted 507,597 shares of restricted stock and 43,977 restricted stock units to certain key executives, selected management employees and non-employee members of the board of directors under the 2005 incentive plan, which grants generally have a vesting period of 20% per year over five years. The weighted average market value per restricted share and restricted stock unit was $41.10 and $41.50, respectively. There were no stock option grants in the six months ended June 30, 2008 and 2007.

     Compensation cost is recognized over the respective vesting periods on a straight-line basis. For the three and six months ended June 30, 2008, $0.3 million and $0.9 million, respectively, was recognized as compensation expense related to stock options (of which $0.1 million and $0.6 million for the three and six months ended June 30, 2008, respectively, was related to the acceleration of unvested options per the separation agreements between the Company and two of our former executive officers). For the three and six months ended June 30, 2008, $4.5 million and $11.5 million, respectively, was recognized as compensation expense related to restricted shares and restricted stock units (of which $1.2 million and $2.4 million, respectively, was related to the CDI Incentive Plan and $0.5 million and $3.6 million, respectively, was related to the accelerated vesting of restricted shares per the separation agreements between the Company and two of our former executive officers). For the three and six months ended June 30, 2007, $3.0 million and $5.9 million, respectively, was recognized as compensation expense related to restricted shares (of which $0.5 million and $1.0 million, respectively, was related to the CDI Incentive Plan). Future compensation cost associated with unvested restricted stock awards at June 30, 2008 totaled approximately $49.7 million, of which approximately $15.2 million was related to CDI Incentive Plan.

Employee Stock Purchase Plan

     Effective May 12, 1998, we adopted a qualified non-compensatory employee stock purchase plan which allows employees to acquire shares of our common stock through payroll deductions over a six-month period. The purchase price is equal to 85% of the fair market value of the common stock on either the first or last day of the subscription period, whichever is lower. Purchases under the plan are limited to the lesser of 10% of an employee’s base salary or $25,000 of our stock value. In January and July 2008, we issued 46,152 and 52,781 shares, respectively, of our common stock to our employees under the ESPP. For the three and six months ended June 30, 2008, we recognized $0.6 million and $1.1 million, respectively, of compensation expense related to the ESPP and the CDI ESPP (of which $0.3 million and $0.6 million, respectively, of expense was related to the CDI ESPP that became effective third quarter 2007). For the three and six months ended June 30, 2007, we recognized $0.5 million and $1.0 million, respectively, of compensation expense related to the ESPP.

Note 16 — Business Segment Information (in thousands)

     Our operations are conducted through two lines of business: contracting services operations and oil and gas operations. We have disaggregated our contracting services operations into three reportable segments in accordance with SFAS No. 131: Contracting Services, Shelf Contracting and Production Facilities. As a result, our reportable segments consist of the following: Contracting Services, Shelf Contracting, Production Facilities, and Oil and Gas. The Contracting Services segment includes services such as subsea construction, well operations, and reservoir and well technology services. The Shelf Contracting segment represents the assets of Cal Dive, which consists of assets deployed primarily for diving-related activities and shallow water construction. All material intercompany transactions among the segments have been eliminated in our consolidated results of operations.

     We evaluate our performance based on income before income taxes of each segment. Segment assets are comprised of all assets attributable to the reportable segment. The majority of our Production Facilities segment is accounted for under the equity method of accounting. Our investment in Kommandor LLC, a Delaware limited liability company, was consolidated in accordance with FASB Interpretation No. 46, Consolidation of Variable Interest Entities (“FIN 46”) and is included in our Production Facilities segment.

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
Revenues –
Contracting Services		$	228,351			$	154,719			$	412,140			$	292,436
Shelf Contracting			171,970				135,258				316,541				284,484
Oil and Gas			194,161				142,082				365,212				273,049
Intercompany elimination			(53,988	)			(21,485	)			(102,662	)			(43,340	)
Total		$	540,494			$	410,574			$	991,231			$	806,629
Income from operations –
Contracting Services		$	37,993			$	31,987			$	58,904			$	55,082
Shelf Contracting			29,498				36,142				37,046				84,445
Production Facilities equity investments(1)			(156	)			(145	)			(294	)			(332	)
Oil and Gas			104,202				48,685				214,119				87,902
Intercompany elimination			(4,241	)			(2,608	)			(8,271	)			(8,021	)
Total		$	167,296			$	114,061			$	301,504			$	219,076
Equity in losses of OTSL, inclusive of impairment		$	—			$	(11,793	)		$	—			$	(10,841	)
Equity in earnings of equity investments excluding OTSL		$	6,155			$	7,045			$	17,078			$	12,197

		June 30,				December 31,
		2008				2007
Identifiable Assets –
Contracting Services.		$	1,358,720			$	1,177,431
Shelf Contracting			1,184,077				1,274,050
Production Facilities			427,432				366,634
Oil and Gas			2,764,216				2,634,238
Total		$	5,734,445			$	5,452,353

     Intercompany segment revenues during the three and six months ended June 30, 2008 and 2007 were as follows:

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
Contracting Services		$	42,718			$	16,901			$	85,041			$	31,497
Shelf Contracting			11,270				4,584				17,621				11,843
Total		$	53,988			$	21,485			$	102,662			$	43,340

     Intercompany segment profits during the three and six months ended June 30, 2008 and 2007 were as follows:

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
Contracting Services		$	2,979			$	657			$	5,892			$	2,675
Shelf Contracting			1,262				1,951				2,379				5,346
Total		$	4,241			$	2,608			$	8,271			$	8,021

Note 17 — Resignation of Executive Officers

     Martin Ferron resigned as our President and Chief Executive Officer effective February 4, 2008. Concurrently, Mr. Ferron resigned from our Board of Directors. Mr. Ferron remained employed by us through February 18, 2008, after which his employment terminated. At the time of Mr. Ferron’s resignation, Owen Kratz, who served as Executive Chairman of Helix, resumed the role and assumed the duties of the President and Chief Executive Officer, and was subsequently elected as President and Chief Executive Officer of Helix. In February 2008, we recognized approximately $5.4 million of compensation expense (inclusive of the expenses recorded for the acceleration of unvested stock options and restricted stock) related to the separation agreement between us and Mr. Ferron.

     Wade Pursell resigned as our Chief Financial Officer effective June 25, 2008. Mr. Pursell remained employed by us through July 4, 2008, after which his employment terminated. Anthony Tripodo, who served as the chairman of our audit committee on our Board of Directors, was elected by our Board of Directors as the new Chief Financial Officer effective June 25, 2008, at which time he resigned from our Board of Directors. In June 2008, we recognized approximately $1.5 million of compensation expense (inclusive of the expenses recorded for the acceleration of unvested stock options and restricted stock) related to the separation between us and Mr. Pursell. In July 2008, we recognized an additional $0.5 million of consulting expense related to a consulting agreement between the Company and Mr. Pursell.

Note 18 — Related Party Transactions

     In April 2000, we acquired a 20% working interest in Gunnison, a Deepwater Gulf of Mexico prospect of Kerr-McGee. Financing for the exploratory costs of approximately $20 million was provided by an investment partnership (OKCD Investments, Ltd. or “OKCD”), the investors of which include our President and Chief Executive Officer, Owen Kratz, and certain former Helix senior management, in exchange for a revenue interest that is an overriding royalty interest of 25% of Helix’s 20% working interest. Owen Kratz, through Class A limited partnership interests in OKCD, personally owns approximately 74% of the partnership. In 2000, OKCD also awarded Class B limited partnership interests to key Helix employees. Production began in December 2003. Payments to OKCD from us totaled $5.7 million and $11.2 million in the three and six months ended June 30, 2008, respectively, and $5.7 million and $11.7 million in the three and six months ended June 30, 2007, respectively.

Note 19 — Commitments and Contingencies

Commitments

     We are converting the Caesar (acquired in January 2006 for $27.5 million in cash) into a deepwater pipelay vessel. Total conversion costs are estimated to range between $165 million and $185 million, of which approximately $124 million had been incurred, with an additional $31.7 million committed, at June 30, 2008. The Caesar is expected to be completed in the fourth quarter of 2008.

     We are also constructing the Well Enhancer, a multi-service dynamically positioned dive support/well intervention vessel that will be capable of working in the North Sea and West of Shetlands to support our expected growth in that region. Total construction cost for the Well Enhancer is expected to range between $200 million to $220 million. We expect the Well Enhancer to join our fleet in first quarter 2009. At June 30, 2008, we had incurred approximately $137 million, with an additional $43.4 million committed to this project.

     Further, we, along with Kommandor RØMØ, a Danish corporation, formed a joint venture called Kommandor LLC to convert a ferry vessel into a floating production unit to be named the Helix Producer I (the “Vessel”). The total cost of the ferry and the conversion is estimated to range between $130 million and $150 million which will be funded through project financing of $45 million, with the remaining amount funded through equity contributions from the partners. The partners will guarantee the project financing

on a several basis, with each partner providing a guarantee of $22.5 million. We have provided $40 million in interim construction financing to the joint venture on terms that would equal an arms length financing transaction, and Kommandor RØMØ has provided $5 million on the same terms. Both of these loans will be repaid with the proceeds of the permanent financing facility.

     Total equity contributions and indebtedness guarantees provided by Kommandor RØMØ are expected to total $42.5 million. The remaining costs to complete the project will be provided by Helix through equity contributions and its guarantee of the permanent financing facility. Under the terms of the operating agreement of the joint venture, if Kommandor RØMØ elects not to make further contributions to the joint venture, the ownership interests in the joint venture will be adjusted based on the relative contributions of each partner (including guarantees of indebtedness) to the total of all contributions and project financing guarantees.

     Upon completion of the initial conversion, scheduled for fourth quarter 2008, we will charter the Vessel from Kommandor LLC, and will install, at 100% our cost, processing facilities and a disconnectable fluid transfer system on the Vessel for use on our Phoenix field. The cost of these additional facilities is approximately $135 million and the work is expected to be completed in second quarter 2009. As of June 30, 2008, approximately $221 million of costs related to the purchase of the Vessel ($20 million), conversion of the Vessel and construction of the additional facilities had been incurred, with an additional $54.7 million committed. Kommandor LLC qualified as a variable interest entity under FIN 46. We determined that we were the primary beneficiary of Kommandor LLC and thus have consolidated the financial results of Kommandor LLC as of June 30, 2008 in our Production Facilities segment. Kommandor LLC has been a development stage enterprise since its formation in October 2006.

     Our projected capital expenditures on certain projects have increased as compared to the initially budgeted amounts due primarily to scope changes, escalating costs for certain materials and services due to increasing demand, and the weakening of the U.S. dollar with respect to foreign denominated contracts. In addition, as of June 30, 2008, we have also committed approximately $94.8 million in additional capital expenditures for exploration, development and drilling costs related to our oil and gas properties.

Contingencies

     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.

     On December 2, 2005, we received an order from the U.S. Department of the Interior Minerals Management Service (“MMS”) that the price thresholds for both oil and gas were exceeded for 2004 production and that royalties are due on such production notwithstanding the provisions of the Outer Continental Shelf Deep Water Royalty Relief Act of 2005 (“DWRRA”), which was intended to stimulate exploration and production of oil and natural gas in the deepwater Gulf of Mexico by providing relief from the obligation to pay royalties on certain federal leases up to certain specified production volumes. Our only leases affected by this order are the Gunnison leases. On May 2, 2006, the MMS issued an order that superseded and replaced the December 2005 order, and claimed that royalties on gas production are due for 2003 in addition to oil and gas production in 2004. The May 2006 order also seeks interest on all royalties allegedly due. We filed a timely notice of appeal with respect to both MMS orders. Other operators in the deepwater Gulf of Mexico who have received notices similar to ours are seeking royalty relief under the DWRRA, including Kerr-McGee, the operator of Gunnison. In March of 2006, Kerr-McGee filed a lawsuit in federal district court challenging the enforceability of price thresholds in certain deepwater Gulf of Mexico leases, including ours. On October 30, 2007, the federal district court in the Kerr-McGee case entered judgment in favor of Kerr-McGee and held that the Department of the Interior exceeded its authority by including the price thresholds in the subject leases. The government filed a notice of appeal of that decision on December 21, 2007. We do not anticipate that the MMS director will

issue decisions in our or the other companies’ administrative appeals until the Kerr-McGee litigation has been resolved in a final decision. As a result of our dispute with the MMS, we have recorded reserves for the disputed royalties (and any other royalties that may be claimed from the Gunnison leases), plus interest, for our portion of the Gunnison related MMS claim. The total reserved amount for this matter at June 30, 2008 and December 31, 2007 was approximately $62.1 million and $55.1 million, respectively, and was included in Other Long-term Liabilities in the accompanying condensed consolidated balance sheet included herein. At this time, it is not anticipated that any penalties would be assessed if we are unsuccessful in our appeal.

     During the fourth quarter of 2006, Horizon received a tax assessment from the Servicio de Administracion Tributaria (“SAT”), the Mexican taxing authority, for approximately $23 million related to fiscal 2001, including penalties, interest and monetary correction. The SAT’s assessment claims unpaid taxes related to services performed among the Horizon subsidiaries that CDI acquired at the time it acquired Horizon. CDI believes under the Mexico and United States double taxation treaty that these services are not taxable and that the tax assessment itself is invalid. On February 14, 2008, CDI received notice from the SAT upholding the original assessment. On April 21, 2008, CDI filed a petition in Mexico tax court disputing the assessment. We believe that CDI’s position is supported by law and CDI intends to vigorously defend its position. However, the ultimate outcome of this litigation and CDI’s potential liability from this assessment, if any, cannot be determined at this time. Nonetheless, an unfavorable outcome with respect to the Mexico tax assessment could have a material adverse effect on our and CDI’s financial position and results of operations. Horizon’s 2002 through 2007 tax years remain subject to examination by the appropriate governmental agencies for Mexico tax purposes, with 2002 through 2004 currently under audit.

Note 20 — Recently Issued Accounting Principles

     In March 2008, the FASB issued Statement No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 (“SFAS No. 161”). SFAS 161 applies to all derivative instruments and related hedged items accounted for under FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS No. 133”). SFAS No. 161 asks entities to provide qualitative disclosures about the objectives and strategies for using derivatives, quantitative data about the fair value of and gains and losses on derivative contracts, and details of credit-risk-related contingent features in their hedged positions. The standard is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged, but not required. We are currently evaluating the impact of this statement on our disclosures.

     In May 2008, the FASB issued FASB Staff Position (“FSP”) APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement) (“FSP APB 14-1"). The FSP would require the proceeds from the issuance of convertible debt instruments to be allocated between a liability component (issued at a discount) and an equity component. The resulting debt discount would be amortized over the period the convertible debt is expected to be outstanding as additional non-cash interest expense. The effective date of FSP APB 14-1 is for fiscal years beginning after December 15, 2008 and requires retrospective application to all periods reported (with the cumulative effect of the change reported in retained earnings as of the beginning of the first period presented). The FSP does not permit early application. This FSP changes the accounting treatment for our Convertible Senior Notes. FSP APB 14-1 will increase our non-cash interest expense for our past and future reporting periods. In addition, it will reduce our long-term debt and increase our shareholders’ equity for the past reporting periods. We are currently evaluating the impact of this FSP on our consolidated financial statements.

     In June 2008, the FASB issued FSP Emerging Issues Task Force 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (“FSP EITF 03-6-1”). This FSP would require unvested share-based payment awards containing non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) to be included in the computation of basic EPS according to the two-class method. The effective date of FSP EITF 03-6-1 is for fiscal years

beginning after December 15, 2008 and requires all prior-period EPS data presented to be adjusted retrospectively (including interim financial statements, summaries of earnings, and selected financial data) to conform with the provisions of this FSP. FSP EITF 03-6-1 does not permit early application. This FSP changes our calculation of basic and diluted EPS and will lower previously reported basic and diluted EPS as weighted-average shares outstanding used in the EPS calculation will increase. We are currently evaluating the impact of this statement on our consolidated financial statements.

Note 21 — Condensed Consolidated Guarantor and Non-Guarantor Financial Information

     The payment of obligations under the Senior Unsecured Notes is guaranteed by all of our restricted domestic subsidiaries (“Subsidiary Guarantors”) except for Cal Dive and its subsidiaries and 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 guarantee 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.

HELIX ENERGY SOLUTIONS GROUP, INC.
CONDENSED CONSOLIDATING BALANCE SHEETS
(in thousands)

		As of June 30, 2008
										Non-				Consolidating
		Helix				Guarantors				Guarantors				Entries				Consolidated
ASSETS
Current assets:
Cash and cash equivalents		$	2,837			$	4,163			$	16,148			$	—			$	23,148
Accounts receivable, net			73,136				169,137				270,223				241				512,737
Other current assets			76,562				108,694				47,834				(70,891	)			162,199
Total current assets			152,535				281,994				334,205				(70,650	)			698,084
Intercompany			144,846				51,929				(176,459	)			(20,316	)			—
Property and equipment, net			148,949				2,164,490				1,225,382				(2,769	)			3,536,052
Other assets:
Equity investments			3,195,861				35,203				202,501				(3,231,064	)			202,501
Goodwill			—				749,670				335,316				(275	)			1,084,711
Other assets, net			54,257				62,055				125,949				(29,164	)			213,097
		$	3,696,448			$	3,345,341			$	2,046,894			$	(3,354,238	)		$	5,734,445
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	52,625			$	161,354			$	110,941			$	41			$	324,961
Accrued liabilities			66,588				106,550				76,852				(3,423	)			246,567
Income taxes payable			(8,478	)			106,221				4,723				(6,778	)			95,688
Current maturities of long-term debt			94,326				—				130,025				(60,695	)			163,656
Total current liabilities			205,061				374,125				322,541				(70,855	)			830,872
Long-term debt			1,291,929				—				431,353				(25,485	)			1,697,797
Deferred income taxes			148,837				284,320				178,148				(11,847	)			599,458
Decommissioning liabilities			—				181,660				4,168				—				185,828
Other long-term liabilities			1,573				64,584				7,152				(4,759	)			68,550
Due to parent			(37,028	)			72,878				37,028				(72,878	)			—
Total liabilities			1,610,372				977,567				980,390				(185,824	)			3,382,505
Minority interest			—				—				—				275,121				275,121
Convertible preferred stock			55,000				—				—				—				55,000
Shareholders’ equity			2,031,076				2,367,774				1,066,504				(3,443,535	)			2,021,819
		$	3,696,448			$	3,345,341			$	2,046,894			$	(3,354,238	)		$	5,734,445