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, 2007

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		77060
(Address of principal executive offices)		(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, 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 þ            Accelerated filer o            Non-accelerated filer 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 31, 2007, 91,331,935 shares of common stock were outstanding.

 

 

TABLE OF CONTENTS

		PAGE
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements:
Condensed Consolidated Balance Sheets – June 30, 2007 (Unaudited) and December 31, 2006			1
Condensed Consolidated Statements of Operations (Unaudited) – Three months ended June 30, 2007 and 2006			2
Six months ended June 30, 2007 and 2006			3
Condensed Consolidated Statements of Cash Flows (Unaudited) – Six months ended June 30, 2007 and 2006			4
Notes to Condensed Consolidated Financial Statements (Unaudited)			5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			22
Item 3. Quantitative and Qualitative Disclosures About Market Risk			36
Item 4. Controls and Procedures			37
PART II. OTHER INFORMATION
Item 1. Legal Proceedings			38
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			38
Item 4. Submission of Matters to a Vote of Security Holders			38
Item 6. Exhibits			38
Signatures			40
Index to Exhibits			41
Term Loan Agreement
Accounting Firms's Acknowledgement Letter
Certification of Executive Chairman Pursuant to Rule 13a-14(a)
Certification of CFO Pursuant to Rule 13a-14(a)
Certification of Executive Chairman Pursuant to Section 1350
Certification of CFO Pursuant to Section 1350
Report of Independent Registered Public Accounting Firm

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

		June 30,				December 31,
		2007				2006
		(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	96,390			$	206,264
Short-term investments			10,000				285,395
Accounts receivable —
Trade, net of allowance for uncollectible accounts of $1,740 and $982, respectively			311,849				287,875
Unbilled revenue			56,377				82,834
Other current assets			76,832				61,532
Total current assets			551,448				923,900
Property and equipment			3,167,825				2,721,362
Less — accumulated depreciation			(630,429	)			(508,904	)
			2,537,396				2,212,458
Other assets:
Equity investments			212,319				213,362
Goodwill, net			828,228				822,556
Other assets, net			137,758				117,911
		$	4,267,149			$	4,290,187
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	268,877			$	240,067
Accrued liabilities			188,148				199,650
Income tax payable			—				147,772
Current maturities of long-term debt			26,165				25,887
Total current liabilities			483,190				613,376
Long-term debt			1,386,011				1,454,469
Deferred income taxes			476,094				436,544
Decommissioning liabilities			140,682				138,905
Other long-term liabilities			4,231				6,143
Total liabilities			2,490,208				2,649,437
Commitments and contingencies			—				—
Minority interest			73,152				59,802
Convertible preferred stock			55,000				55,000
Shareholders’ equity:
Common stock, no par, 240,000 shares authorized, 91,341 and 90,628 shares issued, respectively			752,623				745,928
Retained earnings			866,306				752,784
Accumulated other comprehensive income			29,860				27,236
Total shareholders’ equity			1,648,789				1,525,948
		$	4,267,149			$	4,290,187

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,
		2007				2006
Net revenues:
Contracting services		$	268,492			$	223,903
Oil and gas			142,082				81,110
			410,574				305,013
Cost of sales:
Contracting services			182,464				133,710
Oil and gas			86,345				39,611
			268,809				173,321
Gross profit			141,765				131,692
Gain on sale of assets			5,684				16
Selling and administrative expenses			33,388				27,414
Income from operations			114,061				104,294
Equity in earnings (losses) of investments, net of impairment charge			(4,748	)			4,520
Net interest expense and other			14,286				2,983
Income before income taxes			95,027				105,831
Provision for income taxes			33,261				35,887
Minority interest			3,119				—
Net income			58,647				69,944
Preferred stock dividends			945				805
Net income applicable to common shareholders		$	57,702			$	69,139
Earnings per common share:
Basic		$	0.64			$	0.88
Diluted		$	0.61			$	0.83
Weighted average common shares outstanding:
Basic			90,047				78,462
Diluted			95,991				83,965

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,
		2007				2006
Net revenues:
Contracting services		$	533,580			$	435,238
Oil and gas			273,049				161,423
			806,629				596,661
Cost of sales:
Contracting services			360,519				265,402
Oil and gas			168,730				97,301
			529,249				362,703
Gross profit			277,380				233,958
Gain on sale of assets			5,684				283
Selling and administrative expenses			63,988				48,442
Income from operations			219,076				185,799
Equity in earnings of investments, net of impairment charge			1,356				10,756
Net interest expense and other			27,298				5,440
Income before income taxes			193,134				191,115
Provision for income taxes			66,384				64,978
Minority interest			11,338				—
Net income			115,412				126,137
Preferred stock dividends			1,890				1,609
Net income applicable to common shareholders		$	113,522			$	124,528
Earnings per common share:
Basic		$	1.26			$	1.59
Diluted		$	1.21			$	1.51
Weighted average common shares outstanding:
Basic			90,021				78,216
Diluted			95,262				83,659

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,
		2007				2006
Cash flows from operating activities:
Net income		$	115,412			$	126,137
Adjustments to reconcile net income to net cash provided by operating activities —
Depreciation and amortization			143,462				67,664
Asset impairment charge			904				—
Dry hole expense			116				20,654
Equity in earnings of investments, net of distributions			24				(356	)
Equity in (earnings) losses of OTSL, inclusive of impairment charge			10,841				(2,650	)
Amortization of deferred financing costs			1,522				969
Stock compensation expense			7,472				3,816
Deferred income taxes			36,477				29,120
Gain on sale of assets			(5,684	)			(283	)
Excess tax benefit from stock-based compensation			(432	)			(7,529	)
Minority interest			11,338				—
Changes in operating assets and liabilities:
Accounts receivable, net			3,501				(51,312	)
Other current assets			93				(1,754	)
Accounts payable and accrued liabilities			3,655				(20,658	)
Income taxes payable			(162,044	)			(5,557	)
Other noncurrent, net			(42,966	)			(8,936	)
Net cash provided by operating activities			123,691				149,325
Cash flows from investing activities:
Capital expenditures			(431,482	)			(125,794	)
Acquisition of businesses, net of cash acquired			(136	)			(78,174	)
Investments in equity investments			(15,265	)			(19,019	)
Distributions from equity investments, net of equity in earnings of investments			6,279				—
Sale of short-term investments, net			275,395				—
Increase in restricted cash			(551	)			(5,577	)
Proceeds from sales of property			4,339				16,782
Net cash used in investing activities			(161,421	)			(211,782	)
Cash flows from financing activities:
Repayment of Senior Credit Facilities			(4,200	)			—
Repayment of Cal Dive International, Inc. revolving credit facility			(61,000	)			—
Repayment of MARAD borrowings			(1,888	)			(1,798	)
Deferred financing costs			(88	)			(1,914	)
Capital lease payments			(1,249	)			(1,491	)
Preferred stock dividends paid			(1,890	)			(1,863	)
Repurchase of common stock			(3,969	)			(225	)
Excess tax benefit from stock-based compensation			432				7,529
Exercise of stock options, net			802				8,520
Net cash (used in) provided by financing activities			(73,050	)			8,758
Effect of exchange rate changes on cash and cash equivalents			906				897
Net decrease in cash and cash equivalents			(109,874	)			(52,802	)
Cash and cash equivalents:
Balance, beginning of year			206,264				91,080
Balance, end of period		$	96,390			$	38,278

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, 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, 2006, as amended by our Form 10-K/A for the year ended December 31, 2006 filed on June 18, 2007 (“2006 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, 2007 are not necessarily indicative of the results that may be expected for the year ending December 31, 2007. Our balance sheet as of December 31, 2006 included herein has been derived from the audited balance sheet as of December 31, 2006 included in our 2006 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 2006 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 development solutions and other key services (contracting services operations) to the open market as well as to our own reservoirs (oil and gas operations). Our oil and gas business is a prospect generating, exploration, development and production company. By employing our own key services and methodologies in our reservoirs, we seek to lower finding and development costs relative to industry norms.

Contracting Services Operations

     We seek to provide services and methodologies which we believe are critical to finding and developing offshore reservoirs and maximizing the economics from marginal fields. Those “life of field” services are organized in five disciplines: reservoir and well tech services, drilling, production facilities, construction and well operations. We have disaggregated our contracting services operations into three reportable segments in accordance with Statement of Financial Accounting Standard No. 131 Disclosures about Segments of an Enterprise and Related Information (“SFAS No. 131”): Contracting Services (which currently includes deepwater construction, well operations and reservoir and well tech services), Shelf Contracting, and Production Facilities. Within our contracting services operations, we operate primarily in the Gulf of Mexico, the North Sea and the Asia/Pacific regions, with services that cover the lifecycle of an offshore oil or gas field. Our Shelf Contracting segment, consists of our majority-owned subsidiary, Cal Dive International, Inc. (“Cal Dive” or “CDI”), including its 40% interest in Offshore Technology Solutions Limited (“OTSL”). For information related to the impairment of OTSL, see “—Note 8—Equity Investments.” In December 2006, Cal Dive completed an initial public offering of 22,173,000 shares of its stock. See “—Note 4 – Initial Public Offering of Cal Dive International, Inc.” below.

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 and to achieve better returns than are likely to be generated through pure service contracting. Over the last 15 years we have evolved this business model to include not only mature oil and gas properties but also proved reserves yet to be developed, and most recently the properties of Remington Oil and Gas Corporation (“Remington”), an exploration, development and production company we acquired in July 2006. 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.

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, 2007 and December 31, 2006, we had $34.2 million and $33.7 million, respectively, of restricted cash included in other assets, net, all of which 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. We have fully satisfied the escrow requirement as of June 30, 2007. 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, 2007 and 2006 (in thousands):

		Six Months Ended
		June 30,
		2007				2006
Interest paid (net of capitalized interest)		$	32,047			$	5,072
Income taxes paid		$	191,950			$	41,414

     Non-cash investing activities for the six months ended June 30, 2007 and 2006 included $3.0 million and $62.6 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 4 – Initial Public Offering of Cal Dive International, Inc.

     In December 2006, we contributed the assets of our Shelf Contracting segment into Cal Dive, our then wholly owned subsidiary. Cal Dive subsequently sold 22,173,000 shares of its common stock in an initial public offering and distributed the net proceeds of $264.4 million to us as a dividend. In connection with the offering, CDI also entered into a $250 million revolving credit facility. In December 2006, Cal Dive borrowed $201 million under the facility and distributed $200 million of the proceeds to us as a dividend. For additional information related to the Cal Dive credit facility, see “—Note 9 – Long-Term Debt” below. We recognized an after-tax gain of $96.5 million, net of taxes of $126.6 million, as a result of these transactions in 2006. CDI used the remaining proceeds for general corporate purposes.

     In connection with the offering, together with CDI shares issued to CDI employees since the offering, our ownership of CDI decreased to approximately 73% as of June 30, 2007 and December 31, 2006. Subject to market conditions, we may sell additional shares of Cal Dive common stock in the future.

     Further, in conjunction with the offering, the tax basis of certain of CDI’s tangible and intangible assets was increased to fair value. The increased tax basis should result in additional tax deductions available to CDI over a period of two to five years. Under a Tax Matters Agreement between us and CDI,

for a period of ten years from the closing of CDI’s initial public offering, to the extent CDI generates taxable income sufficient to realize the additional tax deductions, CDI will be required to pay us 90% of the amount of tax savings actually realized from the step-up of the basis of certain assets. As of June 30, 2007 and December 31, 2006, we have a receivable from CDI of approximately $8.8 million and $11.3 million, respectively, related to the Tax Matters Agreement. For additional information related to the Tax Matters Agreement, see our 2006 Form 10-K.

Note 5 – Acquisition of Remington Oil and Gas Corporation

     On July 1, 2006, we acquired 100% of Remington, an independent oil and gas exploration and production company headquartered in Dallas, Texas, with operations concentrated in the onshore and offshore regions of the Gulf Coast, for approximately $1.4 billion in cash and stock and the assumption of $357.8 million of liabilities. The merger consideration was 0.436 of a share of our common stock and $27.00 in cash for each share of Remington common stock. On July 1, 2006, we issued 13,032,528 shares of our common stock to Remington stockholders and funded the cash portion of the Remington acquisition (approximately $806.8 million) and transaction costs (approximately $18.6 million) through borrowings under a credit agreement (see “— Note 9—Long-Term Debt” below).

     The Remington 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, with the excess being recorded in goodwill. The final valuation of net assets was completed in June 2007 with no material changes to our preliminary valuation. The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition (in thousands):

Current assets		$	154,408
Property and equipment			863,935
Goodwill			711,656
Other intangible assets(1)			6,800
Total assets acquired		$	1,736,799
Current liabilities		$	131,881
Deferred income taxes			204,096
Decommissioning liabilities (including current portion)			20,044
Other non-current liabilities			1,800
Total liabilities assumed		$	357,821
Net assets acquired		$	1,378,978

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 the drilling is determined to be unsuccessful.

     At June 30, 2007, we had capitalized approximately $144.7 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, 2007 and December 31, 2006 (in thousands):

		June 30,				December 31,
		2007				2006
Noonan(1)		$	83,421			$	27,824
Danny(1)			15,286				—
Huey			11,570				11,378
East Cameron 169 #1(1)			8,481				—
Castleton (part of Gunnison)			7,070				7,070
High Island A466 #1(1)			6,785				—
Vermilion 348 #1(1)			5,342				—
South Marsh Island 123 #1			5,306				—
Other			1,475				3,711
Total		$	144,736			$	49,983

     As of June 30, 2007, all of these exploratory well costs had been capitalized for a period of one year or less, except for Huey and Castleton. 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, 2007 (in thousands):

		2007
Beginning balance at January 1,		$	49,983
Additions pending the determination of proved reserves			151,973
Reclassifications to proved properties			(57,104	)
Charged to dry hole expense			(116	)
Ending balance at June 30,		$	144,736

     Further, the following table details the components of exploration expense for the three and six months ended June 30, 2007 and 2006 (in thousands):

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2007				2006				2007				2006
Delay rental		$	1,612			$	126			$	1,638			$	290
Geological and geophysical costs			1,376				(456	)			2,414				739
Dry hole expense			(10	)			—				116				20,746
Total exploration expense		$	2,978			$	(330	)		$	4,168			$	21,775

     We agreed to participate in the drilling of an exploratory well (Tulane prospect) that was drilled in first quarter 2006. This prospect targeted reserves in deeper sands within the same trapping fault system of a currently producing well. In March 2006, mechanical difficulties were experienced in the drilling of this well, and after further review, the well was plugged and abandoned. Approximately $20.7 million related to this well was charged to earnings during the first half of 2006.

     In December 2006, we acquired a 100% working interest in the Camelot oil field in the North Sea for the assumption of certain decommissioning liabilities estimated at approximately $7.6 million. In June 2007, we sold a 50% working interest in this property for approximately $1.8 million and the assumption by the purchaser of 50% of the decommissioning liability of approximately $4.0 million. We recognized a gain of approximately $1.6 million as a result of this sale.

Note 7 – Details of Certain Accounts (in thousands)

     Other current assets consisted of the following as of June 30, 2007 and December 31, 2006:

		June 30,				December 31,
		2007				2006
Other receivables		$	3,214			$	3,882
Prepaid insurance			4,399				17,320
Other prepaids			17,435				9,174
Income tax receivable			14,013				—
Current deferred tax assets			5,947				3,706
Insurance claims to be reimbursed			6,809				3,627
Hedging assets			—				5,202
Gas imbalance			7,435				4,739
Spare parts inventory			8,773				3,660
Current notes receivable			—				1,500
Assets held for sale			—				698
Other			8,807				8,024
		$	76,832			$	61,532

     Other assets, net, consisted of the following as of June 30, 2007 and December 31, 2006:

		June 30,				December 31,
		2007				2006
Restricted cash		$	34,227			$	33,676
Deferred drydock expenses, net			45,024				26,405
Deferred financing costs			27,232				28,257
Intangible assets with definite lives, net			17,247				20,783
Intangible asset with indefinite life			7,100				6,922
Other			6,928				1,868
		$	137,758			$	117,911

     Accrued liabilities consisted of the following as of June 30, 2007 and December 31, 2006:

		June 30,				December 31,
		2007				2006
Accrued payroll and related benefits		$	21,445			$	42,381
Royalties payable			78,079				67,822
Current decommissioning liability			29,615				28,766
Insurance claims to be reimbursed			6,809				3,627
Accrued interest			11,098				15,579
Other			41,102				41,475
		$	188,148			$	199,650

Note 8 – Equity Investments

     As of June 30, 2007, 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 $113.3 million and $119.3 million as of June 30, 2007 and December 31, 2006, 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. The platform reached mechanical completion in May 2007. As a result, our performance guaranty related to Independence terminated in May 2007 with no further obligations. First production began in July 2007. Our investment in Independence was $95.8 million and $82.7 million as of June 30, 2007 and December 31, 2006, respectively (including capitalized interest of $6.5 million and $5.5 million at June 30, 2007 and December 31, 2006, respectively), and was included in our Production Facilities segment.
	•		OTSL. In July 2005, we acquired a 40% minority ownership interest in OTSL, now held through CDI, in exchange for our dynamically positioned dive support vessel, Witch Queen. OTSL provides marine construction services to the oil and gas industry in and around Trinidad and Tobago, as well as the U.S. Gulf of Mexico. We periodically review our equity investments for impairment. Recognition of an impairment occurs when the decline in an investment is deemed other than temporary. During the second quarter of 2007, OTSL generated significant operating losses, lost several project bids and ultimately decided to exit the saturation diving market. Based on these events, CDI determined that there were indicators of an impairment in its investment in OTSL. Additionally, OTSL had a significant working capital deficit which would require cash infusion before the end of the year to fund operations and working capital requirements. As a result, we evaluated this investment to determine whether a permanent loss in value had occurred. To determine whether OTSL had the ability to sustain a level of earnings that would justify the carrying amount of the investment, CDI considered the near-term and longer-term operating and financial prospects of OTSL, and CDI’s longer-term intent of retaining the investment in the entity. Based on this evaluation, CDI determined that there was an other than temporary impairment in OTSL at June 30, 2007 and the full value of its investment in OTSL was impaired and recognized equity losses of OTSL, inclusive of the impairment charge, of $11.8 million in the second quarter of 2007. In accordance with the terms of the OTSL agreement, CDI is not required to make additional investments and has no plans to make additional investments in OTSL and therefore will not be subject to future losses or impairments relating to its ownership interest. As of December 31, 2006, CDI’s investment in OTSL was $10.9 million.

Note 9 – Long-Term Debt

Senior Credit Facilities

     On July 3, 2006, we entered into a Credit Agreement (the “Credit Agreement”) with Bank of America, N.A., as administrative agent and as lender, together with the other lenders (collectively, the “Lenders”). Under the Credit Agreement, we borrowed $835 million in a term loan (the “Term Loan”) and may borrow up to $300 million (the “Revolving Loans”) under a revolving credit facility (the “Revolving Credit Facility”). In addition, the Revolving Credit Facility may be used for issuances of letters of credit up to an aggregate outstanding amount of $50 million. The proceeds from the Term Loan were used to fund the cash portion of the Remington acquisition. At June 30, 2007 and December 31, 2006, $828.7 million and $832.9 million, respectively, of the Term Loan was outstanding.

     The Term Loan matures on July 1, 2013 and is subject to scheduled principal payments of $2.1 million quarterly. The Revolving Loans mature on July 1, 2011. We may elect to prepay amounts outstanding under the Term Loan without prepayment penalty, but may not reborrow any amounts prepaid. We may prepay amounts outstanding under the Revolving Loans without prepayment penalty, and may reborrow amounts prepaid prior to maturity. We did not have any amount outstanding under the

Revolving Loans at June 30, 2007. The Credit Agreement includes terms, conditions and covenants that we consider customary for this type of facility. As of June 30, 2007, we were in compliance with these terms, conditions and covenants.

     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 three and six months ended June 30, 2007 was approximately 7.3% (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 Credit Agreement.

     As the rates for the Term Loan are subject to market influences and will vary over the term of the Credit Agreement, we entered into various interest rate swaps for $200 million of notional value effective as of October 3, 2006. These hedges are designated as cash flow hedges and qualify for hedge accounting. Under the swaps we receive interest based on three-month LIBOR and pay interest quarterly at an average annual fixed rate of 5.131% which began in October 2006. The objective of the hedges is to eliminate the variability of cash flows in the interest payments for up to $200 million of our Term Loan. Changes in the cash flows of the interest rate swap are expected to exactly offset the changes in cash flows (i.e., changes in interest rate payments) attributable to fluctuations in LIBOR on up to $200 million of our Term Loan.

Cal Dive International, Inc. Revolving Credit Facility

     In November 2006, CDI entered into a five-year $250 million revolving credit facility with certain financial institutions. The loans mature in November 2011. Loans under this facility are non-recourse to Helix. Loans under the revolving credit facility currently bear interest at the LIBOR rate plus a margin ranging from 0.625% to 1.75%. CDI’s interest rate on the credit facility for the three and six months ended June 30, 2007 was approximately 6.1% and 6.2%, respectively.

     The CDI credit agreement and the other documents entered into in connection with this credit facility include terms, conditions and covenants that are customary for this type of facility. At June 30, 2007, CDI was in compliance with these terms, conditions and covenants.

     At June 30, 2007 and December 31, 2006, CDI had outstanding debt of $140 million and $201 million, respectively, under this credit facility. CDI expects to use the remaining availability under the revolving credit facility for working capital and other general corporate purposes. We do not have access to any unused portion of CDI’s revolving credit facility.

Bridge Loan Commitment

     In July 2007, we entered into a commitment for a bridge loan facility with a financial institution. Under the commitment letter, the financial institution has provided us with an underwritten commitment to fund up to $100 million through October 1, 2007 to fund, to the extent our Revolving Credit Facility is not available, the cash portion of any conversion payments required to be made upon conversion of our 3.25% Convertible Senior Notes due 2025 (“Convertible Senior Notes”) (see below) during third quarter 2007. The amount that may be drawn under this facility will be due on December 31, 2008. This facility bears interest based on one-, two-, three- or six-month LIBOR, at our election, plus a margin of 2.00% prior to April 1, 2008 and 4.00% thereafter. In the event the facility is drawn upon, the commitment letter provides the lender with substantial flexibility to replace or restructure the debt prior to December 31, 2008 through alternative debt instruments (such as high yield bonds).

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 2007, 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 29, 2007 exceeded 120% of the conversion price (i.e. $38.56 per share). As a result, pursuant to the terms of the indenture, the Convertible Senior Notes can be converted during third quarter 2007. As we have sufficient financing available under our Revolving Credit Facility and a commitment from a financial institution to fully fund the cash portion of the potential conversion, the Convertible Senior Notes continue to be classified as a long-term liability in the accompanying balance sheet. 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 1.6 million shares and 977,000 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, 2007, respectively, and approximately 1.3 million shares and 1.2 million shares for the three and six months ended June 30, 2006, respectively, because our average share price for the respective periods was above the conversion price of approximately $32.14 per share. As a result, there would be a premium over the principal amount, which is paid in cash, and the 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, 2007 and December 31, 2006, $129.4 million and $131.3 million was outstanding on our long-term financing for construction of the Q4000. This U.S. government guaranteed financing is pursuant to Title XI of the Merchant Marine Act of 1936 which is administered by the Maritime Administration (“MARAD Debt”). The MARAD Debt is payable in equal semi-annual installments which began in August 2002 and matures 25 years from such date. The MARAD Debt is collateralized by the Q4000, with us guaranteeing 50% of the debt, and initially bore interest at a floating rate which approximated AAA Commercial Paper yields plus 20 basis points. As provided for in the MARAD Debt agreements, in September 2005, we fixed the interest rate on the debt through the issuance of a 4.93% fixed-rate note with the same maturity date (February 2027). In accordance with the MARAD Debt agreements, we are required to comply with certain covenants and restrictions, including the maintenance of minimum net worth, working capital and debt-to-equity requirements. As of June 30, 2007, we were in compliance with these covenants and restrictions.

     In September 2005, we entered into an interest rate swap agreement with a bank. The swap was designated as a cash flow hedge of a forecasted transaction in anticipation of the refinancing of the MARAD Debt from floating rate debt to fixed-rate debt that closed on September 30, 2005. The interest rate swap agreement totaled an aggregate notional amount of $134.9 million with a fixed interest rate of 4.695%. On September 30, 2005, we terminated the interest rate swap and received cash proceeds of approximately $1.5 million representing a gain on the interest rate differential. This gain was deferred and is being amortized over the remaining life of the MARAD Debt as an adjustment to interest expense.

Other

     In connection with the acquisition of Helix Energy Limited, we issued a two-year note payable to the former owners totaling approximately £3.1 million, or approximately $5.6 million, on November 3, 2005 (the balance was approximately $6.3 million and $6.2 million at June 30, 2007 and at December 31, 2006, respectively). The note bears interest at a LIBOR based floating rate with interest payments due quarterly beginning January 1, 2006. The note is due in November 2007.

     Deferred financing costs of $27.2 million and $28.3 million are included in other assets, net as of June 30, 2007 and December 31, 2006, respectively, and are being amortized over the life of the respective agreement.

     Scheduled maturities of long-term debt and capital lease obligations outstanding as of June 30, 2007 were as follows (in thousands):

						CDI
						Revolving				Convertible
		Term				Credit				Senior				MARAD				Loan				Capital
		Loan				Facility				Notes				Debt				Notes(1)				Leases				Total
Less than one year		$	8,400			$	—			$	—			$	3,917			$	11,303			$	2,545			$	26,165
One to two years			8,400				—				—				4,113				—				230				12,743
Two to Three years			8,400				—				—				4,318				—				—				12,718
Three to four years			8,400				—				—				4,533				—				—				12,933
Four to five years			8,400				140,000				—				4,760				—				—				153,160
Over five years			786,700				—				300,000				107,757				—				—				1,194,457
Long-term debt			828,700				140,000				300,000				129,398				11,303				2,775				1,412,176
Current maturities			(8,400	)			—				—				(3,917	)			(11,303	)			(2,545	)			(26,165	)
Long-term debt, less current maturities		$	820,300			$	140,000			$	300,000			$	125,481			$	—			$	230			$	1,386,011

     We had unsecured letters of credit outstanding at June 30, 2007 totaling approximately $35.3 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, 2007 and 2006 (in thousands):

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2007				2006				2007				2006
Interest expense		$	23,153			$	5,063			$	46,246			$	9,598
Interest income			(1,933	)			(644	)			(6,575	)			(1,463	)
Capitalized interest			(6,396	)			(1,233	)			(11,799	)			(2,411	)
Interest expense, net		$	14,824			$	3,186			$	27,872			$	5,724

     The carrying amount and estimated fair value of our debt instruments, including current maturities as of June 30, 2007 and December 31, 2006 were as follows (amount in thousands):

		June 30, 2007								December 31, 2006
		Carrying				Fair				Carrying				Fair
		Value				Value				Value				Value
Term Loan(1)		$	828,700			$	830,772			$	832,900			$	834,462
Cal Dive Revolving Credit Facility(2)			140,000				140,000				201,000				201,000
Convertible Senior Notes(1)			300,000				429,600				300,000				378,780
MARAD Debt(3)			129,398				120,599				131,286				126,691
Loan Notes(4)			11,303				11,303				11,146				11,146

Note 10 – Income Taxes

     The effective tax rate for the three and six months ended June 30, 2007 was 35.0% and 34.4%, respectively. The effective tax rate for the three and six months ended June 30, 2006 was 33.9% and 34.0%, respectively. The effective tax rate for the second quarter of 2007 was primarily increased by non-cash equity losses and the related impairment charge in connection with CDI’s investment in OTSL for which minimal tax benefit was recorded and a $2.0 million nondeductible accrual by CDI for a cash settlement to be paid for a civil claim by the Department of Justice related to the consent decree Cal Dive entered into in connection with the Acergy US Inc. (“Acergy”) and Torch Offshore, Inc. (“Torch”) acquisitions in 2005. This increase was partially offset by lower effective tax rates in foreign jurisdictions.

     We adopted the provisions of FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes (“FIN 48”) on January 1, 2007. The impact of the adoption of FIN 48 was immaterial on our financial position, results of operations and cash flows. We record tax related interest in interest expense and tax penalties in operating expenses as allowed under FIN 48. As of June 30, 2007, we had no material unrecognized tax benefits and no material interest and penalties were recognized.

     We file tax returns in the U.S. and in various state, local and non-U.S. jurisdictions. We anticipate that any potential adjustments to our state, local and non-U.S. jurisdiction tax returns by tax authorities would not have a material impact on our financial position. The tax periods ending December 31, 2002, 2003, 2004, 2005 and 2006 remain subject to examination by the U.S. Internal Revenue Service (“IRS”). In addition, as we acquired Remington on July 1, 2006, we are exposed to any tax uncertainties related to Remington. For Remington, the tax periods ending December 31, 2003, 2004, 2005, and June 30, 2006 remain subject to examination by the IRS. The 2004 and 2005 tax returns for Remington are currently under examination by the IRS. The 2004 tax return includes the utilization of a net operating loss generated prior to 1999. As of June 30, 2007, the IRS has not issued any proposed adjustments for the years under examination.

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 involve the use of derivative financial instruments to hedge the impact of market price risk exposures primarily related to our oil and gas production, variable interest rate exposure and foreign currency exchange rate exposure. All derivatives are reflected in our balance sheet at fair value, unless otherwise noted.

Commodity Hedges

     We have entered into various cash flow hedging costless collar 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) asset of $(339,000) and $5.2 million as of June 30, 2007 and December 31, 2006, respectively. 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, respectively, during the three and six months ended June 30, 2007, 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, 2006, we recorded $(788,000) and $2.4 million, respectively, of unrealized (losses) gains, net of tax (benefit) expense of $(424,000) and $1.3 million, respectively. During the three and six months ended June 30, 2007, we reclassified approximately $152,000 and $2.3 million of gains, respectively, 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, 2006, we reclassified approximately $1.4 million and $6.3 million, respectively, of gains from other comprehensive income to net revenues.

     As of June 30, 2007, we had the following volumes under derivative contracts related to our oil and gas producing activities totaling 1,140 MBbl of oil and 15,350 MMbtu of natural gas:

		Instrument		Average		Weighted
Production Period		Type		Monthly Volumes		Average Price
Crude Oil:
July 2007 – December 2007		Collar		100 MBbl		$50.00 — $67.98
January 2008 – December 2008		Collar		45 MBbl		$56.57 — $76.51
Natural Gas:
July 2007 – December 2007		Collar		1,283,333 MMBtu		$7.50 — $10.05
January 2008 – December 2008		Collar		637,500 MMBtu		$7.32 — $10.87

     We have not entered into any hedge instruments subsequent to June 30, 2007. 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.

     As of June 30, 2007, we had natural gas forward sales contracts for the period from April 2008 through December 2008. The contracts cover an average of 317,178 MMBtu per month at a weighted average price of $8.40. Subsequent to June 30, 2007, we entered into five additional natural gas forward sales contracts and one oil forward sales contract. Gas forward sales contracts cover the period from October 2007 through December 2008. The contracts cover an average of 541,667 MMBtu per month at a weighted average price of $8.31. The oil forward sales contract is for the period of October 2007 through December 2008. The contract covers an average of 41 MBbl per month at a price of $72.20. Hedge accounting does not apply to these contracts as these contracts qualify as normal purchases and sales transactions.

Interest Rate Hedge

     As the rates for our Term Loan are subject to market influences and will vary over the term of the loan, we entered into various cash flow hedging interest rate swaps to stabilize cash flows relating to a portion of our interest payments for our Term Loan. The interest rate swaps were effective October 3, 2006. These interest rate swaps qualify for hedge accounting. See “–Note 9 – Long-Term Debt” above for a detailed discussion of our Term Loan. The aggregate fair value of the hedge instruments was a net asset (liability) of $648,000 and $(531,000) as of June 30, 2007 and December 31, 2006, respectively. For the three and six months ended June 30, 2007, we recorded unrealized gains of approximately $1.2 million and $952,000, respectively, net of tax expense of $642,000 and $413,000, respectively, in accumulated other comprehensive income, a component of shareholders’ equity, as these hedges were highly effective.

Foreign Currency Hedge

     In December 2006, we entered into various foreign currency forward purchase contracts to stabilize expected cash outflows relating to a shipyard contract where the contractual payments are denominated in euros. These forward contracts qualify for hedge accounting. Under the forward contracts, we hedged €7.0 million that was settled in June 2007 at an exchange rate of 1.3255 and €11.0 million at an exchange rate of 1.3326 to be settled in December 2007. In June 2007, we settled €7.0 million of our foreign currency forward contract and recognized a gain of $68,000, and subsequently entered into a €14.0 million foreign currency forward contract that was settled in July 2007. The aggregate fair value of the hedge instruments was a net asset (liability) of $576,000 and ($184,000) as of June 30, 2007 and December 31, 2006, respectively. For the three and six months ended June 30, 2007, we recorded unrealized gains of approximately $227,000 and $558,000, respectively, net of tax expense of $122,000 and $266,000, respectively, in accumulated other comprehensive income, a component of shareholders’ equity, as these hedges were highly effective.

Note 12 – Comprehensive Income

     The components of total comprehensive income for the three and six months ended June 30, 2007 and 2006 were as follows (in thousands):

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2007				2006				2007				2006
Net income		$	58,647			$	69,944			$	115,412			$	126,137
Foreign currency translation gain			4,078				7,846				4,715				9,006
Unrealized gain (loss) on hedges, net			6,098				(788	)			(2,091	)			2,443
Total comprehensive income		$	68,823			$	77,002			$	118,036			$	137,586

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

		June 30,				December 31,
		2007				2006
Cumulative foreign currency translation adjustment		$	29,295			$	24,580
Unrealized gain on hedges, net			565				2,656
Accumulated other comprehensive income		$	29,860			$	27,236

Note 13 – 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 amounts were as follows (in thousands):

		Three Months Ended								Three Months Ended
		June 30, 2007								June 30, 2006
		Income				Shares				Income				Shares
Earnings applicable per common share — Basic		$	57,702				90,047			$	69,139				78,462
Effect of dilutive securities:
Stock options			—				383				—				414
Restricted shares			—				284				—				137
Employee stock purchase plan			—				19				—				4
Convertible Senior Notes			—				1,627				—				1,317
Convertible preferred stock			945				3,631				805				3,631
Earnings applicable per common share — Diluted		$	58,647				95,991			$	69,944				83,965

		Six Months Ended								Six Months Ended
		June 30, 2007								June 30, 2006
		Income				Shares				Income				Shares
Earnings applicable per common share — Basic		$	113,522				90,021			$	124,528				78,216
Effect of dilutive securities:
Stock options			—				375				—				513
Restricted shares			—				227				—				122
Employee stock purchase plan			—				32				—				7
Convertible Senior Notes			—				976				—				1,170
Convertible preferred stock			1,890				3,631				1,609				3,631
Earnings applicable per common share — Diluted		$	115,412				95,262			$	126,137				83,659

     There were no antidilutive stock options in the three and six months ended June 30, 2007 and 2006 as the option strike price was below the average market price for the applicable periods. Net income for the diluted earnings per share calculation for

the three and six months ended June 30, 2007 and 2006 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 14 – 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 a stock-based compensation plan, the 2006 Long-Term Incentive Plan (the “CDI Incentive Plan”) available only to the employees of CDI and its subsidiaries.

     We began accounting for our stock-based compensation plans under the fair value method beginning January 1, 2006. We continue to use the Black-Scholes option pricing model for valuing stock options and recognize compensation cost for our share-based payments on a straight-line basis over the applicable vesting period. During the six months ended June 30, 2007, we granted 686,912 shares of restricted shares to certain key executives, selected management employees and non-employee members of the board of directors under the 2005 Incentive Plan. The average market value of the restricted shares was $31.55 per share, or $21.7 million, at the date of grant. For 2007 restricted share grants to executives and selected management employees, at the grant date we estimated that 8% may be forfeited as the number of restricted stock recipients has increased. No forfeitures were estimated for outstanding unvested options and restricted shares granted prior to January 1, 2007 as historical forfeitures have been immaterial. There were no stock option grants in the first half of 2007 and 2006.

     For the three and six months ended June 30, 2007, $265,000 and $530,000, respectively, was recognized as compensation expense related to stock options. Future compensation cost associated with unvested options at June 30, 2007 was approximately $1.3 million. The weighted average vesting period related to unvested stock options at June 30, 2007 was approximately 1.2 years. For the three and six months ended June 30, 2007, $3.0 million and $5.9 million (of which $519,000 and $ 1.0 million, respectively, of expense is related to the CDI Incentive Plan), respectively, were recognized as compensation expense related to restricted shares. For the three and six months ended June 30, 2006, $1.3 million and $2.5 million, respectively, were recognized as compensation expense related to restricted shares. Future compensation cost associated with unvested restricted shares at June 30, 2007 was approximately $41.0 million, of which $7.7 million is related to the CDI Incentive Plan. The weighted average vesting period related to unvested restricted shares of our common stock at June 30, 2007 was approximately 3.8 years.

Employee Stock Purchase Plan

     Effective May 12, 1998, we adopted a qualified, non-compensatory ESPP, which allows employees to acquire shares of common stock through payroll deductions over a six-month period. The purchase price is equal to 85 percent 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 percent of an employee’s base salary or up to $25,000 of our stock value. In January and July 2007, we issued 109,754 and 113,230 shares, respectively, of our common stock to our employees under this plan, which increased our common stock outstanding. We subsequently repurchased the same number of shares of our common stock in the open market at $29.94 and $40.00 per share in January and July 2007, respectively, and reduced the number of shares of our common stock outstanding. During the six months ended June 30, 2006, 41,006 shares of common stock were purchased in the open market at a share price of $26.14. For the three and six months ended June 30, 2007, we recognized $496,000 and $996,000, respectively, of compensation expense related to stock purchased under the ESPP. For the six months ended June 30, 2006, we recognized $568,000 of compensation expense related to stock purchased under the ESPP.

Note 15 – 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 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 deepwater pipelay, well operations, robotics and reservoir and well tech services. The Shelf Contracting segment consists of assets deployed primarily for diving-related activities and shallow water construction. See “— Note 4—Initial Public Offering of Cal Dive International, Inc.” for discussion of the initial public offering of CDI common stock (represented by the Shelf Contracting segment). All material intercompany transactions between 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,
		2007				2006				2007				2006
Revenues -
Contracting Services		$	154,719			$	112,590			$	292,436			$	213,620
Shelf Contracting			135,258				124,764				284,484				244,554
Oil and Gas			142,082				81,110				273,049				161,423
Intercompany elimination			(21,485	)			(13,451	)			(43,340	)			(22,936	)
Total		$	410,574			$	305,013			$	806,629			$	596,661
Income from operations -
Contracting Services		$	31,987			$	18,653			$	55,082			$	39,193
Shelf Contracting			36,142				51,599				84,445				95,917
Production Facilities equity investments(1)			(145	)			(335	)			(332	)			(653	)
Oil and Gas			48,685				35,374				87,902				52,339
Intercompany elimination			(2,608	)			(997	)			(8,021	)			(997	)
Total		$	114,061			$	104,294			$	219,076			$	185,799
Equity in earnings (losses) of OTSL, inclusive of impairment		$	(11,793	)		$	(183	)		$	(10,841	)		$	2,650
Equity in earnings of equity investments excluding OTSL		$	7,045			$	4,703			$	12,197			$	8,106

		June 30,				December 31,
		2007				2006
Identifiable Assets -
Contracting Services		$	1,045,031			$	1,313,206
Shelf Contracting			445,608				452,153
Production Facilities			285,848				242,113
Oil and Gas			2,490,662				2,282,715
Total		$	4,267,149			$	4,290,187

          Intercompany segment revenues during the three and six months ended June 30, 2007 and 2006 were as follows:

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2007				2006				2007				2006
Contracting Services		$	16,901			$	10,215			$	31,497			$	18,192
Shelf Contracting			4,584				3,236				11,843				4,744
Total		$	21,485			$	13,451			$	43,340			$	22,936

          Intercompany segment profit (which related primarily to intercompany capital projects) during the three and six months ended June 30, 2007 and 2006 was as follows:

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2007				2006				2007				2006
Contracting Services		$	657			$	248			$	2,675			$	248
Shelf Contracting			1,951				749				5,346				749
Total		$	2,608			$	997			$	8,021			$	997

          During the three and six months ended June 30, 2007, we derived $56.8 million and $97.4 million, respectively, of our revenues from our operations in the United Kingdom, utilizing $257.5 million of our total assets in this region. During the three and six months ended June 30, 2006, we derived $33.2 million and $62.3 million, respectively, of our revenues from our operations in the United Kingdom, utilizing $185.8 million of our total assets in this region. The majority of the remaining revenues were generated in the U.S. Gulf of Mexico.

Note 16 – Related Party Transactions

          In April 2000, we acquired a 20% working interest in Gunnison, a Deepwater Gulf of Mexico prospect of Kerr-McGee Oil & Gas Corporation (“Kerr-McGee”). Financing for the exploratory costs of approximately $20 million was provided by an investment partnership (OKCD Investments, Ltd. or “OKCD”) in exchange for a revenue interest that is an overriding royalty interest of 25% of our 20% working interest. The investors of OKCD include certain current and former members of Helix senior management. Production began in December 2003. Payments to OKCD from us totaled $5.7 million and $11.7 million in the three and six months ended June 30, 2007, respectively, and $9.0 million and $19.4 million in the three and six months ended June 30, 2006.

Note 17 – 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 be approximately $135 million, of which approximately $45.4 million had been incurred, with an additional $57.9 million committed, at June 30, 2007. The initial budget for this conversion was $110 million. The increase in projected cost relates primarily to the weakening of the U.S. dollar versus the applicable foreign currency and escalating costs for certain materials and services due to increasing demand. In addition, we will upgrade the Q4000 to include drilling capability by adding a modular-based drilling system, and will also perform thruster modifications and other significant upgrades on the vessel. The total cost for all of these activities is estimated to be approximately $75 million, of which approximately $32.3 million had been incurred, with an additional $25.1 million committed, at June 30, 2007.

          We are also constructing a $183 million multi-service dynamically positioned dive support/well intervention vessel (“Well Enhancer”) that will be capable of working in the North Sea and West of

Shetlands to support our expected growth in that region. The initial budget for this vessel was $160 million. The increase in projected cost relates primarily to the weakening of the U.S. dollar versus the applicable foreign currency and escalating costs for certain materials and services due to increasing demand. We expect the Well Enhancer to join our fleet in 2008. At June 30, 2007, we had incurred approximately $25.3 million, with an additional $95.8 million committed to this project.

          Further, we, along with Kommandor RØMØ, a Danish corporation, formed Kommandor LLC to convert a ferry vessel into a floating production unit to be named the Helix Producer I (the “Vessel”). The cost of the ferry and the conversion is approximately $89 million. Kommandor RØMØ and we are each responsible for 50% of the agreed Vessel and conversion cost. Upon completion of the conversion, scheduled for the end of 2007, we will charter the Vessel from Kommandor LLC, and will install, at 100% our cost, processing facilities and a disconnectable fluid transfer system (“DTS”) on the Vessel for use on our Phoenix field. The cost of these additional facilities is approximately $100 million. 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, 2007 in our Production Facilities segment. Kommandor LLC has been a development stage enterprise since its formation in October 2006.

          On June 19, 2007, Kommandor LLC entered into a term loan agreement (“Loan Agreement”) with Nordea Bank Norge ASA. Pursuant to the Loan Agreement, the lenders will make available to Kommandor up to $45.0 million pursuant to a secured term loan facility. Kommandor 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 expects this borrowing to occur at the end of 2007 or in the first quarter of 2008 upon the delivery of the Vessel after its 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.

          In addition, as of June 30, 2007, we have also committed approximately $34.6 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 royalty on certain federal leases. 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 Deep Water 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 such as ours. 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. As a result of this dispute, we have recorded reserves for the disputed royalties (and any other royalties that may be claimed from the Gunnison leases), plus interest at 5%, for our portion of the Gunnison related MMS claim. The total

reserved amount at June 30, 2007 and December 31, 2006 was approximately $48.6 million and $42.6 million, respectively. At this time, it is not anticipated that any penalties would be assessed if we are unsuccessful in our appeal.

          Although the above discussed matters may have the potential for additional liability and may have an impact on our consolidated financial results for a particular reporting period, we believe that the outcome of all such matters and proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.

Note 18 – Recently Issued Accounting Principles

          In September 2006, the FASB issued Statement of Financial Accounting Standard No. 157, Fair Value Measurements (“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles and expands disclosures about fair value measurements. The provisions of SFAS No. 157 are effective for fiscal years beginning after November 15, 2007. We are currently evaluating the impact, if any, of adopting this statement.

          In February 2007, the FASB issued Statement of Financial Accounting Standard No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS No. 159”). SFAS No. 159 allows entities to voluntarily choose, at specified election dates, to measure many financial assets and financial liabilities at fair value. The election is made on an instrument-by-instrument basis and is irrevocable. If the fair value option is elected for an instrument, SFAS No. 159 specifies that all subsequent changes in fair value for that instrument shall be reported in earnings. The provisions of SFAS No. 159 are effective for fiscal years beginning after November 15, 2007. We are currently evaluating the impact, if any, of adopting this statement.

Note 19 – Pending Transaction

          On June 11, 2007, CDI and Horizon Offshore, Inc. (“Horizon”) announced that they had entered into an agreement under which CDI will acquire Horizon in a transaction valued at approximately $650 million, including approximately $22 million of Horizon’s net debt as of March 31, 2007. Under the terms of the agreement, Horizon stockholders will receive a combination of $9.25 in cash and 0.625 shares of CDI common stock for each Horizon common stock outstanding, or an estimated total of $302.5 million in cash and 20.4 million shares of CDI common stock. The expected issuance of this equity will reduce our majority interest in CDI from approximately 73% to approximately 59%. The boards of directors of CDI and Horizon unanimously approved the transaction. Closing of the transaction is subject to regulatory approvals and other customary conditions, as well as Horizon stockholder approval.

          In limited circumstances, if Horizon fails to close the transaction, it must pay Cal Dive a termination fee of $18.9 million. Cal Dive obtained a commitment from a bank to fund the cash portion of the transaction consideration through a $675 million commitment from a bank, consisting of a $375 million senior secured term loan and a $300 million senior secured revolving credit facility which are non-recourse to Helix.

Note 20 – Subsequent Event

          In October 2006, we acquired a 58% interest in Seatrac Pty Ltd. (“Seatrac”) for total consideration of approximately $12.7 million (including $180,000 of transaction costs), with approximately $9.1 million paid to existing shareholders and $3.4 million for subscription of new Seatrac shares. We have changed the name of this entity to Well Ops SEA Pty Ltd. 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 purchased the remaining 42% of the entity. 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.

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 certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of 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, other than statements of historical facts, included herein or incorporated herein by reference are forward-looking statements. Included among forward-looking statements are, among other things:

	•		statements related to the volatility in commodity prices for oil and gas and in the supply of and demand for oil and gas or the ability to replace oil and gas reserves;
	•		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 property or well;
	•		statements regarding any financing transactions or arrangements, or ability to enter into such transactions;
	•		statements relating to the construction or acquisition of vessels or equipment and our proposed acquisition of any producing property or well prospect, including statements concerning the engagement of any engineering, procurement and construction contractor and any anticipated costs related thereto;
	•		statements that our proposed vessels, when completed, will have certain characteristics or the effectiveness of such characteristics;
	•		statements regarding projections of revenues, gross margin, expenses, earnings or losses or other financial items;
	•		statements regarding our business strategy, our business plans or any other plans, forecasts or objectives, any or all of which are subject to change;
	•		statements regarding any Securities and Exchange Commission or other governmental or regulatory inquiry or investigation;
	•		statements regarding anticipated legislative, governmental, regulatory, administrative or other public body actions, requirements, permits or decisions;
	•		statements regarding anticipated developments, industry trends, performance or industry ranking relating to our services or any statements related to the underlying assumptions related to any projection or forward-looking statement;
	•		statements related to environmental risks, drilling and operating risks, or exploration and development risks and the ability of the combined company to retain key members of its senior management and key employees;
	•		statements regarding general economic or political conditions, whether internationally, nationally or in the regional and local market areas in which we are doing business; and
	•		any other statements that relate to non-historical or future information.

          These forward-looking statements are often identified by the use of terms and phrases such as “achieve,” “anticipate,” “believe,” “estimate,” “expect,” “forecast,” “plan,” “project,” “propose,” “strategy,” “predict,” “envision,” “hope,” “intend,” “will,” “continue,” “may,” “potential,” “achieve,” “should,” “could” and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve assumptions, risks and uncertainties, and these expectations may prove to be incorrect. You should not place undue reliance on these forward-looking statements.

          Our actual results could differ materially from those anticipated in these forward-looking statements as a result of a variety of factors, including those described under the heading “Risk Factors” in our 2006 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.

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. There have been no material changes or developments in authoritative accounting pronouncements or in our evaluation of the accounting estimates and the underlying assumptions or methodologies that we believe would change the Critical Accounting Policies and Estimates as disclosed in our 2006 Form 10-K.

Recently Issued Accounting Principles

          In September 2006, the FASB issued SFAS No. 157. This statement defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles and expands disclosures about fair value measurements. The provisions of SFAS No. 157 are effective for fiscal years beginning after November 15, 2007. We are currently evaluating the impact, if any, of adopting this statement.

          In February 2007, the FASB issued SFAS No. 159, which allows entities to voluntarily choose, at specified election dates, to measure many financial assets and financial liabilities at fair value. The election is made on an instrument-by-instrument basis and is irrevocable. If the fair value option is elected for an instrument, SFAS No. 159 specifies that all subsequent changes in fair value for that instrument shall be reported in earnings. The provisions of SFAS No. 159 are effective for fiscal years beginning after November 15, 2007. We are currently evaluating the impact, if any, of adopting this statement.

RESULTS OF OPERATIONS

          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 131. 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 deepwater pipelay, well operations, robotics and reservoir and well tech services. The Shelf Contracting segment consists of assets deployed primarily for diving-related activities and shallow water construction. See “—Note 4 – Initial Public Offering of Cal Dive International, Inc.” for discussion of the initial public offering of CDI common stock (represented by the Shelf Contracting segment). All material intercompany transactions between the segments have been eliminated in our consolidated results of operations.

Comparison of Three Months Ended June 30, 2007 and 2006

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

		Three Months Ended
		June 30,								Increase/
		2007				2006				(Decrease)
Revenues (in thousands) –
Contracting Services		$	154,719			$	112,590			$	42,129
Shelf Contracting			135,258				124,764				10,494
Oil and Gas			142,082				81,110				60,972
Intercompany elimination			(21,485	)			(13,451	)			(8,034	)
		$	410,574			$	305,013			$	105,561
Gross profit (in thousands) –
Contracting Services		$	43,071			$	30,247			$	12,824
Shelf Contracting			45,565				60,943				(15,378	)
Oil and Gas			55,737				41,499				14,238
Intercompany elimination			(2,608	)			(997	)			(1,611	)
		$	141,765			$	131,692			$	10,073
Gross Margin –
Contracting Services			28	%			27	%		1 pt
Shelf Contracting			34	%			49	%		(15) pts
Oil and Gas			39	%			51	%		(12) pts
Total company			35	%			43	%		(8) pts
Number of vessels(1)/ Utilization(2) –
Contracting Services:
Pipelay			2/70	%			3/85	%
Well operations			2/94	%			2/83	%
ROVs			39/86	%			31/75	%
Shelf Contracting			25/63	%			24/87	%

          Intercompany segment revenues during the three months ended June 30, 2007 and 2006 were as follows (in thousands):

		Three Months Ended
		June 30,								Increase/
		2007				2006				(Decrease)
Contracting Services		$	16,901			$	10,215			$	6,686
Shelf Contracting			4,584				3,236				1,348
		$	21,485			$	13,451			$	8,034

          Intercompany segment profit (which related primarily to intercompany capital projects) during the three months ended June 30, 2007 and 2006 was as follows (in thousands):

		Three Months Ended
		June 30,								Increase/
		2007				2006				(Decrease)
Contracting Services		$	657			$	248			$	409
Shelf Contracting			1,951				749				1,202
		$	2,608			$	997			$	1,611

          The following table details various financial and operational highlights related to our Oil and Gas segment for the periods presented (price volume analysis relates to U.S. operations only):

		Three Months Ended
		June 30,								Increase/
		2007				2006				(Decrease)
Oil and Gas information–
Oil production volume (MBbls)			938				642				296
Oil sales revenue (in thousands)		$	58,429			$	41,721			$	16,708
Average oil sales price per Bbl (excluding hedges)		$	62.78			$	66.69			$	(3.91	)
Average realized oil price per Bbl (including hedges)		$	62.32			$	64.98			$	(2.66	)
Increase (decrease) in oil sales revenue due to:
Change in prices (in thousands)		$	(1,704	)
Change in production volume (in thousands)			18,412
Total increase in oil sales revenue (in thousands)		$	16,708
Gas production volume (MMcf)			10,144				4,798				5,346
Gas sales revenue (in thousands)		$	81,738			$	38,573			$	43,165
Average gas sales price per mcf (excluding hedges)		$	8.00			$	7.51			$	0.49
Average realized gas price per mcf (including hedges)		$	8.06			$	8.04			$	0.02
Increase (decrease) in gas sales revenue due to:
Change in prices (in thousands)		$	88
Change in production volume (in thousands)			43,077
Total increase in gas sales revenue (in thousands)		$	43,165
Total production (MMcfe)			15,772				8,650				7,122
Price per Mcfe		$	8.89			$	9.28			$	(0.39	)
Oil and Gas revenue information (in thousands)–
Oil and gas sales revenue		$	140,167			$	80,294			$	59,873
Miscellaneous revenues(1)			1,915				816				1,099
		$	142,082			$	81,110			$	60,972