Helix Energy Solutions (HLX) 10-Q 2006 Q1 Quarterly report

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 March 31, 2006

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 000-22739

HELIX ENERGY SOLUTIONS GROUP, INC.

(Exact name of registrant as specified in its charter)

Minnesota	95–3409686
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
400 N. Sam Houston Parkway E. 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, 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 May 4, 2006, 78,450,664 shares of common stock were outstanding.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION	PAGE
Item 1. Financial Statements:
Condensed Consolidated Balance Sheets – March 31, 2006 (Unaudited) and December 31, 2005		1
Condensed Consolidated Statements of Operations (Unaudited) – Three months ended March 31, 2006 and 2005		2
Condensed Consolidated Statements of Cash Flows (Unaudited) – Three months ended March 31, 2006 and 2005		3
Notes to Condensed Consolidated Financial Statements (Unaudited)		4
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		20
Item 3. Quantitative and Qualitative Disclosures About Market Risk		29
Item 4. Controls and Procedures		30
PART II. OTHER INFORMATION
Item 1. Legal Proceedings		31
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		31
Item 6. Exhibits		31
Signatures		32
Index to Exhibits		33
Independent Registered Public Accounting Firm's Acknowledgement Letter
Certification Pursuant to Rule 13a-14a, CEO
Certification Pursuant to Rule 13a-14a, CFO
Section 1350 Certification by CEO
Section 1350 Certification by CFO
Report of Independent Registered Public Accounting Firm

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands)

	March 31,			December 31,
	2006			2005
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	37,833		$	91,080
Accounts receivable —
Trade, net of allowance for uncollectible accounts of $832 and $585		199,242			197,046
Unbilled revenue		34,638			31,012
Other current assets		59,478			52,915
Total current assets		331,191			372,053
Property and equipment		1,387,546			1,259,014
Less — Accumulated depreciation		(367,721	)		(342,652	)
		1,019,825			916,362
Other assets:
Equity investments		193,735			179,556
Goodwill, net		106,251			101,731
Other assets, net		91,849			91,162
	$	1,742,851		$	1,660,864
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	115,314		$	99,445
Accrued liabilities		126,879			145,752
Current maturities of long-term debt		6,438			6,468
Total current liabilities		248,631			251,665
Long-term debt		438,256			440,703
Deferred income taxes		178,015			167,295
Decommissioning liabilities		108,875			106,317
Other long-term liabilities		9,121			10,584
Total liabilities		982,898			976,564
Convertible preferred stock		55,000			55,000
Commitments and contingencies Shareholders’ equity:
Common stock, no par, 240,000 shares authorized, 105,609 and 104,898 shares issued		242,056			233,537
Retained earnings		464,136			408,748
Treasury stock, 27,209 and 27,204 shares, at cost		(3,900	)		(3,741	)
Unearned compensation		—			(7,515	)
Accumulated other comprehensive income (loss)		2,661			(1,729	)
Total shareholders’ equity		704,953			629,300
	$	1,742,851		$	1,660,864

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

1

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(in thousands, except per share amounts)

	Three Months Ended
	March 31,
	2006		2005
Net revenues	$	291,648	$	159,575
Cost of sales		189,382		107,702
Gross profit		102,266		51,873
Gain on sale of assets		267		—
Selling and administrative expenses		21,028		12,837
Income from operations		81,505		39,036
Equity in earnings of investments		6,236		1,729
Net interest expense and other		2,457		264
Income before income taxes		85,284		40,501
Provision for income taxes		29,091		14,540
Net Income		56,193		25,961
Preferred stock dividends		804		550
Net income applicable to common shareholders	$	55,389	$	25,411
Earnings per common share:
Basic	$	0.71	$	0.33
Diluted	$	0.67	$	0.32
Weighted average common shares outstanding:
Basic		77,969		77,143
Diluted		83,803		81,739

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

2

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(in thousands)

	Three Months Ended
	March 31,
	2006			2005
Cash flows from operating activities:
Net income	$	56,193		$	25,961
Adjustments to reconcile net income to net cash provided by operating activities —
Depreciation and amortization		33,226			26,723
Asset impairment charge		20,746			—
Equity in earnings of investments, net of distributions		(2,803	)		—
Amortization of deferred financing costs		289			260
Stock compensation expense		1,565			194
Deferred income taxes		7,789			14,540
Gain on sale of assets		(267	)		(925	)
Excess tax benefit from stock-based compensation		(6,738	)		—
Changes in operating assets and liabilities:
Accounts receivable, net		(3,016	)		4,205
Other current assets		1,702			6,958
Accounts payable and accrued liabilities		(15,039	)		(8,860	)
Other noncurrent, net		(6,117	)		(2,028	)
Net cash provided by operating activities		87,530			67,028
Cash flows from investing activities:
Capital expenditures		(61,461	)		(24,472	)
Investments in production facilities		(11,373	)		(78,327	)
Acquisition of businesses, net of cash acquired		(77,927	)		—
Distributions from equity investments, net		635			9,847
(Increase) decrease in restricted cash		(3,038	)		2,423
Proceeds from sales of property		1,531			2,150
Net cash used in investing activities		(151,633	)		(88,379	)
Cash flows from financing activities:
Borrowings on Convertible Senior Notes		—			300,000
Repayment of MARAD borrowings		(1,798	)		(2,144	)
Deferred financing costs		(6	)		(7,570	)
Capital lease payments		(739	)		(702	)
Preferred stock dividends paid		(1,059	)		(550	)
Redemption of stock in subsidiary		—			(2,438	)
Repurchase of common stock		(149	)		—
Excess tax benefit from stock-based compensation		6,738			—
Exercise of stock options, net		7,729			6,050
Net cash provided by financing activities		10,716			292,646
Effect of exchange rate changes on cash and cash equivalents		140			(170	)
Net (decrease) increase in cash and cash equivalents		(53,247	)		271,125
Cash and cash equivalents:
Balance, beginning of year		91,080			91,142
Balance, end of period	$	37,833		$	362,267

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

3

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 — Basis of Presentation

     The accompanying condensed consolidated financial statements include the accounts of Helix Energy Solutions Group, Inc. (formerly known as Cal Dive International, 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 subsidiaries. We account for our 50% interest in Deepwater Gateway, L.L.C., our 20% interest in Independence Hub, LLC (“Independence”) and our 40% interest in Offshore Technology Solutions Limited (“OTSL”) using the equity method of accounting as we do not have voting or operational control of these entities. 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, 2005. 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. The actual results may differ from our estimates. Please see our 2005 Annual Report on Form 10-K for a detailed description of our critical accounting policies. The SEC has defined critical accounting policies as the ones that are most important to the portrayal of a company’s financial condition and results of operations and require the company to make its most difficult and subjective judgments, often as a result of the need to make estimates of matters that are inherently uncertain.

     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 March 31, 2006 are not necessarily indicative of the results that may be expected for the year ending December 31, 2006. Our balance sheet as of December 31, 2005 included herein has been derived from the audited balance sheet as of December 31, 2005 included in our 2005 Annual Report on 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 2005 Annual Report on 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. Reclassifications related primarily to reportable segment realignment in the fourth quarter of 2005.

Note 2 — 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 March 31, 2006 and December 31, 2005, we had $30.0 million and $27.0 million, respectively, of restricted cash included in other assets, net, all of which related to Energy Resource Technology, Inc. (“ERT”), a wholly owned subsidiary of the Company, escrow funds for decommissioning liabilities associated with the South Marsh Island 130 (“SMI 130”) field acquisitions in 2002. Under the purchase agreement for those acquisitions, ERT is obligated to escrow 50% of production up to the first $20 million of escrow and 37.5% of production on the remaining balance up to $33 million in total escrow. ERT may use the restricted cash for decommissioning the related fields.

4

     During the three months ended March 31, 2006 and 2005, we made cash payments for interest charges, net of capitalized interest, of $1.4 million and $1.6 million respectively. During the three months ended March 31, 2006, we paid $8.8 million in income taxes. We made no income tax payments in the three months ended March 31, 2005.

     Non-cash investing activities for the three months ended March 31, 2006 included $27.3 million related to accruals of capital expenditures. Amounts were not significant for the same period in 2005. The accruals have been reflected in the condensed consolidated balance sheet as an increase in property and equipment and accounts payable.

Note 3 — Offshore 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. During the first quarter of 2005, impairments and unsuccessful capitalized well work totaling $1.7 million were expensed as a result of analyses on certain properties. Furthermore, we expensed $603,000 and $4.5 million of purchased seismic data related to our offshore properties in the first quarter of 2006 and 2005, respectively. In addition, in the three months ended March 31, 2006, we incurred inspection and repair costs totaling approximately $3.5 million related to HurricanesKatrinaandRita, partially offset by $2.7 million of insurance recoveries.

     As an extension of ERT’s well exploitation and PUD strategies, ERT agreed to participate in the drilling of an exploratory well (Tulane prospect) that was drilled in the first quarter of 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, we concluded that the wellbore would be plugged and abandoned. The total estimated cost to us of approximately $20.7 million was charged to earnings in the first quarter of 2006. We will continue to evaluate various options with the operator for recovering the potential reserves. Approximately $5.5 million of the equipment was redeployed and remains capitalized.

     In March 2005, ERT acquired a 30% working interest in a proven undeveloped field in Atwater Block 63 (Telemark) of the Deepwater Gulf of Mexico for cash and assumption of certain decommissioning liabilities. In December 2005, ERT was advised by Norsk Hydro USA Oil and Gas, Inc. (“Norsk Hydro”) that Norsk Hydro will not pursue their development plan for the deepwater discovery. ERT did not support that development plan and is currently developing its own plans based on the marginal field methodologies that were envisaged when the working interest was acquired. Any revised development plan will have to be approved by the Minerals Management Service. In April 2006, Norsk Hydro relinquished its interest in Telemark to ERT.

     In April 2005, ERT entered into a participation agreement to acquire a 50% working interest in the Devil’s Island discovery (Garden Banks Block 344 E/2) in 2,300 feet water depth. This deepwater development is operated by Amerada Hess. An appraisal well was drilled in April 2006 and was suspended. A new sidetrack well completion plan is currently under review. The field will ultimately be developed via a subsea tieback to Baldpate Field (Garden Banks Block 260). Under the participation agreement, ERT will pay 100% of the drilling costs and a disproportionate share of the development costs to earn a 50% working interest in the field. Our Contracting Services assets would participate in this development.

     Also in April 2005, ERT acquired a 37.5% working interest in the Bass Lite discovery (Atwater Blocks 182, 380, 381, 425 and 426) in 7,500 feet water depth along with varying interests in 50 other blocks of exploration acreage in the eastern portion of the Atwater lease protraction area from BHP Billiton. The Bass Lite discovery contains proved undeveloped gas reserves in a sand discovered in 2001

5

by the Atwater 426 #1 well. In October 2005, ERT exchanged 15% of its working interest in Bass Lite for a 40% working interest in the Tiger Prospect located in Green Canyon Block 195. ERT paid $1.0 million in the exchange with no corresponding gain or loss recorded on the transaction.

     In February 2006, ERT entered into a participation agreement with Walter Oil & Gas for a 20% interest in the Huey prospect in Garden Banks Blocks 346/390 in 1,835 feet water depth. Drilling of the exploration well began in April 2006. If successful, the development plan would consist of a subsea tieback to the Baldplate Field (Garden banks 260). Under the participation agreement, ERT has committed to pay 32% of the costs to casing point to earn the 20% interest in the potential development, with ERT’s share of drilling costs estimated to be approximately $6.7 million.

     As of March 31, 2006, we had incurred costs of $63.3 million and committed to an additional estimated $64 million for development and drilling costs related to the above property transactions.

     In June 2005, ERT acquired a mature property package on the Gulf of Mexico shelf from Murphy Exploration & Production Company — USA (“Murphy”), a wholly owned subsidiary of Murphy Oil Corporation. The acquisition cost to ERT included both cash ($163.5 million) and the assumption of the abandonment liability from Murphy of approximately $32.0 million (a non-cash investing activity). The acquisition represents essentially all of Murphy’s Gulf of Mexico Shelf properties consisting of eight operated and eleven non-operated fields. ERT estimates proved reserves of the acquisition to be approximately 75 BCF equivalent. The results of the acquisition are included in the accompanying statements of operations since the date of purchase. The purchase price allocation is preliminary, and estimates and assumptions are subject to change upon the receipt of management’s review of the final valuations. We do not expect the final purchase price allocation to be materially different from current allocations.

Note 4 — Acquisitions

     In April 2005, we agreed to acquire the diving and shallow water pipelay assets of Stolt Offshore (“Stolt”) that operate in the waters of the Gulf of Mexico (GOM) and Trinidad. The transaction included: seven diving support vessels; two diving and pipelay vessels (theKestreland theDB801);a portable saturation diving system; various general diving equipment and Louisiana operating bases at the Port of Iberia and Fourchon. All of the assets are included in the Shelf Contracting segment. The transaction required regulatory approval, including the completion of a review pursuant to a Second Request from the U.S. Department of Justice. On October 18, 2005, we received clearance from the U.S. Department of Justice to close the asset purchase from Stolt. Under the terms of the clearance, we will divest two diving support vessels and have disposed of the portable saturation diving system from the combined asset package acquired through this transaction and the Torch transaction which closed August 31, 2005. These assets were included in assets held for sale totaling $7.0 million and $7.8 million (included in other current assets in the accompanying consolidated balance sheet) as of March 31, 2006 and December 31, 2005, respectively. On November 1, 2005, we closed the transaction to purchase the Stolt diving assets operating in the Gulf of Mexico. We acquired theDB801in January 2006 for approximately $38.0 million and theKestrelfor approximately $39.9 million in March 2006.

     Subsequent to our purchase of theDB801,we sold a 50% interest in the vessel in January 2006 for approximately $19.0 million. We received $6.5 million in cash in 2005 and a $12.5 million interest-bearing promissory note in 2006. We have received $6.0 million of the promissory note and expect to collect the remaining balance in the second quarter of 2006. Subsequent to the sale of the 50% interest, we entered into a 10 year charter lease agreement with the purchaser, in which the lessee has an option to purchase the remaining 50% interest in the vessel beginning in January 2009. This lease was accounted for as an operating lease. Included in our lease accounting analysis was an assessment of the likelihood of the lessee performing under the full term of the lease. The carrying amount of theDB801at March 31, 2006, was approximately $18.6 million. Minimum future rentals to be received on this lease are $73.0 million over the next ten years ($7.3 million per year). In addition, under the lease agreement, the lessee is able to credit $2.35 million of its lease payments per year against the remaining 50% interest in theDB801not already owned.

6

     The Stolt acquisition was accounted for as a business purchase with the acquisition price allocated to the assets acquired and liabilities assumed based upon their fair values, with the excess being recorded as goodwill. The preliminary allocation of the purchase price at March 31, 2006 resulted in $91.4 million allocated to vessels (including the asset held for sale at March 31, 2006), $10.1 million allocated to the portable saturation diving system and various general diving equipment and inventory, $4.3 million to operating leases at the Port of Iberia and Fourchon, $3.7 million allocated to a customer-relationship intangible asset (amortized over eight years on a straight-line basis) and goodwill of approximately $14.7 million. The preliminary allocation of the purchase price was based upon preliminary valuations, and estimates and assumptions are subject to change upon the receipt of management’s review of the final valuation. The primary areas of the purchase price allocation that are not yet finalized relate to vessel valuations and residual goodwill. The final valuation of net assets is expected to be completed no later than one year from the acquisition date. The total transaction value for all of the assets was approximately $124 million. The results of the acquired assets are included in the accompanying condensed consolidated statements of operations since the date of the purchase.

     On November 3, 2005, we acquired Helix Energy Limited for approximately $32.7 million (approximately $27.1 million in cash, including transaction costs, and $5.6 million at time of acquisition in two year, variable rate notes payable to certain former owners), offset by $3.4 million of cash acquired. Helix Energy Limited is an Aberdeen, UK based provider of reservoir and well technology services to the upstream oil and gas industry with offices in London, Kuala Lampur (Malaysia) and Perth (Australia). The acquisition was accounted for as a business purchase with the acquisition price allocated to the assets acquired and liabilities assumed based upon their estimated fair values, with the excess being recorded as goodwill. The allocation of the purchase price resulted in $8.9 million allocated to net working capital, equipment and other assets acquired, $1.1 million allocated to patented technology (to be amortized over 20 years), $6.9 million allocated to a customer-relationship intangible asset (to be amortized over 12 years), $2.4 million allocated to covenants-not-to-compete (to be amortized over 3.5 years), $6.3 million allocated to trade name (not amortized, but tested for impairment on an annual basis) and goodwill of approximately $6.6 million. Resulting amounts are included in the Contracting Services segment. The final valuation of net assets was completed in the first quarter of 2006. The results of Helix Energy Limited are included in the accompanying statements of operations since the date of the purchase.

     In January 2006, theCaesar(formerly known as theBaron), a four year old mono-hull vessel, originally built for the cable lay market, was acquired by our subsidiary Vulcan Marine Technology LLC (“Vulcan”)for the Contracting Services segment for approximately $27.5 million in cash. It is currently under charter to a third-party. After completion of the charter (anticipated to end in mid-2006), we plan to convert the vessel into a deepwater pipelay asset. The vessel is 485 feet long and already has a state-of-the-art, class 2, dynamic positioning system. The conversion program will primarily involve the installation of a conventional ‘S’ lay pipelay system together with a main crane and a significant upgrade to the accommodation capability. A conversion team has already been assembled with a base at Rotterdam, the Netherlands, and the vessel is likely to enter service by mid-2007. We have entered into an agreement with a third-party (currently leasing the vessel), whereby, the third-party has an option to purchase up to 49% of Vulcan for consideration totaling (i) $32.0 million cash prior to the vessel entering conversion plus its proportionate share of actual conversion costs (total conversion cost estimated to be $93 million), or (ii) once conversion begins, proportionate share (up to 49%) of total vessel and conversion costs (estimated to be $120 million). The third-party must make all contributions to Vulcan on or before December 28, 2006.

7

Note 5 — Details of Certain Accounts

     Other current assets consisted of the following as of March 31, 2006 and December 31, 2005 (in thousands):

	March 31,		December 31,
	2006		2005
Other receivables	$	2,330	$	1,386
Insurance recoveries		2,700		—
Prepaids		11,044		13,182
Spare parts inventory		3,495		3,628
Current deferred tax assets		9,476		8,861
Gas imbalance		3,829		3,888
Current notes receivable		14,000		1,500
Assets held for sale		7,000		7,936
Other		5,604		12,534
	$	59,478	$	52,915

     Other assets, net, consisted of the following as of March 31, 2006 and December 31, 2005 (in thousands):

	March 31,		December 31,
	2006		2005
Restricted cash	$	30,049	$	27,010
Deposits		3,499		4,594
Deferred drydock expenses		17,317		18,285
Deferred financing costs		18,451		18,714
Intangible assets with definite lives		14,618		14,707
Intangible asset with indefinite life		6,142		6,074
Other		1,773		1,778
	$	91,849	$	91,162

     Accrued liabilities consisted of the following as of March 31, 2006 and December 31, 2005 (in thousands):

	March 31,		December 31,
	2006		2005
Accrued payroll and related benefits	$	15,767	$	27,982
Workers’ compensation claims		1,827		2,035
Insurance claims to be reimbursed		2,437		6,133
Royalties payable		46,174		46,555
Current decommissioning liability		15,035		15,035
Hedging liability		3,688		8,814
Income taxes payable		15,405		7,288
Deposits		3,500		10,000
Other		23,046		21,910
	$	126,879	$	145,752

8

Note 6 — Equity Investments

     In June 2002, we, along with Enterprise Products Partners L.P. (“Enterprise”), formed Deepwater Gateway, L.L.C. to design, construct, install, own and operate a tension leg platform (“TLP”) production hub primarily for Anadarko Petroleum Corporation’sMarco Polofield discovery in the Deepwater Gulf of Mexico. Our share of the construction costs was approximately $120 million. Our investment in Deepwater Gateway, L.L.C. totaled $116.6 million and $117.2 million as of March 31, 2006 and December 31, 2005, respectively. Included in the investment account was capitalized interest and insurance paid by us totaling approximately $2.1 million. Further, for the three months ended March 31, 2006 and 2005, we received cash distributions from Deepwater Gateway, L.L.C. totaling $4.0 million and $11.6 million, respectively.

     In December 2004, we acquired a 20% interest in Independence, an affiliate of Enterprise. Independence will own the “Independence Hub” platform to be located in Mississippi Canyon block 920 in a water depth of 8,000 feet. Our investment was $62.9 million and $50.8 million as of March 31, 2006 and December 31, 2005, respectively, and our total investment is expected to be approximately $83 million. Further, we are party to a guaranty agreement with Enterprise to the extent of our ownership in Independence. The agreement states, among other things, that Enterprise and we guarantee performance under the Independence Hub Agreement between Independence and the producers group of exploration and production companies up to $397.5 million, plus applicable attorneys’ fees and related expenses. We have estimated the fair value of our share of the guarantee obligation to be immaterial at December 31, 2005 based upon the remote possibility of payments being made under the performance guarantee.

     In July 2005, we acquired a 40% minority ownership interest in OTSL in exchange for our DP DSV,Witch Queen. Our investment in OTSL totaled $14.3 million and $11.5 million at March 31, 2006 and December 31, 2005. 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. Effective December 31, 2003, we adopted and applied the provisions of FASB Interpretation (“FIN”) No. 46,Consolidation of Variable Interest Entities,as revised December 31, 2003, for all variable interest entities. FIN 46 requires the consolidation of variable interest entities in which an enterprise absorbs a majority of the entity’s expected losses, receives a majority of the entity’s expected residual returns, or both, as a result of ownership, contractual or other financial interests in the entity. OTSL qualified as a variable interest entity (“VIE”) under FIN 46 through March 31, 2006. We have determined that we were not the primary beneficiary of OTSL and, thus, have not consolidated the financial results of OTSL. We account for our investment in OTSL under the equity method of accounting.

     Further, in conjunction with our investment in OTSL, we entered into a one year, unsecured $1.5 million working capital loan, bearing interest at 6% per annum, with OTSL. Interest is due quarterly beginning September 30, 2005 with a lump sum principal payment due to us on June 30, 2006.

     In the first quarter of 2006, OTSL contracted theWitch Queento us for certain services to be performed in the U.S. Gulf of Mexico. We incurred costs associated with the contract with OTSL totaling approximately $7.3 million during the first quarter of 2006.

Note 7 — Long-Term Debt

Convertible Senior Notes

     On March 30, 2005, we issued $300 million of 3.25% Convertible Senior Notes due 2025 (“Convertible Senior Notes”) at 100% of the principal amount to certain qualified institutional buyers. The Convertible Senior Notes are convertible into cash and, if applicable, shares of our common stock based on the specified conversion rate, subject to adjustment.

     The Convertible Senior Notes can be converted prior to the stated maturity under certain triggering events as specified in the indenture governing the Convertible Senior Notes. To the extent we

9

do not have alternative long-term financing secured to cover the conversion, the Convertible Senior Notes would be classified as a current liability in the accompanying balance sheet. During the first quarter of 2006, no conversion triggers were met.

     Approximately 1.5 million shares underlying the Convertible Senior Notes were included in the calculation of diluted earnings per share because our share price as of March 31, 2006 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.

     As of March 31, 2006 and December 31, 2005, we estimated the fair value of our $300 million (carrying value) fixed-rate debt to be $426.2 million and $433.7 million, respectively, based upon quoted market prices.

MARAD Debt

     At March 31, 2006, $133.1 million was outstanding on our long-term financing for construction of theQ4000.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 theQ4000,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 March 31, 2006, we were in compliance with these covenants.

     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.

Revolving Credit Facility

     In August 2004, we entered into a four-year, $150 million revolving credit facility with a syndicate of banks, with Bank of America, N.A. as administrative agent and lead arranger. The amount available under the facility may be increased to $250 million at any time upon the agreement of us and the existing or additional lenders. The credit facility is secured by the stock in certain of our subsidiaries and contains a negative pledge on assets. The facility bears interest at LIBOR plus 75-175 basis points depending on our leverage and contains financial covenants relative to the our level of debt to EBITDA, as defined in the credit facility, fixed charge coverage and book value of assets coverage. As of March 31, 2006, we were in compliance with these covenants and there was no outstanding balance under this facility.

10

     Scheduled maturities of Long-term Debt and Capital Lease Obligations outstanding as of March 31, 2006 were as follows (in thousands):

				Convertible
	MARAD			Senior				Capital			Loan
	Debt			Notes		Revolver		Leases			Notes		Total
Less than one year	$	3,731		$	—	$	—	$	2,707		$	—	$	6,438
One to two years		3,917			—		—		2,542			5,452		11,911
Two to Three years		4,113			—		—		864			—		4,977
Three to four years		4,318			—		—		—			—		4,318
Four to five years		4,533			—		—		—			—		4,533
Over five years		112,517			300,000		—		—			—		412,517
Long-term debt		133,129			300,000		—		6,113			5,452		444,694
Current maturities		(3,731	)		—		—		(2,707	)		—		(6,438	)
Long-term debt, less current maturities	$	129,398		$	300,000	$	—	$	3,406		$	5,452	$	438,256

     We had unsecured letters of credit outstanding at March 31, 2006 totaling approximately $6.9 million. These letters of credit primarily guarantee various contract bidding and insurance activities.

     We capitalized interest totaling $1.2 million and $73,000 during the three months ended March 31, 2006 and 2005, respectively. We incurred interest expense of $4.5 million and $1.4 million during the three months ended March 31, 2006 and 2005, respectively.

Note 8 — Income Taxes

     The effective tax rate of 34.1% in the three months ended March 31, 2006 was lower than the effective rate of 36% for the same period in 2005 due primarily to permanent tax benefits related to percentage depletion, Internal Revenue Code Section 199 deduction, primarily related to oil and gas production, and increased earnings that allowed for the utilization of foreign tax credits.

Note 9 — Convertible Preferred Stock

     On January 8, 2003, we completed the private placement of $25 million of a newly designated class of cumulative convertible preferred stock (Series A-1 Cumulative Convertible Preferred Stock, par value $0.01 per share) that is convertible into 1,666,668 shares of our common stock at $15 per share. The preferred stock was issued to a private investment firm. Subsequently in June 2004, the preferred stockholder exercised its existing right and purchased $30 million in additional cumulative convertible preferred stock (Series A-2 Cumulative Convertible Preferred Stock, par value $0.01 per share). In accordance with the January 8, 2003 agreement, the $30 million in additional preferred stock is convertible into 1,964,058 shares of Helix common stock at $15.27 per share. In the event the holder of the convertible preferred stock elects to redeem into Helix common stock and our common stock price is below the conversion prices, unless we have elected to settle in cash, the holder would receive additional shares above the 1,666,668 common shares (Series A-1 tranche) and 1,964,058 common shares (Series A-2 tranche). The incremental shares would be treated as a dividend and reduce net income applicable to common shareholders.

     The preferred stock has a minimum annual dividend rate of 4%, subject to adjustment (approximately 5.85% at March 31, 2006), payable quarterly in cash or common shares at our option. We paid these dividends in 2006 and 2005 on the last day of the respective quarter in cash. The holder may redeem the value of its original and additional investment in the preferred shares to be settled in common stock at the then prevailing market price or cash at our discretion. In the event we are unable to deliver registered common shares, we could be required to redeem in cash.

11

     The proceeds received from the sales of this stock, net of transaction costs, have been classified outside of shareholders’ equity on the balance sheet below total liabilities. Prior to the conversion, common shares issuable will be assessed for inclusion in the weighted average shares outstanding for our diluted earnings per share using the if-converted method based on the lower of our share price at the beginning of the applicable period or the applicable conversion price ($15.00 and $15.27).

Note 10 — Hedging Activities

     Our price 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. All derivatives are reflected in our balance sheet at fair value. During 2005 and the first three months of 2006, we 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 qualified for hedge accounting. The aggregate fair value of the hedge instruments was a net liability of $8.4 million as of March 31, 2006. We recorded unrealized gains (losses) of approximately $3.2 million and ($3.0) million, net of tax (expense) benefit of $(1.7) million and $1.6 million, during the first three months of 2006 and 2005, respectively, in accumulated other comprehensive income (loss), a component of shareholders’ equity, as these hedges were highly effective. During the three months ended March 31, 2006 and 2005, we reclassified approximately $4.9 million of gains and $1.2 million of losses, respectively, from other comprehensive income to Oil and Gas Production revenues upon the sale of the related oil and gas production.

     As of March 31, 2006, we had the following volumes under derivative contracts related to our oil and gas producing activities:

	Instrument	Average	Weighted
Production Period	Type	Monthly Volumes	Average Price
Crude Oil:
April 2006 — December 2006	Collar	125 MBbl	$44.00 — $70.48
January 2007 — December 2007	Collar	50 MBbl	$40.00 — $62.15
Natural Gas:
April 2006 — December 2006	Collar	666,667 MMBtu	$7.38 — $13.37
January 2007 — March 2007	Collar	600,000 MMBtu	$8.00 — $16.24

     Subsequent to March 31, 2006, we entered into additional natural gas costless collars for the period of April 2007 through June 2007. The contract covers 500,000 MMBtu per month at a weighted average price of $8.00 to $10.62.

Note 11 — Foreign Currency

     The functional currency for our foreign subsidiaries, Well Ops (U.K.) Limited and Helix Energy Limited, is the applicable local currency (British Pound). Results of operations for these subsidiaries are translated into U.S. dollars using average exchange rates during the period. Assets and liabilities of these foreign subsidiaries are translated into U.S. dollars using the exchange rate in effect at the balance sheet date, and the resulting translation adjustment, which were unrealized gains (losses) of $1.2 million and $(1.6) million for the three months ended March 31, 2006 and 2005, respectively, is included in accumulated other comprehensive income (loss), a component of shareholders’ equity. Beginning in 2004, deferred taxes have not been provided on foreign currency translation adjustments since we consider our undistributed earnings (when applicable) of our non-U.S. subsidiaries to be permanently reinvested. These amounts for the three months ended March 31, 2006 and 2005, respectively, were not material to our results of operations or cash flows.

     Canyon Offshore, Inc. (“Canyon”), our ROV subsidiary, has operations in the United Kingdom and Southeast Asia sectors. Canyon conducts the majority of its operations in these regions in U.S. dollars which it considers the functional currency. When currencies other than the U.S. dollar are to be

12

paid or received, the resulting transaction gain or loss is recognized in the statements of operations. These amounts for the three months ended March 31, 2006, respectively, were not material to our results of operations or cash flows.

Note 12 — Comprehensive Income

     The components of total comprehensive income for the three months ended March 31, 2006 and 2005 were as follows (in thousands):

	Three Months Ended
	March 31,
	2006		2005
Net Income	$	56,193	$	25,961
Foreign currency translation gain (loss)		1,160		(1,636	)
Unrealized gain (loss) on commodity hedges, net		3,230		(3,053	)
Total comprehensive income	$	60,583	$	21,272

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

	March 31,			December 31,
	2006			2005
Cumulative foreign currency translation adjustment	$	8,139		$	6,979
Unrealized loss on commodity hedges, net		(5,478	)		(8,708	)
Accumulated other comprehensive income (loss)	$	2,661		$	(1,729	)

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 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 per share amounts were as follows (in thousands):

	Three Months Ended				Three Months Ended
	March 31, 2006				March 31, 2005
	Income		Shares		Income		Shares
Earnings applicable per common share — Basic	$	55,389		77,969	$	25,411		77,143
Effect of dilutive securities:
Stock options		—		630		—		781
Restricted shares		—		115		—		184
Convertible Senior Notes		—		1,458		—		—
Convertible preferred stock		804		3,631		550		3,631
Earnings applicable per common share — Diluted	$	56,193		83,803	$	25,961		81,739

     There were no antidilutive stock options in the three months ended March 31, 2006 and 2005, respectively. Net income for the diluted earnings per share calculation for the three months ended March 31, 2006 and 2005 was adjusted to add back the preferred stock dividends on the 3.6 million shares.

13

Note 14 — Stock-Based Compensation Plans

     We have three stock-based compensation plans: the 1995 Long-Term Incentive Plan, as amended, the 2005 Long-Term Incentive Plan (together as the “Incentive Plans”) and the Employee Stock Purchase Plan (the “ESPP”). Under the Incentive Plans, a maximum of 10% of the total shares of common stock issued and outstanding may be granted to key executives and selected employees who are likely to make a significant positive impact on our reported net income as well as non-employee members of the Board of Directors. The Incentive Plans are administered by a committee which determines, subject to approval of the Compensation Committee of the Board of Directors, the type of award to be made to each participant and set forth in the related award agreement the terms, conditions and limitations applicable to each award. The committee may grant stock options, stock appreciation rights or stock and cash awards. Awards granted to employees under the Incentive Plan typically vest 20% per year for a five year period or 33% per year for a three year period, have a maximum exercise life of three, five or ten years and, subject to certain exceptions, are not transferable.

     Prior to January 1, 2006, we used the intrinsic value method of accounting for our stock-based compensation. Accordingly, no compensation expense was recognized when the exercise price of an employee stock option was equal to the common share market price on the grant date. In addition, under the intrinsic value method, on the date of grant for restricted shares, we recorded unearned compensation (a component of shareholders’ equity) that equaled the product of the number of shares granted and the closing price of our common stock on the grant date, and expense was recognized over the vesting period of each grant on a straight-line basis.

     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 fair value model for valuing share-based payments and recognize compensation cost on a straight-line basis over the respective vesting period. No forfeitures were estimated for outstanding unvested options and restricted shares as historical forfeitures have been immaterial. We have selected the modified-prospective method of adoption, which requires that compensation expense be recorded for all unvested stock options and restricted stock beginning in 2006 as the requisite service is rendered. In addition to the compensation cost recognition requirements, tax deduction benefits for an award in excess of recognized compensation cost is reported as a financing cash flow rather than as an operating cash flow. The adoption did not have a material impact on our consolidated results of operations, earnings per share and cash flows. There were no stock option grants in the first quarter of 2006 or 2005.

14

     The following table reflects our pro forma results if the fair value method had been used for the accounting for these plans for the three months ended March 31, 2005 (in thousands, except per share amounts):

	Three Months
	Ended
	March 31, 2005
Net income applicable to common shareholders:
As Reported	$	25,411
Add back: Stock-based compensation cost included in reported net income, net of taxes		126
Deduct: Total stock-based compensation cost determined under the fair value method, net of tax		(459	)
Pro Forma	$	25,078
Earnings per common share:
Basic:
As reported	$	0.33
Pro forma	$	0.33
Diluted:
As reported	$	0.32
Pro forma	$	0.31

     For the purposes of pro forma disclosures, the fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model. The estimated fair value of the options is amortized to pro forma expense over the vesting period.

     On January 3, 2005, we granted 188,132 restricted shares to key executives and selected management employees which vest 20% per year for a five year period. The market value (based on the quoted price of the common stock on the date of the grant) of the restricted shares was $19.56 per share, or $3.7 million, at the date of the grant. The amounts granted were recorded as unearned compensation, a component of shareholders’ equity, and charged to expense over the respective vesting periods. Amortization of unearned compensation totaled $194,000 for the three months ended March 31, 2005. Awards are amortized directly to expense and additional paid in capital (a component of Common Stock). The balance in unearned compensation at December 31, 2005 was $7.5 million and was reversed in January 2006 upon adoption of the fair value method.

     During the first three months ended March 31, 2006, we made the following restricted share grants to key executives and selected management employees:

• 196,820 restricted shares on January 3, 2006 which vest 20% per year for a five year period. The market value (based on the quoted price of the common stock on the date of the grant) of the restricted shares was $35.89 per share, or $7.1 million, at the date of the grant;

• 1,705 restricted shares on March 1, 2006 which vest 20% per year for a five year period. The market value (based on the quoted price of the common stock on the date of the grant) of the restricted shares was $35.21 per share, or approximately $60,000, at the date of the grant; and

• 10,000 restricted shares on March 20, 2006 which vest 20% per year for a five year period. The market value (based on the quoted price of the common stock on the date of the grant) of the restricted shares was $35.61 per share, or approximately $356,000, at the date of the grant.

15

     For the three months ended March 31, 2006, $1.6 million was recognized as compensation expense related to unvested stock options and restricted stock. No expense was recognized related to the ESPP for the three months ended March 31, 2006.

     All of the options outstanding at March 31, 2006, have exercise prices as follows: 178,000 shares at $8.57; 88,997 shares at $9.32; 122,014 shares at $10.92; 73,500 shares at $10.94; 88,000 shares at $11.00; 200,000 shares at $12.18; 70,400 shares at $13.91; and 223,200 shares ranging from $8.23 to $12.00, and a weighted average remaining contractual life of 6.46 years.

     Options outstanding are as follows:

	March 31, 2006					March 31, 2005
				Weighted					Weighted
				Average					Average
				Exercise					Exercise
	Shares			Price		Shares			Price
Options outstanding, Beginning of year		1,717,904		$	10.91		2,599,894		$	10.65
Granted		—		$	—		—		$	—
Exercised		(673,793	)	$	11.47		(596,174	)	$	10.15
Terminated		—		$	—		—		$	—
Options outstanding at March 31,		1,044,111		$	10.55		2,003,720		$	10.80
Options exercisable at March 31,		570,319		$	10.24		1,236,532		$	10.78

     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 10 percent of an employee’s base salary. Under this plan 41,006 and 42,224 shares of common stock were purchased in the open market at a share price of $26.14 and $15.26 during the three months ended March 31, 2006 and 2005, respectively, for the purchase periods for the second half of 2005 and 2004, respectively. No expenses were recognized under the intrinsic value method.

Note 15 — Business Segment Information (in thousands)

     In the fourth quarter of 2005, we modified our segment reporting from three reportable segments to four reportable segments. Our operations are conducted through the following primary reportable segments: Contracting Services (formerly known as Deepwater Contracting), Shelf Contracting, Oil and Gas Production and Production Facilities. The realignment of reportable segments was attributable to organizational changes within the Company as it is related to separating Marine Contracting into two reportable segments — Contracting Services and Shelf Contracting. Contracting Services operations include deepwater pipelay, well operations and robotics. Shelf Contracting operations consist of assets deployed primarily for diving-related activities and shallow water construction. As a result, segment disclosures for the prior period have been restated to conform to the current period presentation. All intercompany transactions between the segments have been eliminated.

16

	Three Months Ended
	March 31,
	2006			2005
Revenues -
Contracting services	$	101,031		$	64,284
Shelf contracting		119,790			36,204
Oil and gas production		80,312			63,385
Intercompany elimination		(9,485	)		(4,298	)
Total	$	291,648		$	159,575
Income from operations -
Contracting services	$	20,659		$	4,339
Shelf contracting(1)		47,069			8,401
Oil and gas production		16,966			26,414
Production facilities equity investments(2)		(318	)		(118	)
Total	$	84,376		$	39,036
Equity in earnings of production facilities investments	$	3,365		$	1,729

	March 31,		December 31,
	2006		2005
Identifiable Assets -
Contracting services	$	696,825	$	736,852
Shelf contracting		382,316		277,446
Oil and gas production		484,254		478,522
Production facilities equity investments		179,456		168,044
Total	$	1,742,851	$	1,660,864

     Intercompany segment revenues during the three months ended March 31, 2006 and 2005 were as follows:

	Three Months Ended
	March 31,
	2006		2005
Contracting services	$	7,155	$	3,377
Shelf contracting		2,330		921
Total	$	9,485	$	4,298

(1)	Included $2.8 million equity in earnings from investment in OTSL in first quarter 2006.
(2)	Represents selling and administrative expense of Production Facilities incurred by us. See Equity in Earnings of Production Facilities Investments for earnings contribution.

     During the three months ended March 31, 2006 and 2005, we derived $29.1 million and $30.7 million, respectively, of our revenues from the U.K. sector, utilizing $168.4 million and $134.9 million, respectively, of our total assets in this region. The majority of the remaining revenues were generated in the U.S. Gulf of Mexico.

17

Note 16 — Related Party Transactions

     In April 2000, ERT acquired a 20% working interest inGunnison, aDeepwater Gulf of Mexico prospect of Kerr-McGee Oil & Gas Corp. Financing for the exploratory costs of approximately $20 million was provided by an investment partnership (OKCD Investments, Ltd. or “OKCD”). The investors of this entity include current and former Helix senior management, in exchange for a revenue interest that is an overriding royalty interest of 25% of our 20% working interest. Production began in December 2003. Payments to OKCD from ERT totaled $9.6 million and $6.5 million in the three months ended March 31, 2006 and 2005, respectively.

Note 17 — Commitments and Contingencies

Commitments

     At March 31, 2006, we had committed to convert a certain Contracting Services vessel (theCaesar,acquired in January 2006 for $27.5 million in cash)into a deepwater pipelay vessel. Total conversion costs are estimated to be approximately $93 million, of which $1.7 million had been committed at March 31, 2006. In addition, we will upgrade theQ4000to include drilling via the addition of a modular-based drilling system for approximately $40 million, of which approximately $10 million had been committed at March 31, 2006.

Contingencies

     We are involved in various routine legal proceedings, primarily involving claims for personal injury under the General Maritime Laws of the United States and the Jones Act as a result of alleged negligence. In addition, we, from time to time, incur other claims, such as contract disputes, in the normal course of business. In that regard, in 1998, one of our subsidiaries entered into a subcontract with Seacore Marine Contractors Limited (“Seacore”) to provide theSea Sorceressto a Coflexip subsidiary in Canada (“Coflexip”). Due to difficulties with respect to the sea and soil conditions, the contract was terminated and an arbitration to recover damages was commenced. A preliminary liability finding has been made by the arbitrator against Seacore and in favor of the Coflexip subsidiary. We were not a party to this arbitration proceeding. Seacore and Coflexip settled this matter prior to the conclusion of the arbitration proceeding, with Seacore paying Coflexip $6.95 million CDN. Seacore has initiated an arbitration proceeding against Cal Dive Offshore Ltd. (“CDO”), a subsidiary of Helix, seeking contribution for half of this amount. One of the grounds in the preliminary findings by the arbitrator is applicable to CDO, and CDO holds substantial counterclaims against Seacore.

     Although the above discussed matters may have the potential for additional liability, we believe 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.

     We sustained damage to certain of our oil and gas production facilities in HurricanesKatrina andRita. We estimate total repair and inspection costs resulting from the hurricanes will range from $5 million to $8 million net of expected insurance reimbursement. These costs, and any related insurance reimbursements, will be recorded as incurred this year.

Note 18 — Pending Transaction

     On January 23, 2006, we announced an agreement under which we will acquire Remington Oil and Gas Corporation (“Remington”) in a transaction valued at approximately $1.4 billion. Under the terms of the agreement, Remington stockholders will receive $27.00 in cash and 0.436 shares of our common stock for each Remington share. The acquisition is conditioned upon, among other things, the approval of Remington stockholders.

     The transaction is expected to be completed in the second quarter of 2006. In limited circumstances, if Remington fails to close the transaction, it must pay us a $45 million breakup fee and

18

reimburse up to $2 million of expenses related to the transaction. We expect to fund the cash portion of the Remington acquisition (approximately $814 million) through a senior secured term facility which has been underwritten by a bank. A detailed description of this transaction is set forth in our registration statement on Form S-4 (Reg. No. 333-132922).

19

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 forward-looking statements that involve risks, uncertainties and assumptions that could cause our results to differ materially from those expressed or implied by such forward-looking statements. All statements, other than statements of historical fact, are statements that could be deemed “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, including, without limitation, any projections of revenue, gross margin, expenses, earnings or losses from operations, or other financial items; any statements of the plans, strategies and objectives of management for future operations; any statement concerning developments, performance or industry rankings relating to services; any statements regarding future economic conditions or performance; any statements of expectation or belief; any statements regarding the proposed merger of Remington Oil and Gas Corporation into a wholly owned subsidiary of Helix or the anticipated results (financial or otherwise) thereof; and any statements of assumptions underlying any of the foregoing. The risks, uncertainties and assumptions referred to above include the performance of contracts by suppliers, customers and partners; employee management issues; complexities of global political and economic developments, other risks described under the heading “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2005; and, with respect to the proposed Remington merger, actual results could differ materially from our expectations depending on factors such as the combined company’s cost of capital, the ability of the combined company to identify and implement cost savings, synergies and efficiencies in the time frame needed to achieve these expectations, prior contractual commitments of the combined companies and their ability to terminate these commitments or amend, renegotiate or settle the same, the combined company’s actual capital needs, the absence of any material incident of property damage or other hazard that could affect the need to make capital expenditures, any unforeseen merger or acquisition opportunities that could affect capital needs, the costs incurred in implementing synergies and the factors that generally affect both our respective businesses as further outlined in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in each of our respective Annual Reports on Form 10-K for the year ended December 31, 2005. Actual actions that the combined company may take may differ from time to time as the combined company may deem necessary or advisable in the best interest of the combined company and its shareholders to attempt to achieve the successful integration of the companies, the synergies needed to make the transaction a financial success and to react to the economy and the combined company’s market for its exploration and production. We assume no obligation and do not intend to update these forward-looking statements.

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 to be Critical Accounting Policies and Estimates as disclosed in our Form 10-K for the year ended December 31, 2005.

RESULTS OF OPERATIONS

     In the fourth quarter of 2005, we modified our segment reporting from three reportable segments to four reportable segments. Our operations are conducted through the following primary reportable segments: Contracting Services (formerly known as Deepwater Contracting), Shelf Contracting, Oil and

20

Gas Production and Production Facilities. The realignment of reportable segments was attributable to organizational changes within the Company as it is related to separating Marine Contracting into two reportable segments — Contracting Services and Shelf Contracting. Contracting Services operations include deepwater pipelay, well operations and robotics. Shelf Contracting operations consist of assets deployed primarily for diving-related activities and shallow water construction. As a result, segment disclosures for the prior period have been restated to conform to the current period presentation. All intercompany transactions between the segments have been eliminated.

Comparison of Three Months Ended March 31, 2006 and 2005

          Net Revenues.Of the overall $132.1 million increase in revenues, $33.0 million was generated by the Contracting Services segment, $82.2 million by the Shelf Contracting segment and $16.9 million generated by the Oil and Gas Production segment. Contracting Services revenues increased primarily due to improved market demand and the addition of theExpressacquired from Torch in August 2005, resulting in significantly improved utilization rates and contract pricing for the Pipelay and ROV divisions, offset partially by decreased utilization in the Well Operations division due to unscheduled downtime in the first quarter of 2006. Shelf Contracting revenues increased due to improved market demand, much of which continues to be the result of damages sustained in HurricanesKatrinaandRita. This resulted in significantly improved utilization rates and contract pricing for all divisions within the segment (shallow water pipelay, diving and portable SAT systems). Further, Shelf Contracting’s revenues increased in the three months ended March 31, 2006 compared with 2005 directly as a result of the acquisition of the Torch and Stolt vessels in the third and fourth quarters of 2005.

          Oil and Gas Production revenue increased $16.9 million, or 27%, during the three months ended March 31, 2006 compared with the prior year period. The increase was primarily due to increases in oil and natural gas prices realized. The average realized natural gas price of $9.52 per Mcf, net of hedges in place, during first quarter 2006 was 43% higher than the $6.64 per Mcf realized in first quarter 2005, while average realized oil prices, net of hedges in place, increased 33% to $58.71 per barrel in first quarter 2006 compared with $44.02 per barrel realized during first quarter 2005. These increases were partially offset by a production decrease of 11% (8.1 Bcfe for the three months ended March 31, 2006 compared to 9.0 Bcfe in the prior year period) primarily due to production shut-ins due to HurricanesKatrinaandRita. However, oil and gas production is currently at or near pre-hurricane levels.

          Gross Profit.Gross profit of $102.3 million for the three months ended March 31, 2006 represented a 97% increase compared to the $51.9 million recorded in the comparable prior year period. Contracting Services gross profit increased to $29.5 million for the three months ended March 31, 2006, from $9.9 million in the first quarter of 2005. The increase was primarily attributable to improved utilization rates, contract pricing for the Pipelay and ROV divisions and the addition of theExpressfor the full first quarter 2006. Shelf Contracting gross profit increased to $50.2 million for the three months ended March 31, 2006, from $11.1 million in the first quarter of 2005. As previously discussed, the increase was primarily attributable to improved utilization rates, contract pricing for all divisions within the segment and the addition of the Torch and Stolt assets for a full first quarter 2006. Oil and Gas Production gross profit decreased $8.3 million, to $22.6 million, due primarily to $20.7 million of exploratory drilling costs expensed related to the Tulane prospect as a result of mechanical difficulties experienced in the drilling of this well and after further review, we concluded that the wellbore would be plugged and abandoned. Further, we incurred inspection and repair costs of approximately $3.5 million as a result of HurricanesKatrinaandRita, partially offset by $2.7 million in insurance recoveries. In addition, gross profit for the Oil and Gas Production segment decreased due to the aforementioned lower production levels. Decreases in Oil and Gas Production segment gross profit were partially offset by higher commodity prices.

          Gross margins in the first quarter of 2006 were 35% as compared to 33% in the comparable prior year period. Contracting Services margins increased 15 points to 31% in first quarter 2006 compared with 16% in the prior year period, due to the factors noted above. Shelf Contracting margins increased 11 points to 43% in first quarter 2006 from 32% in the prior year period, due to the factors noted above. In addition, margins in the Oil and Gas Production segment decreased 21 points to 28% in first quarter 2006 from 49% in first quarter 2005, primarily due to the Tulane charge.

21

          As discussed above, we sustained damage to certain of our oil and gas production facilities in HurricanesKatrinaandRita. Our estimate of total repair and inspection costs resulting from the hurricanes will range from $5 million to $8 million, net of expected insurance reimbursement. These costs, and any related insurance reimbursements, will be recorded as incurred over the next year.

          Selling and Administrative Expenses.Selling and administrative expenses of $21.0 million for the three months ended March 31, 2006 were $8.2 million higher than the $12.8 million incurred in first quarter 2005 due primarily to increased overhead to support our growth. Selling and administrative expenses at 7% of revenues for the first quarter of 2006 was slightly lower than the 8% in first quarter 2005.

          Equity in Earnings of Investments.Equity in earnings of our 50% investment in Deepwater Gateway, L.L.C. increased to $3.4 million in first quarter 2006 compared with $1.7 million in first quarter 2005. Further, equity in earnings from our 40% minority ownership interest in OTSL in first quarter 2006 totaled approximately $2.8 million compared with $0 in the comparable prior year period.

          Net Interest Expense and Other.We reported other expense of $2.5 million for the three months ended March 31, 2006 compared to other expense of $264,000 in the prior year period. Net interest expense of $2.5 million in first quarter 2006 was higher than the $1.3 million incurred in first quarter 2005 due primarily to higher levels of debt associated with our $300 million Convertible Senior Notes which closed in March 2005. Offsetting the increase in interest expense was $1.2 million of capitalized interest in first quarter 2006, compared with $73,000 in first quarter 2005, which related primarily to our investment in Independence Hub.

          Provision for Income Taxes.Income taxes increased to $29.1 million for the three months ended March 31, 2006 compared to $14.5 million in the prior year period, primarily due to increased profitability. The effective tax rate of 34.1% in first quarter 2006 was lower than the 36% effective tax rate for first quarter 2005 due to our ability to realize foreign tax credits and oil and gas percentage depletion due to improved profitability both domestically and in foreign jurisdictions and implementation of the Internal Revenue Code section 199 manufacturing deduction as it primarily related to oil and gas production.

LIQUIDITY AND CAPITAL RESOURCES

          Total debt as of March 31, 2006 was $444.7 million comprised primarily of $300 million of Convertible Senior Notes which mature in 2025 and $133.1 million of MARAD debt which matures in 2027. See further discussion below under “Financing Activities.” In addition, as of March 31, 2006, we had $37.8 million of unrestricted cash, as well as a $150 million, undrawn revolving credit facility. See “Investing Activities” below for a discussion of expected uses of our cash related to our exploration and development of our deepwater prospects and the Remington merger.

          Hedging Activities.Our price risk management activities involve the use of derivative financial instruments to hedge the impact of market price risk exposures primarily related to the our oil and gas production. All derivatives are reflected in our balance sheet at fair value.

          During 2005 and the first three months of 2006, we entered into various cash flow hedging swap and costless collar contracts to stabilize cash flows relating to a portion of our expected oil and gas production. All of these qualified for hedge accounting. The aggregate fair value of the hedge instruments was a net liability of $8.4 million as of March 31, 2006. We recorded unrealized gains (losses) of approximately $3.2 million and ($3.0) million, net of tax (expense) benefit of $(1.7) million and $1.6 million, during the first three months of 2006 and 2005, respectively, in accumulated other comprehensive income (loss), a component of shareholders’ equity, as these hedges were highly effective. During the three months ended March 31, 2006 and 2005, we reclassified approximately $4.9 million of gains and $1.2 million of losses, respectively, from other comprehensive income to Oil and Gas Production revenues upon the sale of the related oil and gas production.

22

          Operating Activities.The increase in cash flow from operations for the three months ended March 31, 2006 as compared to the same period in 2005 was due primarily to an increase in profitability ($30.2 million), which included a non-cash asset impairment charge of $20.7 million. These increases were partially offset by decreases in accounts payable and accrued liabilities due primarily to incentive compensation payments, timing of trade accounts payable and a decrease in hedge liability accruals.

          Investing Activities.Included in the capital acquisitions and expenditures during the first three months of 2006 was $24.1 million for ERT well exploitation programs, furtherGunnisonfield development and other deepwater development costs, and $33.7 million related to our Contracting Services segment (including $27.5 million for the purchase of theCaesar). Further, we completed our Stolt acquisition with the purchase of theDB801and theKestrelfor approximately $77.9 million. Included in the capital expenditures during the first three months of 2005 was $17.9 million for ERT well exploitation programs and furtherGunnisonfield development and $4.8 million for Canyon Offshore ROV and trencher systems.

          As of March 31, 2006, we have the following investments that are accounted for under the equity method of accounting: Deepwater Gateway, L.L.C., Independence Hub, LLC (“Independence”) and Offshore Technology Solutions Limited (“OTSL”):

• Deepwater Gateway, L.L.C.We, along with Enterprise Products Partners L.P. (“Enterprise”), formed Deepwater Gateway, L.L.C. (a 50/50 venture) to design, construct, install, own and operate a TLP production hub primarily for Anadarko Petroleum Corporation’sMarco Polofield discovery in the Deepwater Gulf of Mexico. Our investment in Deepwater Gateway, L.L.C. totaled $116.6 million as of March 31, 2006. Included in the investment account was capitalized interest and insurance paid by us totaling approximately $2.1 million.

• Independence Hub, LLC.In December 2004, we acquired a 20% interest in Independence, an affiliate of Enterprise. Independence will own the “Independence Hub” platform to be located in Mississippi Canyon block 920 in a water depth of 8,000 feet. Our investment in Independence Hub LLC (“Independence”) was $62.9 million as of March 31, 2006, and our total investment is expected to be approximately $83 million. We expect to complete our investment by the end of 2006.

• OTSL.In July 2005, we acquired a 40% minority ownership interest in OTSL in exchange for our DP DSV,Witch Queen. Our investment in OTSL totaled $14.3 million at March 31, 2006. 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. Further, in conjunction with our investment in OTSL, we entered into a one year, unsecured $1.5 million working capital loan, bearing interest at 6% per annum, with OTSL. Interest is due quarterly beginning September 30, 2005 with a lump sum principal payment due to us on June 30, 2006. In the first quarter of 2006, OTSL contracted theWitch Queento us for certain services to be performed in the U.S. Gulf of Mexico. We incurred costs associated with the contract with OTSL totaling approximately $7.3 million during the first quarter of 2006.

23

          We made the following contributions to our equity investments during the three months ended March 31, 2006 and 2005 (in thousands):

	Three Months Ended
	March 31,
	2006		2005
Deepwater Gateway, L.L.C.(1)	$	—	$	72,000
Independence Hub, LLC		11,373		6,327
OTSL		—		—
	$	11,373	$	78,327

(1) Contribution made in March 31, 2005 related to Deepwater Gateway, L.L.C. was for the repayment of our portion of the term loan for Deepwater Gateway, L.L.C. Upon repayment of the loan, our $7.5 million restricted cash was released from escrow and the escrow agreement was terminated.

          We received the following distributions from our equity investments during the three months ended March 31, 2006 and 2005 (in thousands):

	Three Months Ended
	March 31,
	2006		2005
Deepwater Gateway, L.L.C.	$	4,000	$	11,600
Independence Hub, LLC		—		—
OTSL		68		—
	$	4,068	$	11,600

          As of March 31, 2006, we had $30.0 million of restricted cash, included in other assets, net, in the accompanying condensed consolidated balance sheet, all of which related to ERT’s escrow funds for decommissioning liabilities associated with the SMI 130 field acquisitions in 2002. Under the purchase agreement for the acquisitions ERT is obligated to escrow 50% of production up to the first $20 million and 37.5% of production on the remaining balance up to $33 million in total escrow. ERT may use the restricted cash for decommissioning the related fields.

          In March 2005, Canyon Offshore sold an ROV for $2.1 million in cash and recognized a gain on the sale totaling $925,000.

          In April 2000, ERT acquired a 20% working interest inGunnison, aDeepwater Gulf of Mexico prospect of Kerr-McGee Oil & Gas Corp. Financing for the exploratory costs of approximately $20 million was provided by an investment partnership (OKCD Investments, Ltd. or “OKCD”), the investors of which include current and former Helix senior management, in exchange for a revenue interest that is an overriding royalty interest of 25% of our 20% working interest. Production began in December 2003. Payments to OKCD from ERT totaled $9.6 million and $6.5 million in the first three months of 2006 and 2005, respectively.

          As an extension of ERT’s well exploitation and PUD strategies, ERT agreed to participate in the drilling of an exploratory well (Tulane prospect) that was drilled in the first quarter of 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, we concluded that the wellbore would be plugged and abandoned. The total estimated cost to us of approximately $20.7 million was charged to earnings in the first quarter of 2006. We will continue to evaluate various options with the operator for recovering the potential reserves. Approximately $5.5 million of the equipment was redeployed and remains capitalized.

24

          In March 2005, ERT acquired a 30% working interest in a proven undeveloped field in Atwater Block 63 (Telemark) of the Deepwater Gulf of Mexico for cash and assumption of certain decommissioning liabilities. In December 2005, ERT was advised by Norsk Hydro USA Oil and Gas, Inc. (“Norsk Hydro”) that Norsk Hydro will not pursue their development plan for the deepwater discovery. ERT did not support that development plan and is currently developing its own plans based on the marginal field methodologies that were envisaged when the working interest was acquired. Any revised development plan will have to be approved by the Minerals Management Service. In April 2006, Norsk Hydro relinquished its interest in Telemark to ERT.

          In April 2005, ERT entered into a participation agreement to acquire a 50% working interest in the Devil’s Island discovery (Garden Banks Block 344 E/2) in 2,300 feet water depth. This deepwater development is operated by Amerada Hess. An appraisal well was drilled in April 2006 and was suspended. A new sidetrack well completion plan is currently under review. The field will ultimately be developed via a subsea tieback to Baldpate Field (Garden Banks Block 260). Under the participation agreement, ERT will pay 100% of the drilling costs and a disproportionate share of the development costs to earn 50% working interest in the field.

          Also in April 2005, ERT acquired a 37.5% working interest in the Bass Lite discovery (Atwater Blocks 182, 380, 381, 425 and 426) in 7,500 feet water depth along with varying interests in 50 other blocks of exploration acreage in the eastern portion of the Atwater lease protraction area from BHP Billiton. The Bass Lite discovery contains proved undeveloped gas reserves in a sand discovered in 2001 by the Atwater 426 #1 well. In October 2005, ERT exchanged 15% of its working interest in Bass Lite for a 40% working interest in the Tiger Prospect located in Green Canyon Block 195. ERT paid $1.0 million in the exchange with no corresponding gain or loss recorded on the transaction.

          In February 2006, ERT entered into a participation agreement with Walter Oil & Gas for a 20% interest in the Huey prospect in Garden Banks Blocks 346/390 in 1,835 feet water depth. Drilling of the exploration well began in April 2006. If successful, the development plan would consist of a subsea tieback to the Baldplate Field (Garden banks 260). Under the participation agreement, ERT has committed to pay 32% of the costs to casing point to earn the 20% interest in the potential development, with ERT’s share of drilling costs estimated to be approximately $6.7 million.

          As of March 31, 2006, we had incurred costs of $63.3 million and had committed to an additional estimated $64 million for development and drilling costs related to the above property transactions.

          Also in April 2005, we agreed to acquire the diving and shallow water pipelay assets of Stolt Offshore that currently operate in the waters of the Gulf of Mexico (GOM) and Trinidad. On November 1, 2005, we closed the transaction to purchase the diving assets of Stolt that operate in the Gulf of Mexico. In addition, separate agreements to purchase theDB801andKestrelwere closed in 2006 when these assets completed their work campaigns in Trinidadian waters. TheDB801was purchased in January 2006 for approximately $38.0 million. We subsequently sold a 50% interest in this vessel in January 2006 for approximately $19.0 million. We received $6.5 million in cash in 2005 and a $12.5 million interest-bearing promissory note in 2006. We have received $6.0 million of the promissory note and expect to collect the remaining balance in the second quarter of 2006. Subsequent to the sale of the 50% interest, we entered into a 10 year charter lease agreement with the purchaser, in which the lessee has an option to purchase the remaining 50% interest in the vessel beginning in January 2009. This lease was accounted for as an operating lease. Included in our lease accounting analysis was an assessment of the likelihood of the lessee performing under the full term of the lease. The carrying amount of theDB801at March 31, 2006, was approximately $18.6 million. Minimum future rentals to be received on this lease are $73.0 million over the next ten years ($7.3 million per year). In addition, under the lease agreement, the lessee is able to credit $2.35 million of its lease payments per year against the remaining 50% interest in theDB801 not already owned.

          In addition, in January 2006, one of our subsidiaries, Vulcan Marine Technology LLC, purchased theCaesarfor the Contracting Services segment for approximately $27.5 million in cash. It is currently

25

under charter to a third-party. After completion of the charter (anticipated to end in mid-2006), we plan to convert the vessel into a deepwater pipelay asset. Total conversion costs are estimated to be approximately $93 million, of which $1.7 million had been committed at March 31, 2006. We have entered into an agreement with a third-party (currently leasing the vessel), whereby, it has an option to purchase up to 49% of Vulcan for consideration totaling (i) $32.0 million cash prior to the vessel entering conversion plus its proportionate share of actual conversion costs (estimated to be $93 million), or (ii) once conversion begins, proportionate share (up to 49%) of total vessel and conversion costs (estimated to be $120 million). The third-party must make all contributions to Vulcan on or before December 28, 2006. In addition, we will upgrade theQ4000to include drilling via the addition of a modular-based drilling system for approximately $40 million, of which approximately $10 million had been committed at March 31, 2006.

          On January 23, 2006, we announced an agreement under which we will acquire Remington in a transaction valued at approximately $1.4 billion. Under the terms of the agreement, Remington stockholders will receive $27.00 in cash and 0.436 shares of our common stock for each Remington share. The acquisition is conditioned upon, among other things, the approval of Remington stockholders.

          The transaction is expected to be completed in the second quarter of 2006. In limited circumstances, if Remington fails to close the transaction, it must pay us a $45 million breakup fee and reimburse up to $2 million of our expenses related to the transaction. We expect to fund the cash portion of the Remington acquisition (approximately $814 million) through a senior secured term facility which has been underwritten by a bank. A detailed description of this transaction is set forth in our registration statement on Form S-4 (Reg. No. 333-132922).

          Financing Activities.We have financed seasonal operating requirements and capital expenditures with internally generated funds, borrowings under credit facilities, sale of equity and project financings.

Convertible Senior Notes

          On March 30, 2005, we issued $300 million of 3.25% Convertible Senior Notes due 2025 at 100% of the principal amount to certain qualified institutional buyers. Proceeds from the offering were used for general corporate purposes including a capital contribution of $72 million (made in March 2005) to Deepwater Gateway, L.L.C. to enable it to repay its term loan, $163.5 million related to the ERT acquisition of the Murphy properties in June 2005 and approximately $85.6 million to partially fund the Torch vessels acquired in August 2005.

MARAD Debt

          The MARAD debt is payable in equal semi-annual installments which began in August 2002 and matures 25 years from such date. We made one payment during each of the three months ended March 31, 2006 and 2005 totaling $1.8 million and $2.1 million, respectively. The MARAD Debt is collateralized by theQ4000,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 March 31, 2006, we were in compliance with these covenants.

          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.

26

Revolving Credit Facility

          In August 2004, we entered into a four year, $150 million revolving credit facility with a syndicate of banks, with Bank of America, N.A. as administrative agent and lead arranger. The amount available under the facility may be increased to $250 million at any time upon the agreement of us and existing or additional lenders. The credit facility is secured by the stock in certain of our subsidiaries and contains a negative pledge on assets. The facility bears interest at LIBOR plus 75-175 basis points depending on our leverage and contains financial covenants relative to the our level of debt to EBITDA, as defined in the credit facility, fixed charge coverage and book value of assets coverage. As of March 31, 2006, we were in compliance with these covenants and there was no outstanding balance under this facility.

Other

          Related to our $55 million cumulative convertible preferred stock, we paid $1.1 million and $550,000 in dividends for the three months ended March 31, 2006 and 2005, respectively. The holder may redeem the value of its original and additional investment in the preferred shares to be settled in common stock at the then prevailing market price or cash at our discretion. In the event we are unable to deliver registered common shares, we could be required to redeem in cash.

          In addition, in connection with the acquisition of Helix Energy Limited, on November 3, 2005, we entered into a two year notes payable to former owners totaling approximately 3.1 million British Pounds, or approximately $5.6 million ($5.5 million at March 31, 2006). The notes bear interest at a LIBOR based floating rate with payments due quarterly beginning on January 31, 2006. Principal amounts are due in November 2007.

          In connection with borrowings under credit facilities and long-term debt financings, we have paid deferred financing costs totaling $7.6 million in the three months ended March 31, 2005.

          Related to the Canyon purchase in January 2002, we purchased the final one-third of the redeemable shares at the minimum purchase price of $13.53 per share ($2.4 million) in March 2005. Consideration included approximately $337,000 of contingent consideration relating to tax gross-up payments paid to the Canyon employees in accordance with the purchase agreement. This gross-up amount was recorded as goodwill in the period paid.

          During the first three months of 2006 and 2005, we made payments of $739,000 and $702,000, respectively, on capital leases relating to Canyon. The only other financing activity during the three months ended March 31, 2006 and 2005 involved exercises of employee stock options of $7.7 million and $6.1 million, respectively. In addition, in the first quarter of 2006, financing activities included $6.7 million of excess tax benefits related to exercise of options and vesting of restricted shares.

27

          The following table summarizes our contractual cash obligations as of March 31, 2006 and the scheduled years in which the obligations are contractually due (in thousands):

			Less Than						More Than
	Total(1)		1 year		1-3 Years		3-5 Years		5 Years
Convertible Senior Notes(2)	$	300,000	$	—	$	—	$	—	$	300,000
MARAD debt		133,129		3,731		8,030		8,851		112,517
Revolving debt		—		—		—		—		—
Loan notes		5,452		—		5,452		—		—
Capital leases		6,113		2,707		3,406		—		—
Acquisition of businesses(3)		814,000		814,000		—		—		—
Investments in Independence Hub, LLC		20,000		20,000		—		—		—
Drilling and development costs		64,000		32,000		32,000		—		—
Property and equipment(4)		16,700		16,700		—		—		—
Operating leases		16,646		2,693		4,077		3,253		6,623
Total cash obligations	$	1,376,040	$	891,831	$	52,965	$	12,104	$	419,140

(1)	Excludes guarantee of performance related to the construction of the Independence Hub platform under Independence Hub, LLC (estimated to be immaterial at March 31, 2006) and unsecured letters of credit outstanding at March 31, 2006 totaling $6.9 million. These letters of credit primarily guarantee various contract bidding and insurance activities.
(2)	Maturity 2025. Can be converted prior to stated maturity if closing sale price of Helix’s common stock for at least 20 days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter exceeds 120% of the closing price on that 30th trading day (i.e. $38.56 per share).
(3)	On January 23, 2006, we announced an agreement under which we will acquire Remington in a transaction valued at approximately $1.4 billion. Under the terms of the agreement, Remington stockholders will receive $27.00 in cash and 0.436 shares of our common stock for each Remington share. We expect to fund the cash portion of the Remington acquisition (approximately $814 million) through a senior secured term facility which has been underwritten by a bank (not reflected in the table above). See Note 18 to the Condensed Consolidated Financial Statements included herein for detailed discussion of this transaction.
(4)	At December 31, 2005, we had committed to purchase a certain Contracting Services vessel (Caesar) to be converted into a deepwater pipelay vessel. The vessel was purchased in January 2006 for $27.5 million and estimated conversion costs are estimated to be approximately $93 million, of which $1.7 million was committed at March 31, 2006. Further, we will upgrade theQ4000to include drilling via the addition of a modular-based drilling system for approximately $40 million, of which approximately $10 million had been committed at March 31, 2006.

          In addition, in connection with our business strategy, we regularly evaluate acquisition opportunities (including additional vessels as well as interest in offshore natural gas and oil properties). We believe internally generated cash flow, borrowings under existing credit facilities and use of project financings along with other debt and equity alternatives will provide the necessary capital to meet these obligations and achieve our planned growth. However, there can be no assurance that sufficient financing will be available for all future capital expenditures.

28

Item 3. Quantitative and Qualitative Disclosure about Market Risk

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

Interest Rate Risk

          Because only 1% of our outstanding debt at March 31, 2006 was based on floating rates, changes in interest would, assuming all other things equal, have a minimal impact on the fair market value of the debt instruments.

Commodity Price Risk

          We have utilized derivative financial instruments with respect to a portion of 2006 and 2005 oil and gas production to achieve a more predictable cash flow by reducing our exposure to price fluctuations. We do not enter into derivative or other financial instruments for trading purposes.

          As of March 31, 2006, we have the following volumes under derivative contracts related to our oil and gas producing activities:

	Instrument	Average	Weighted
Production Period	Type	Monthly Volumes	Average Price
Crude Oil:
April 2006 – December 2006	Collar	125 MBbl	$	44.00 - $70.48
January 2007 – December 2007	Collar	50 MBbl	$	40.00 - $62.15
Natural Gas:
April 2006 – December 2006	Collar	666,667 MMBtu	$	7.38 - $13.37
January 2007 – March 2007	Collar	600,000 MMBtu	$	8.00 - $16.24

          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.

          Subsequent to March 31, 2006, we entered into additional natural gas costless collars for the period of April 2007 through June 2007. The contract covers 500,000 MMBtu per month at a weighted average price of $8.00 to $10.62.

Foreign Currency Exchange Rates

          Because we operate in various oil and gas exploration and production regions in the world, we conduct a portion of our business in currencies other than the U.S. dollar (primarily with respect to Well Ops (U.K.) Limited and Helix Energy Limited). The functional currency for Well Ops (U.K.) Limited and Helix Energy Limited is the applicable local currency (British Pound). Although the revenues are denominated in the local currency, the effects of foreign currency fluctuations are partly mitigated because local expenses of such foreign operations also generally are denominated in the same currency. The impact of exchange rate fluctuations during each of the three months ended March 31, 2006 and 2005, respectively, were not material to our results of operations or cash flows.

          Assets and liabilities of Wells Ops (U.K.) Limited and Helix Energy Limited are translated using the exchange rates in effect at the balance sheet date, resulting in translation adjustments that are reflected in accumulated other comprehensive income in the shareholders’ equity section of our balance sheet. Approximately 10% of our assets are impacted by changes in foreign currencies in relation to the U.S. dollar at March 31, 2006. We recorded unrealized gains (losses) of $1.2 million and $(1.6) million, respectively, to our equity account in the three months ended March 31, 2006 and 2005. Beginning in 2004, deferred taxes have not been provided on foreign currency translation adjustments since we

29

consider our undistributed earnings (when applicable) of our non-U.S. subsidiaries to be permanently reinvested.

          Canyon Offshore, our ROV subsidiary, has operations in the United Kingdom and Southeast Asia sectors. Canyon conducts the majority of its operations in these regions in U.S. dollars which it considers the functional currency. When currencies other than the U.S. dollar are to be paid or received, the resulting transaction gain or loss is recognized in the statements of operations. These amounts for the three months ended March 31, 2006 and 2005, respectively, were not material to our results of operations or cash flows.

Item 4. Controls and Procedures

          (a)Evaluation of disclosure controls and procedures. Our management, with the participation of the our principal executive officer (CEO) and principal financial officer (CFO), evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of the end of the fiscal quarter ended March 31, 2006. Based on this evaluation, the CEO and CFO have concluded that the our disclosure controls and procedures were effective as of the end of the fiscal quarter ended March 31, 2006 to ensure that information that is required to be disclosed by us in the reports we file or submit under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms and (ii) accumulated and communicated to our management, as appropriate, to allow timely decisions regarding required disclosure.

          (b) Changes in internal control over financial reporting.There were no changes in the our internal control over financial reporting that occurred during the fiscal quarter ended March 31, 2006 that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting.

30

Part II. OTHER INFORMATION

Item 1. Legal Proceedings

          See Part I, Item 1, Note 17 to the Condensed Consolidated Financial Statements, which is incorporated herein by reference.

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

Issuer Purchases of Equity Securities

					(c) Total		(d) Maximum
					number		value of shares
					of shares		that may yet be
	(a) Total		(b)		purchased as		purchased
	number		Average		part of publicly		under
	of shares		price paid		announced		the program
Period	purchased		per share		program		(in millions)
January 1 to January 31, 2006(1)		4,138	$	35.89		—	$	N/A
February 1 to February 28, 2006		—		—		—		N/A
March 1 to March 31, 2006		—		—		—		N/A
		4,138	$	35.89		—	$	N/A

(1) 4,138 shares subject to restricted share awards were withheld to satisfy tax obligations arising upon the vesting of restricted shares.

Item 6. Exhibits

15.1	Independent Registered Public Accounting Firm’s Acknowledgement Letter(1)
31.1	Certification Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934 by Owen Kratz, Chief Executive Officer(1)
31.2	Certification Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934 by A. Wade Pursell, Chief Financial Officer(1)
32.1	Section 1350 Certification by Owen Kratz, Chief Executive Officer(2)
32.2	Section 1350 Certification by A. Wade Pursell, Chief Financial Officer(2)
99.1	Report of Independent Registered Public Accounting Firm(1)
	(1) Filed herewith
	(2) Furnished herewith

31

SIGNATURES

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

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

	HELIX ENERGY SOLUTIONS GROUP, INC. (Registrant)
Date: May 4, 2006	By:	/s/Owen Kratz
		Owen Kratz
		Chairman and Chief Executive Officer
Date: May 4, 2006	By:	/s/A. Wade Pursell
		A. Wade Pursell
		Senior Vice President and Chief Financial Officer

32

INDEX TO EXHIBITS
OF
HELIX ENERGY SOLUTIONS GROUP, INC.

15.1	Independent Registered Public Accounting Firm’s Acknowledgement Letter(1)
31.1	Certification Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934 by Owen Kratz, Chief Executive Officer(1)
31.2	Certification Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934 by A. Wade Pursell, Chief Financial Officer(1)
32.1	Section 1350 Certification by Owen Kratz, Chief Executive Officer(2)
32.2	Section 1350 Certification by A. Wade Pursell, Chief Financial Officer(2)
99.1	Report of Independent Registered Public Accounting Firm(1)
	(1) Filed herewith
	(2) Furnished herewith

33