SEC Filing | Helix Energy Solutions Group, Inc.

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

[X]		Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
		For the quarterly period ended March 31, 2009
		or
[ ]		Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
		For the transition period from__________ to__________

Commission File Number 001-32936

HELIX ENERGY SOLUTIONS GROUP, INC.

(Exact name of registrant as specified in its charter)

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

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

(281) 618–0400

(Registrant's telephone number, including area code)

NOT APPLICABLE

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

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

Yes

[ √ ]

[ ]

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

Yes

[ ]

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

Large accelerated filer

[ √ ]

Accelerated filer

[ ]

Non-accelerated filer

[ ]

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

Yes

[ ]

[ √ ]

As of April 30, 2009, 98,379,842 shares of common stock were outstanding.

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PART I.	FINANCIAL INFORMATION	PAGE
Item 1.	Financial Statements:
	Condensed Consolidated Balance Sheets – March 31, 2009 (Unaudited) and December 31, 2008	3
	Condensed Consolidated Statements of Operations (Unaudited) – Three months ended March 31, 2009 and 2008	4
	Condensed Consolidated Statements of Cash Flows (Unaudited) – Three months ended March 31, 2009 and 2008	5
	Notes to Condensed Consolidated Financial Statements (Unaudited)	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	44
Item 4.	Controls and Procedures	45
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	46
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46
Item 6.	Exhibits	46
	Signatures	47
	Index to Exhibits	48

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,
	2009			2008
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	251,585		$	223,613
Accounts receivable — Trade, net of allowance for uncollectible accounts of $6,203 and $5,904, respectively		385,090			427,856
Unbilled revenue		43,795			42,889
Costs in excess of billing		67,927			74,361
Other current assets		200,269			172,089
Net assets of discontinued operations		17,153			19,215
Total current assets		965,819			960,023
Property and equipment		4,803,576			4,742,051
Less — accumulated depreciation		(1,384,226	)		(1,323,608	)
		3,419,350			3,418,443
Other assets:
Equity investments		194,087			196,660
Goodwill		365,641			366,218
Other assets, net		117,791			125,722
	$	5,062,688		$	5,067,066

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	271,969		$	344,807
Accrued liabilities		209,215			231,679
Income tax payable		26,921			—
Current maturities of long-term debt		93,644			93,540
Current liabilities of discontinued operations		6,489			2,772
Total current liabilities		608,238			672,798
Long-term debt		1,912,357			1,933,686
Deferred income taxes		657,138			615,504
Decommissioning liabilities		196,836			194,665
Other long-term liabilities		8,723			81,637
Total liabilities		3,383,292			3,498,290

Convertible preferred stock		25,000			55,000

Commitments and contingencies		—			—
Shareholders’ equity:
Common stock, no par, 240,000 shares authorized, 98,376 and 91,972 shares issued, respectively		891,809			806,905
Retained earnings		471,390			417,940
Accumulated other comprehensive loss		(41,772	)		(33,696	)
Total controlling interest shareholders’ equity		1,321,427			1,191,149
Noncontrolling interests		332,969			322,627
Total equity		1,654,396			1,513,776
	$	5,062,688		$	5,067,066

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

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

(in thousands, except per share amounts)

		Three Months Ended
		March 31,
		2009			2008

Net revenues:
Contracting services	$	410,794		$	270,718
Oil and gas		160,181			171,051
		570,975			441,769

Cost of sales:
Contracting services		325,698			213,514
Oil and gas		84,067			109,672
		409,765			323,186

Gross profit		161,210			118,583

Gain on oil and gas derivative contracts		74,609			—
Gain on sale of assets, net		454			61,113
Selling and administrative expenses		(41,353	)		(46,168	)
Income from operations		194,920			133,528
Equity in earnings of investments		7,503			10,816
Net interest expense and other		(22,195	)		(28,001	)
Income before income taxes		180,228			116,343
Provision for income taxes		(64,919	)		(42,700	)
Income from continuing operations		115,309			73,643
Discontinued operations, net of tax		(2,554	)		559
Net income, including noncontrolling interests		112,755			74,202
Net income applicable to noncontrolling interests		(5,553	)		(237	)
Net income applicable to the Helix		107,202			73,965
Preferred stock dividends		(313	)		(881	)
Preferred stock beneficial conversion charges		(53,439	)		—
Net income applicable to Helix common shareholders	$	53,450		$	73,084

Basic earnings per share of common stock:
Continuing operations	$	0.58		$	0.79
Discontinued operations		(0.03	)		0.01
Net income per common share	$	0.55		$	0.80

Diluted earnings per share of common stock:
Continuing operations	$	0.52		$	0.76
Discontinued operations		(0.02	)		0.01
Net income per common share	$	0.50			0.77

Weighted average common shares outstanding:
Basic		95,052			90,413
Diluted		105,863			95,086

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

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(in thousands)

		Three Months Ended
		March 31,
		2009			2008
Cash flows from operating activities:
Net income, including noncontrolling interests	$	112,755		$	74,202
Adjustments to reconcile net income, including noncontrolling interests to net cash provided by operating activities —
Depreciation and amortization		82,893			84,554
Asset impairment charge and dry hole expense		361			16,671
Equity in earnings of investments, net of distributions		320			81
Amortization of deferred financing costs		1,482			1,062
(Income) loss from discontinued operations		2,554			(559	)
Stock compensation expense		4,084			8,079
Amortization of debt discount		1,938			1,816
Deferred income taxes		43,699			5,763
Excess tax benefit from stock-based compensation		1,676			(629	)
Gain on sale of assets		(454	)		(61,113	)
Unrealized gain on derivative contracts		(55,420	)		—
Changes in operating assets and liabilities:
Accounts receivable, net		41,134			112,355
Other current assets		(2,448	)		(4,924	)
Income tax payable		54,518			36,861
Accounts payable and accrued liabilities		(51,713	)		(116,297	)
Other noncurrent, net		(73,889	)		(30,721	)
Cash provided by operating activities		163,490			127,201
Cash provided by (used in ) discontinued operations		(1,002	)		(1,635	)
Net cash provided by operating activities		162,488			125,566

Cash flows from investing activities:
Capital expenditures		(133,663	)		(241,550	)
Investments in equity investments		(320	)		(207	)
Distributions from equity investments, net		2,477			5,995
Increase in restricted cash		—			(232	)
Proceeds from sales of property		22,481			110,147
Net cash used in investing activities		(109,025	)		(125,847	)

Cash flows from financing activities:
Repayment of Helix Term Notes		(1,082	)		(1,082	)
Borrowings on Helix Revolver		—			318,500
Repayments on Helix Revolver		(100,000	)		(185,000	)
Repayment of MARAD borrowings		(2,081	)		(1,982	)
Borrowings on CDI Revolver		100,000			—
Repayments on CDI Term Note		(20,000	)		(40,000	)
Deferred financing costs		—			(409	)
Preferred stock dividends paid		(250	)		(881	)
Repurchase of common stock		(288	)		(3,309	)
Excess tax benefit from stock-based compensation		(1,676	)		629
Exercise of stock options, net		—			321
Net cash provided by (used in) financing activities		(25,377	)		86,787

Effect of exchange rate changes on cash and cash equivalents		(114	)		58
Net increase in cash and cash equivalents		27,972			86,564
Cash and cash equivalents:
Balance, beginning of year		223,613			89,555
Balance, end of period	$	251,585		$	176,119

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

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 – Basis of Presentation

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

The accompanying condensed consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles and are consistent in all material respects with those applied in our Annual Report on Form 10-K for the year ended December 31, 2008 (“2008 Form 10-K”). The preparation of these financial statements requires us to make estimates and judgments that affect the amounts reported in the financial statements and the related disclosures. Actual results may differ from our estimates. Management has reflected all adjustments (which were normal recurring adjustments unless otherwise disclosed herein) that it believes are necessary for a fair presentation of the condensed consolidated balance sheets, results of operations, and cash flows, as applicable. Operating results for the period ended March 31, 2009 are not necessarily indicative of the results that may be expected for the year ending December 31, 2009. Our balance sheet as of December 31, 2008 included herein has been derived from the audited balance sheet as of December 31, 2008 included in our 2008 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 2008 Form 10-K.

Certain reclassifications were made to previously reported amounts in the condensed consolidated financial statements and notes thereto to make them consistent with the current presentation format, including the adoption of certain recent accounting pronouncement that require retrospective application (Note 3).

Note 2 – Company Overview

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

Contracting Services Operations

We seek to provide services and methodologies, which we believe are critical to finding and developing offshore reservoirs and maximizing production economics, particularly from marginal fields. By “marginal”, we mean reservoirs that are no longer wanted by major operators or are too small to be material to them. Our “life of field” services are segregated into four disciplines: construction, well operations, drilling, and production facilities. We have disaggregated our contracting services operations into three reportable segments in accordance with Financial Accounting Standards Board (“FASB”) Statement No. 131 Disclosures about Segments of an Enterprise and Related Information (“SFAS No. 131”): Contracting Services, Shelf Contracting and Production Facilities. Our Contracting Services business includes subsea construction, well operations, robotics and drilling. Our Shelf Contracting business represents the assets of CDI, of which we owned 57.2% at December 31, 2008. In January 2009, our ownership of CDI was reduced to approximately 51% (Note 3). Our Production Facilities business includes our investments in Deepwater Gateway, L.L.C. (“Deepwater Gateway”) and Independence Hub, LLC (“Independence Hub”).

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Oil and Gas Operations

In 1992 we began our oil and gas operations to provide a more efficient solution to offshore abandonment, to expand our off-season asset utilization of our contracting services business and to achieve incremental returns to our contracting services. Since 1992, we have evolved this business model to include not only mature oil and gas properties but also proved and unproved reserves yet to be developed and explored. This has led to the assembly of services that allows us to create value at key points in the life of a reservoir from exploration through development, life of field management and operating through abandonment.

Discontinued Operations

In February 2009, our board of directors approved a formal plan to market and to sell our reservoir and well technology services business. On April 27, 2009, we sold Helix Energy Limited (“HEL”) to a subsidiary of Baker Hughes Incorporated for $25 million. HEL through its subsidiary, Helix RDS Limited is a provider of reservoir engineering, geophysical, production technology and associated specialized consulting services to the upstream oil and gas industry. As a result of the formal efforts to sell HEL and Helix RDS Limited, we have presented the results of Helix RDS as discontinued operations in the accompanying condensed consolidated financial statements. HEL and Helix RDS were previously components of our Contracting Services segment. No asset or liability of HEL and Helix RDS are material to any single line item in our accompanying condensed consolidated balance sheet. .

Economic Outlook

The continued economic downturn and weakness in the equity and credit capital markets has led to increased uncertainty regarding the outlook of the global economy. This uncertainty coupled with the decrease in the near-term global demand for oil and gas resulted in commodity price declines over the second half of 2008, with significant declines occurring in the fourth quarter of 2008. A decline in oil and gas prices negatively impacts our operating results and cash flows. Our stock price also significantly declined over the second half of 2008. The decline in our stock price and the prices of oil and natural gas were considered in association with our required annual impairment assessment of goodwill and properties at year end 2008, which resulted in significant impairment charges (see Note 2 of our “2008 Form 10-K”). Our stock price decreased further in the first quarter of 2009 resulting in our assessment our goodwill amounts as of March 31, 2009; however, no further impairments were required. Our stock price has recently increased; however, we are required to continue to monitor our remaining $365.6 million of goodwill as of March 31, 2009, of which $73.1 million is included within Contracting Services and $292.5 million for the Shelf Contracting. Our Contracting Services and Shelf Contracting segments may be negatively impacted by low commodity prices because that may cause our customers, primarily oil and gas companies, to curtail or eliminate capital spending. We have stabilized the price for a significant portion of our anticipated oil and gas production for 2009 when we entered into commodity hedges during 2008, which is enabling us to minimize our near-term cash flow risks related to declining commodity prices (Note 17). As of March 31, 2009 and as of the time of this filing on May 8, 2009, the prices for these contracts are significantly higher than the forward market prices for both crude oil and natural gas over the remainder of 2009. In March 2009, we entered into additional financial swap contracts for a portion of our anticipated 2010 natural gas production. These prices approximate the future strip price for natural gas. If the prices for crude oil and natural gas do not increase from current levels, our oil and gas revenues may decrease in 2010 and beyond, perhaps significantly, absent increases in production amounts.

Note 3 – Recent Accounting Pronouncements

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

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

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

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

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

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

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

The following table provides additional information related to assets and liabilities measured at fair value on a recurring basis at March 31, 2009 (in thousands):

Level 1

Level 2

Level 3

Total

Valuation Technique

Assets:

Oil and gas swaps and collars

–

77,939

–

77,939

(c)

Foreign currency forwards

–

(c)

Liabilities:

Gas swaps and collars

–

1,227

–

1,227

(c)

Foreign currency forwards

–

559

–

559

(c)

Interest rate swaps

–

7,231

–

7,231

(c)

Total

–

68,951

–

68,951

In December 2007, the FASB issued Statement No. 141 (Revised), Business Combinations (“SFAS No. 141(R)”). SFAS No. 141 (R) requires the acquiring entity in a business combination to recognize all the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. It also requires that the costs incurred related to the acquisition be charged to expense as incurred, when previously these costs were capitalized as part of the acquisition cost of the asset or business. We adopted the provisions of SFAS No. 141(R) on January 1, 2009 and it had no impact on our results of operations, cash flows and financial condition.

In December 2007, the FASB issued Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB 51 (“SFAS No. 160”). SFAS No. 160 improves the relevance, comparability, and transparency of financial information provided to investors by requiring all entities to report noncontrolling (minority) interests in subsidiaries as equity in the consolidated financial statements. We adopted SFAS No. 160 on January 1, 2009, which is required to be adopted prospectively, except the following provisions must be adopted retrospectively:

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1.	Reclassifying noncontrolling interest from the “mezzanine” to equity, separate from the parents’ shareholders’ equity, in the statement of financial position; and

2.	Recast consolidated net income to include net income attributable to both the controlling and noncontrolling interests. That is, retrospectively, the noncontrolling interests’ share of a consolidated subsidiary’s income should not be presented in the income statement as “minority interest.”

Effective January 1, 2009, we changed our accounting policy of recognizing a gain or loss upon any future direct sale or issuance of equity by our subsidiaries if the sales price differs from our carrying amount to be in accordance with SFAS No. 160, in which a gain or loss will only be recognized when loss of control of a consolidated subsidiary occurs. In January 2009, we sold approximately 13.6 million shares of CDI common stock to CDI for $86 million. This transaction constituted a single transaction and was not part of any planned set of transactions that would result in us having a noncontrolling interest in CDI. Our ownership of CDI following the transaction approximated 51%. Since we retained control of CDI immediately after the transaction, the approximate $2.9 million loss on this sale was treated as a reduction of our equity in the accompanying condensed consolidated balance sheet. Any future significant transactions would result in us losing control of CDI and accordingly the gain or loss on those transactions will be recognized in our statement of operations.

In March 2008, the FASB issued Statement No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 (“SFAS No. 161”). SFAS 161 applies to all derivative instruments and related hedged items accounted for under SFAS No. 133. SFAS No. 161 requires entities to provide qualitative disclosures about the objectives and strategies for using derivatives, quantitative data about the fair value of and gains and losses on derivative contracts, and details of credit-risk-related contingent features in their hedged positions. We adopted the provisions of SFAS No. 161 on January 1, 2009 and it had no impact on our results of operations, cash flows or financial condition. See Note 17 below for additional disclosure regarding our derivative instruments.

In May 2008, the FASB issued FASB Staff Position (“FSP”) APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement) (“FSP APB 14-1”). We adopted the FSP APB 14-1 effective January 1, 2009. FSP APB 14-1 requires retrospective application for all periods reported (with the cumulative effect of the change reported in retained earnings as of the beginning of the first period presented). FSP APB 14-1 requires the proceeds from the issuance of convertible debt instruments to be allocated between a liability component (issued at a discount) and an equity component. The resulting debt discount is amortized over the period the convertible debt is expected to be outstanding as additional non-cash interest expense. This FSP changed the accounting treatment for our Convertible Senior Notes. FSP APB 14-1 increases our interest expense for our past and future reporting periods by recognizing accretion charges on the resulting debt discount.

Upon adoption of FSP APB 14-1, we recorded a discount of $60.2 million related to our Convertible Senior Notes. To arrive at this discount amount we estimated the fair value of the liability component of the Convertible Senior Notes as of the date of their issuance (March 30, 2005) using an income approach. To determine this estimated fair value, we used borrowing rates of similar market transactions involving comparable liabilities at the time of issuance and an expected life of 7.75 years. In selecting the expected life, we selected the earliest date that the holder could require us to repurchase all or a portion of the Convertible Senior Notes (December 15, 2012).

The following table sets forth the effect of retrospective application of FSP APB 14-1 and FSP EITF 03-06-1 “Determining Whether Instruments Granted in Share Based Payment Transactions Are Participating Securities” (Note 12) and discontinued operations on certain previously reported line items in our accompanying condensed consolidated statements of operations (in thousands, except per share data):

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	Three Months Ended March 31, 2008
	Originally Reported		As Adjusted

Net interest expense and other	$	26,046	$	28,001
Provision for Income taxes		43,632		42,700
Net income from continuing operations		75,453		73,643

Earnings per common share from continuing operations - Basic	$	0.82	$	0.79
Earnings per common share from continuing operations – Diluted		0.79		0.76

The following table sets forth the effect of retrospective application of FSP APB 14-1 on certain previously reported line items in our accompanying condensed consolidated balance sheet (in thousands):

	December 31, 2008
	As Reported		As Adjusted

Long-term debt	$	1,968,502	$	1,933,686
Deferred income tax liability		604,464		615,504
Common stock, no par value		768,835		806,905
Retained earnings		435,506		417,940
Total controlling interest shareholders’ equity		1,170,645		1,191,149

Note 4 – Details of Certain Accounts (in thousands)

Other current assets consisted of the following as of March 31, 2009 and December 31, 2008:

	March 31,		December 31,
	2009		2008

Other receivables	$	14,819	$	22,977
Prepaid insurance		10,948		18,327
Other prepaids		37,703		23,956
Current deferred tax assets		5,447		3,978
Insurance claims to be reimbursed		7,824		7,880
Hedging assets		78,162		26,800
Gas imbalance		6,691		7,550
Inventory		31,754		32,195
Income tax receivable		—		23,485
Other		6,921		4,941
	$	200,269	$	172,089

Other assets, net, consisted of the following as of March 31, 2009 and December 31, 2008:

	March 31,		December 31,
	2009		2008

Restricted cash	$	35,412	$	35,402
Deposits		2,872		1,890
Deferred drydock expenses, net		35,935		38,620
Deferred financing costs		32,179		33,431
Intangible assets with definite lives, net		5,598		7,600
Other		5,795		8,779
	$	117,791	$	125,722

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Accrued liabilities consisted of the following as of March 31, 2009 and December 31, 2008:

	March 31,		December 31,
	2009		2008

Accrued payroll and related benefits	$	35,786	$	46,224
Royalties payable		8,152		10,265
Current decommissioning liability		31,126		31,116
Unearned revenue		16,374		9,353
Billings in excess of costs		10,180		13,256
Insurance claims to be reimbursed		7,824		7,880
Accrued interest		19,493		34,299
Deposit		25,542		25,542
Hedge liability		7,984		7,687
Other		46,754		46,057
	$	209,215	$	231,679

Note 5 – Convertible Preferred Stock

In January 2003, we completed the private placement of $25 million of a newly designated class of cumulative convertible stock (Series A-1 Cumulative Convertible Stock, par value $0.01 per share) convertible into 1,666,668 shares of our common stock at $15 per share. The preferred stock was issued to a private investment firm, Fletcher International, Ltd. (“Fletcher”). Subsequently on June 2004, Fletcher exercised an existing right to purchase an additional $30 million of cumulative convertible preferred stock (Series A-2 Cumulative Convertible Preferred Stock, par value $0.01 per share) convertible into 1,964,058 shares of our common stock at $15.27 per share. Pursuant to the agreement governing the preferred stock (the “Fletcher Agreement”), Fletcher was entitled to convert its investment in the preferred shares at any time, or redeem its investment in the preferred shares at any time after December 31, 2004. In January 2009, Fletcher issued a redemption notice with respect to all its shares of the Series A-2 Cumulative Convertible Preferred Stock, and, pursuant to such redemption, we issued and delivered 5,938,776 shares of our common stock to Fletcher. Accordingly, in the first quarter of 2009 we recognized a $29.3 million charge to reflect the terms this redemption, which was recorded as a reduction our net income applicable to common shareholders. This beneficial conversion charge reflected the value associated with the additional 3,974,718 shares delivered over the original 1,964,058 shares that were contractually required to be issued upon conversion but was limited to the $29.3 million of net proceeds we received from the issuance of the Series A-2 Cumulative Convertible Preferred Stock.

The Fletcher Agreement provided that if the volume weighted average price of our common stock on any date was less than a certain minimum price ($2.767), then our right to pay dividends in our common stock is extinguished, and we must deliver a notice to Fletcher that either (1) the conversion price will be reset to such minimum price (in which case Fletcher shall have no further right to cause the redemption of the preferred stock), or (2) in the event Fletcher exercises its redemption rights, we will satisfy our redemption obligations either in cash, or a combination of cash and common stock subject to a maximum number of shares (14,973,814) that can be delivered to Fletcher under the Fletcher Agreement. On February 25, 2009, the volume weighted average price of our common stock was below the minimum price, and, on February 27, 2009 we provided notice to Fletcher that with respect to the Series A-1 Cumulative Convertible Preferred Stock the conversion price is reset to $2.767 as of that date and that Fletcher shall have no further rights to redeem the shares, and we have no further right to pay dividends in common stock. As a result of the reset of the conversion price, Fletcher would receive an aggregate of 9,035,056 shares in future conversion(s) into our common stock. In the event we elect to settle any future conversion in cash, Fletcher would receive cash in an amount approximately equal to the value of the shares it would receive upon a conversion, which could be substantially greater than the original face amount of the Series A-1 Cumulative Convertible Preferred Stock, and which would result in additional beneficial conversion charges in our statement of operations. Under the existing terms of our Senior Credit Facilities (Note 9) we are not permitted to deliver cash to the holder upon a conversion of the Convertible Preferred Stock.

In connection with the reset of the conversion price of the Series A-1 Cumulative Convertible Preferred Stock to $2.767, we were required to recognize a $24.1 million charge to reflect the value associated with the additional 7,368,388 shares that will be required to be delivered upon any future conversion(s) over the 1,666,668 shares that were to be delivered under the original contractual terms. This $24.1 million charge was recorded as a beneficial conversion charge reducing our net income applicable to common shareholders. Similar to the beneficial conversion charge associated with the redemption of Series A-2 Cumulative Convertible Preferred Stock, the beneficial conversion charge for the Series A-1 Cumulative Convertible Preferred Stock is limited to the $24.1 million of net proceeds received upon its issuance.

The remaining $25 million of our convertible preferred stock maintains its mezzanine presentation below liabilities but not included as component of shareholders’ equity, because we may, under certain instances be required to settle any future conversions in cash. Prior to any future conversion(s), the common shares issuable will be assessed for inclusion in our diluted earnings per share computations using the if converted method based on the applicable conversion price of $2.767 per share, meaning that for all periods in which our average stock price exceeds $2.767 per share we will have an assumed conversion of convertible preferred stock and the 9,035,056 shares will be included in our diluted shares outstanding amount.

Note 6 – Oil and Gas Properties

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

Litigation and Claims

On December 2, 2005, we received an order from the U.S. Department of the Interior Minerals Management Service (“MMS”) that the price threshold for both oil and gas was exceeded for 2004 production and that royalties were due on such production notwithstanding the provisions of the Outer Continental Shelf Deep Water Royalty Relief Act of 2005 (“DWRRA”), which was intended to stimulate exploration and production of oil and natural gas in the deepwater Gulf of Mexico by providing relief from the obligation to pay royalty on certain federal leases up to certain specified production volumes. Our oil and gas leases affected by this dispute are Garden Banks Blocks 667, 668 and 669 (“Gunnison”). On May 2, 2006, the MMS issued another order that superseded the December 2005 order, and claimed that royalties on gas production are due for 2003 in addition to oil and gas production in 2004. The Order also seeks interest on all royalties allegedly due. We filed a timely notice of appeal with respect to both the December 2005 Order and the May 2006 Order. We received an additional order from the MMS dated September 30, 2008 stating that the price thresholds for oil and gas were exceeded for 2005, 2006 and 2007 production and that royalties and interest are payable. We appealed this order on the same basis as the previous orders.

Other operators in the Deep Water Gulf of Mexico who have received notices similar to ours are seeking royalty relief under the DWRRA, including Kerr-McGee, the operator of Gunnison. In March of 2006, Kerr-McGee filed a lawsuit in federal district court challenging the enforceability of price thresholds in certain deepwater Gulf of Mexico leases, including ours. On October 30, 2007, the federal district court in the Kerr-McGee case entered judgment in favor of Kerr-McGee and held that the Department of the Interior exceeded its authority by including the price thresholds in the subject leases. The government filed a notice of appeal of that decision on December 21, 2007. On January 12, 2009, the United States Court of Appeals for the Fifth Circuit affirmed the decision of the district court in favor of Kerr-McGee, holding that the DWRRA unambiguously provides that royalty suspensions up to certain production volumes established by Congress apply to leases that qualify under the DWRRA. The plaintiff petitioned the appellate court for rehearing; however, that petition was denied on April 14, 2009. The plaintiff may appeal the appellate court’s decision to the United States Supreme Court, although there is no certainty that the court will accept the case.

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As a result of this dispute, we have been recording reserves for the disputed royalties (and any other royalties that may be claimed for production during 2005, 2006, 2007 and 2008) plus interest at 5% for our portion of the Gunnison related MMS claim. The result of accruing these reserves since 2005 had reduced our oil and gas revenues. Following the decision of the United States Court of Appeals for the Fifth Circuit Court , we reversed our previously accrued royalties ($73.5 million) to oil and gas revenues in the first quarter of 2009. Effective in January 2009, we commenced recognizing oil and natural gas sales revenue associated with this disputed net revenue interest and are no longer accruing any additional royalty reserves as we believe it is remote that we will be liable for such amounts.

Insurance

In September 2008, we sustained damage to certain of our oil and gas production facilities from Hurricanes Gustav and Ike. While we sustained some damage to our own production facilities from Hurricane Ike, the larger issue in terms of production recovery involved damage to third party pipelines and onshore processing facilities. The timing of when these facilities reestablish operations was not subject to our control and in certain cases some of these third party facilities remain out of service at the time of this filing. We carry comprehensive insurance on all of our operated and non-operated producing and non-producing properties, which is subject to approximately $6 million of aggregate deductibles. We met our aggregate deductible in September 2008. We record our hurricane-related costs as incurred. Insurance reimbursements will be recorded when the realization of the claim for recovery of a loss is deemed probable. In the first quarter of 2009 we incurred hurricane-related repair cost totaling $12.7 million, which was offset by reimbursement or approved reimbursement of $3.1 million.

Property Sales

In the first quarter of 2009, we sold our interest in East Cameron Block 316 for gross proceeds of approximately $18 million. We recorded an approximate $0.7 million gain from the sale of East Cameron Block 316 which was partially offset by the loss on the sale of the remaining 10% of our interest in the Bass Lite field at Atwater Block 426 in January 2009.

In March and April 2008, we sold a total 30% working interest in the Bushwood discoveries (Garden Banks Blocks 463, 506 and 507) and other Outer Continental Shelf oil and gas properties (East Cameron Blocks 371 and 381), in two separate transactions to affiliates of a private independent oil and gas company for total cash consideration of approximately $183.4 million (which included the purchasers’ share of incurred capital expenditures on these fields), and additional potential cash payments of up to $20 million based upon certain field production milestones. The new co-owners will also pay their pro rata share of all future capital expenditures related to the exploration and development of these fields. Decommissioning liabilities will be shared on a pro rata share basis between the new co-owners and us. Proceeds from the sale of these properties were used to pay down our outstanding revolving loans in April 2008. Our first quarter of 2008 results included a $61.1 million gain of the first of the two transactions previously discussed.

Exploration and Other

As of March 31, 2009, we capitalized approximately $3.3 million of costs associated with ongoing exploration and/or appraisal activities. Such capitalized costs may be charged against earnings in future periods if management determines that commercial quantities of hydrocarbons have not been discovered or that future appraisal drilling or development activities are not likely to occur.

Further, the following table details the components of exploration expense for the three months ended March 31, 2009 and 2008 (in thousands):

		Three Months Ended
		March 31,
		2009		2008

Delay rental and geological and geophysical costs	$	472	$	1,940
Dry hole expense		4		(52	)
Total exploration expense	$	476	$	1,888

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In January 2008, the development well on Devil’s Island (Garden Banks Block 344) was determined to be unsuccessful and we recorded an impairment charge of $14.3 million that is included as a component of oil and gas cost of sales in the accompanying condensed statement of operations.

Note 7 – 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, 2009 and December 31, 2008, our restricted cash totaled $35.4 million and is included in other assets, net. All of our restricted cash relates to funds required to be escrowed to cover the future decommissioning liabilities associated with the South Marsh Island 130, which we acquired in 2002. We have fully satisfied the escrow requirements under this agreement and may use the restricted cash for future decommissioning of the related field.

The following table provides supplemental cash flow information for the three months ended March 31, 2009 and 2008 (in thousands):

		Three Months Ended
		March 31,
		2009		2008

Interest paid, net of capitalized interest(1)	$	33,372	$	6,048
Income taxes paid	$	30,928	$	966

Non-cash investing activities for the three months ended March 31, 2009 included $88.4 million of accruals for capital expenditures. Non-cash investing activities for the three months ended March 31, 2008 totaled $45.7 million. The accruals have been reflected in the condensed consolidated balance sheet as an increase in property and equipment and accounts payable.

Note 8 – Equity Investments

As of March 31, 2009, we have the following material investments, both of which are included within our Production Facilities segment and are accounted for under the equity method of accounting:

Deepwater Gateway, L.L.C. In June 2002, we, along with Enterprise Products Partners L.P. (”Enterprise”), formed Deepwater Gateway, L.L.C. (“Deepwater Gateway”) (each with a 50% interest) to design, construct, install, own and operate a tension leg platform (“TLP”) production hub primarily for Anadarko Petroleum Corporation's Marco Polo field in the Deepwater Gulf of Mexico. Our investment in Deepwater Gateway totaled $104.6 million and $106.3 million as of March 31, 2009 and December 31, 2008, respectively (including capitalized interest of $1.6 million at March 31, 2009 and December 31, 2008, respectively). Distributions from Deepwater Gateway, net to our interest, totaled $3.5 million in the first quarter of 2009.

Independence Hub, LLC. In December 2004, we acquired a 20% interest in Independence Hub, LLC (“Independence”), an affiliate of Enterprise. Independence owns the "Independence Hub" platform located in Mississippi Canyon Block 920 in a water depth of 8,000 feet. First production began in July 2007. Our investment in Independence was $89.3 million and $90.2 million as of March 31, 2009 and December 31, 2008, respectively (including capitalized interest of $5.8 million and $5.9 million at March 31, 2009 and December 31, 2008, respectively). Distributions from Independence, net to our interest, totaled $6.8 million in the first quarter of 2009.

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Note 9 – Long-Term Debt

Scheduled maturities of long-term debt and capital lease obligations outstanding as of March 31, 2009 were as follows (in thousands):

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

Less than one year	$	4,326		$	─	$	80,000		$	─	$	─		$	4,318		$	5,000		$	93,644
One to two years		4,326			─		80,000			─		─			4,533			─			88,859
Two to three years		4,326			249,500		80,000			─		─			4,760			─			338,586
Three to four years		4,326			─		155,000			─		─			4,997			─			164,323
Four to five years		400,707			─		─			─		─			5,247			─			405,954
Over five years		─			─		─			550,000		300,000			97,513			─			947,513
Total debt		418,011			249,500		395,000			550,000		300,000			121,368			5,000			2,038,879
Current maturities		(4,326	)		─		(80,000	)		─		─			(4,318	)		(5,000	)		(93,644	)
Long-term debt, less current maturities	$	413,685		$	249,500	$	315,000		$	550,000	$	300,000		$	117,050		$	─		$	1,945,235
Unamortized debt discount (2)		─			─		─			─		(32,878	)		─			─			(32,878	)
Long-term debt	$	413,685		$	249,500	$	315,000		$	550,000	$	267,122		$	117,050		$	─		$	1,912,357

(1)	Includes $5 million loan provided by Kommandor RØMØ to Kommandor LLC.

(2)	Reflects debt discount resulting from adoption of APB 14-1 on January 1, 2009. The notes will increase to $300 million face amount through accretion of non-cash interest charges through 2012.

We had unsecured letters of credit outstanding at March 31, 2009 totaling approximately $24.4 million, including $13.3 million related to CDI. These letters of credit primarily guarantee various contract bidding, contractual performance and insurance activities and shipyard commitments. The following table details our interest expense and capitalized interest for the three months ended March 31, 2009 and 2008 (in thousands):

		Three Months Ended
		March 31,
		2009			2008

Interest expense	$	29,850		$	36,807
Interest income		(264	)		(1,000	)
Capitalized interest		(7,620	)		(10,971	)
Interest expense, net	$	21,966		$	24,836

Included below is a summary of certain components of our indebtedness. At March 31, 2009 and December 31, 2008, we were in compliance with all debt covenants. For additional information regarding our debt see Note 11 of our 2008 Form 10-K.

Senior Unsecured Notes

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

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Senior Credit Facilities

In July 2006, we entered into a credit agreement (the “Senior Credit Facilities”) under which we borrowed $835 million in a term loan (the “Term Loan”) and were initially able to borrow up to $300 million (the “Revolving Loans”) under a revolving credit facility (the “Revolving Credit Facility”). The proceeds from the Term Loan were used to fund the cash portion of the Remington acquisition (see Note 4 of our 2008 Form 10-K). This facility was subsequently amended in November 2007, and as part of that amendment, an accordion feature was added that allows for increases in the Revolving Credit Facility up to an additional $150 million, subject to availability of borrowing capacity provided by new or existing lenders. In May 2008, we completed a $120 million increase in the Revolving Credit Facility utilizing this accordion feature. Total borrowing capacity under the Revolving Credit Facility now totals $420 million. The full amount of the Revolving Credit Facility may be used for issuances of letters of credit.

The Term Loan matures on July 1, 2013 and is subject to quarterly scheduled principal payments. As a result of a $400 million prepayment made in December 2007, the quarterly scheduled principal payment was reduced from $2.1 million to $1.1 million. The Revolving Loans mature on July 1, 2011. At March 31, 2009, there was $159.4 million available under the Revolving Loans (including $11.1 million of unsecured letters of credit).

The Term Loan currently bears interest either at the one-, three- or six-month LIBOR at our current election plus a 2.00% margin. Our average interest rate on the Term Loan for the three months ended March 31, 2009 and 2008 was approximately 3.3% and 6.6%, respectively, including the effects of our interest rate swaps (see below). The Revolving Loans bear interest based on one-, three- or six-month LIBOR rates or on Base Rates at our current election plus a margin ranging from 1.00% to 2.25% on LIBOR loans or 0% to 1.25% on Base Rate loans. Margins on the Revolving Loans will fluctuate in relation to the consolidated leverage ratio as provided in the Credit Agreement. Our average interest rate on the Revolving Loans for the three months ended March 31, 2009 was approximately 3.4%.

Cal Dive International, Inc. Revolving Credit Facility

CDI has a senior secured credit facility with certain financial institutions, consisting of a $375 million term loan and a $300 million revolving credit facility. As of March 31, 2009, CDI had outstanding debt of $295.0 million under the term loan and $100.0 million under the revolving credit facility with $186.7 million available for borrowings. At March 31, 2009, $13.3 million of this facility was used to support letters of credit issued to secure performance bonds. The weighted-average interest rate was 3.83% (LIBOR plus 2.25%) on the $295.0 million outstanding under the term loan and 2.53% (LIBOR plus 2%) on the $100.0 million outstanding under the revolving credit facility at March 31, 2009. The term loan requires quarterly principal payments of $20 million.

At March 31, 2009 and December 31, 2008, CDI was in compliance with all debt covenants. The credit facility is secured by vessel mortgages on all of CDI’s vessels (except for the Sea Horizon), a pledge of all of the stock of all of CDI’s domestic subsidiaries and 65% of the stock of two of its foreign subsidiaries, and a security interest in, among other things, all of CDI’s equipment, inventory, accounts receivable and general tangible assets.

Convertible Senior Notes

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

The Convertible Senior Notes can be converted prior to the stated maturity under certain triggering events specified in the indenture governing the Convertible Senior Notes. To the extent we do not have long-term financing secured to cover the conversion, the Convertible Senior Notes would be classified as a current liability in the accompanying balance sheet. During the first quarter of 2009, no

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conversion triggers were met. As a result of adopting FSP APB 14-1 (Note 3), the effective interest is 6.6%.

Approximately 706,000 shares underlying the Convertible Senior Notes were included in the calculation of diluted earnings per share for the three months ended March 31, 2008, because our average share price for period was above the conversion price of approximately $32.14 per share. Our average share price was below the $32.14 per share conversion price for the three month period ended March 31, 2009 and as a result there are no shares included in our diluted earnings per share calculation associated with the assumed conversion of our Convertible Senior Notes. In the event our average share price exceeds the conversion price, there would be a premium, payable in shares of common stock, in addition to the principal amount, which is paid in cash, and such shares would be issued on conversion. The Convertible Senior Notes are convertible into a maximum 13,303,770 shares of our common stock.

MARAD Debt

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

In accordance with the Senior Unsecured Notes, amended Senior Credit Facilities, Convertible Senior Notes, MARAD Debt agreements and CDI’s credit facility, we are required to comply with certain covenants and restrictions, including the maintenance of minimum net worth, working capital and debt-to-equity requirements. As of March 31, 2009, we were in compliance with these covenants and restrictions. The Senior Unsecured Notes and Senior Credit Facilities contain provisions that limit our ability to incur certain types of additional indebtedness.

Other

Deferred financing costs of $32.2 million and $33.4 million are included in other assets, net as of March 31, 2009 and December 31, 2008, respectively, and are being amortized over the life of the respective loan agreements.

Note 10 – Income Taxes

The effective tax rate for the three months ended March 31, 2009 was 36.0% compared with 36.7% for the three months ended March 31, 2008. The effective tax rate for the first quarter of 2009 decreased as a result of the benefit derived from the Internal Revenue Code Section 199 manufacturing deduction as is primarily related to oil and gas production and the effect of lower tax rates in certain foreign jurisdictions. This decrease was partially offset by the additional deferred tax expense recorded as a result of the increase in the equity earnings of CDI in excess of our tax basis in CDI.

We believe our recorded assets and liabilities are reasonable; however, tax laws and regulations are subject to interpretation and tax litigation is inherently uncertain; therefore our assessments can involve a series of complex judgments about future events and rely heavily on estimates and assumptions. See Note 16 below for disclosure related to a potential a tax assessment related to CDI.

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Note 11 – Comprehensive Income

The components of total comprehensive income for the three months ended March 31, 2009 and 2008 were as follows (in thousands):

		Three Months Ended
		March 31,
		2009			2008

Net income, including noncontrolling interests	$	112,755		$	74,202
Other comprehensive income (loss), net of tax
Foreign currency translation gain (loss)		(3,619	)		807
Unrealized gain on hedges, net		(4,464	)		(2,447	)
Total comprehensive income		104,672			72,562
Less: Other comprehensive income applicable to noncontrolling interest		(5,546	)		(237	)
Total comprehensive income applicable to Helix	$	99,126		$	72,325

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

	March 31,			December 31,
	2009			2008

Cumulative foreign currency translation adjustment	$	(46,481	)	$	(42,874	)
Unrealized gain on hedges, net		4,709			9,178
Accumulated other comprehensive loss	$	(41,772	)	$	(33,696	)

Note 12 – Earnings Per Share

On January 1, 2009, we adopted FSP No. EITF 03-06-1, “Determining Whether Instruments Granted in Share Based Payment Transactions Are Participating Securities.” We have shares of restricted stock issued and outstanding, some of which remain subject to certain vesting requirements. Holders of such shares of unvested restricted stock are entitled to the same liquidation and dividend rights as the holders of our outstanding common stock and are thus considered participating securities. Under FSP 03-06-1, the undistributed earnings for each period are allocated based on the contractual participation rights of both the common shareholders and holders of any participating securities as if earnings for the respective periods had been distributed. Because both the liquidation and dividend rights are identical, the undistributed earnings are allocated on a proportionate basis. Under FSP 03-06-1, we are required to compute EPS amounts under the two class method. We have revised the prior periods EPS amounts to reflect the current year adoption of FSP 03-06-1 (see table below).

Basic earnings per share ("EPS") is computed by dividing the net income available to common shareholders by the weighted average shares of outstanding common stock. The calculation of diluted EPS is similar to basic EPS, except that the denominator includes dilutive common stock equivalents and the income included in the numerator excludes the effects of the impact of dilutive common stock equivalents, if any. The computation of basic and diluted EPS amounts for the three months ended March 31, 2009 and 2008 are as follows (in thousands):

	Three Months Ended				Three Months Ended
	March 31, 2009				March 31, 2008
	Income			Shares	Income			Shares
Basic:
Net income applicable to common shareholders	$	53,450			$	73,084
Less: Undistributed net income allocable to participating securities		(884	)			(1,006	)
Undistributed net income applicable to common shareholders		52,566				72,078
(Income) loss from discontinued operations		2,554				(559	)
Income per common share – continuing operations	$	55,120		95,052	$	71,519		90,413

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		Three Months Ended March 31, 2009				Three Months Ended March 31, 2008
		Three Months Ended March 31, 2009				Three Months Ended March 31, 2008
		Income		Shares		Income	Shares
Diluted:
Net income per common share – continuing operations – Basic	$	55,120		95,052	$	71,519	90,413
Effect of dilutive securities:
Stock options		─		─		─	336
Undistributed earnings reallocated to participating securities		89		─		49	─
Convertible Senior Notes		─		─		─	706
Convertible preferred stock		313		10,811		881	3,631
Income per common share ─ continuing operations		55,522				72,449
Income (loss) per common share ─ discontinued operations		(2,554	)			559
Net income (loss) per common share	$	52,968		105,863	$	73,008	95,086

There were no dilutive stock options in the three months ended March 31, 2009 as the option strike price was below the average market price for the period ($5.22 per share). The diluted earnings per share amount included the $0.3 million and $0.9 million of dividends and related costs associated with the assumed conversion of the convertible preferred stock for the three months ended March 31, 2009 and 2008, respectively. The cumulative $53.4 million of beneficial conversion charges that were realized and recorded during the first quarter of 2009 following the transaction affecting our convertible preferred stock (Note 5) are not included as an addback to adjust earnings applicable to common stock for our diluted earnings per share calculation.

The following table compares EPS as originally reported and EPS under the two-class method, pursuant to FSP EITF 03-6-1, to quantify the per common share impact of the new standard on total net income applicable to Helix common shareholders’ for the three months ended March 31, 2008.

	Three Months Ended
	March 31, 2008

Basic, as previously reported	$	0.82
Basic, impact of adoption of APB 14-1		(0.01	)
Basic, restated for adoption of APB 14-1		0.81
Impact of FSP EITF 03-06-1 on basic EPS		0.01
Basic, under FSP EITF 03-06-1		0.80

Diluted, as previously reported		0.79
Diluted, impact of adoption of APB 14-1		(0.01	)
Diluted, restated for adoption of APB 14-1		0.78
Impact of FSP EITF 03-06-1 on diluted EPS		0.01
Diluted, under FSP EITF 03-06-1	$	0.77

Note 13 – Stock-Based Compensation Plans

We have two stock-based compensation plans: the 1995 Long-Term Incentive Plan, as amended (the “1995 Incentive Plan”) and the 2005 Long-Term Incentive Plan, as amended (the “2005 Incentive Plan”) .. In addition, CDI has a stock-based compensation plan, the 2006 Long-Term Incentive Plan (the “CDI Incentive Plan”) and an Employee Stock Purchase Plan (the “CDI ESPP”) available only to the employees of CDI and its subsidiaries. As of March 31, 2009, there were approximately 1.8 million shares available for grant under our 2005 Incentive Plan.

During the first three months ended March 31, 2009, we made the following restricted share or restricted stock unit grants to certain key executives, selected management employees and non-employee members of the board of directors under the 2005 incentive plan:

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Date of Grant	Type	Shares		Market Value Per Share	Vesting Period

January 2, 2009	(1)	343,368	$	7.24	20% per year over five years
January 2, 2009	(2)	26,506		7.24	20% per year over five years
January 2, 2009	(1)	10,617		7.24	100% on January 2, 2011
February 26, 2009	(1)	141,975		2.70	20% per year over five years

(1)	Restricted shares

(2)	Restricted stock units

There were no stock option grants in the three months ended March 31, 2009 and 2008.

Compensation cost is recognized over the respective vesting periods on a straight-line basis. For the three months ended March 31, 2009, $0.1 million was recognized as compensation expense related to stock options compared to $0.5 million for the same period last year, including $0.3 million associated with the acceleration of unvested options per the separation agreement between the Company and our former Chief Executive Officer, Martin Ferron. For the three months ended March 31, 2009, $4.0 million was recognized as compensation expense related to restricted shares, including $1.7 million related to CDI and its compensation plans, as compared with $6.9 million during the three months ended March 31, 2008, which included $3.1 million associated with the accelerated vesting of restricted shares per the separation agreement between the Company and our former Chief Executive Officer, Martin Ferron.

Note 14 – Business Segment Information (in thousands)

Our operations are conducted through the following lines of business: contracting services and oil and gas operations. We have disaggregated our contracting services operations into three reportable segments in accordance with SFAS No. 131: Contracting Services, Shelf Contracting and Production Facilities. As a result, our reportable segments consist of the following: Contracting Services, Shelf Contracting, Production Facilities and Oil and Gas. Contracting Services operations include subsea construction, well operations, robotics and drilling. Shelf Contracting operations consist of CDI, which include all its assets deployed primarily for diving-related activities and shallow water construction. All material intercompany transactions between the segments have been eliminated.

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

		Three Months Ended
		March 31,
		2009			2008

Revenues ─
Contracting Services	$	230,855		$	174,718
Shelf Contracting		207,053			144,571
Oil and Gas		160,181			171,051
Intercompany elimination		(27,114	)		(48,571	)
Total	$	570,975		$	441,769

Income from operations ─
Contracting Services	$	29,229		$	20,181
Shelf Contracting		20,932			7,548
Production Facilities equity investments(1)		(134	)		(138	)
Oil and Gas		145,183			109,917
Intercompany elimination		(290	)		(3,980	)
Total	$	194,920		$	133,528

Equity in earnings of equity investments	$	7,503		$	10,816

(1)	Includes selling and administrative expense of Production Facilities incurred by us.

(2)	Includes $73.5 million of disputed accrued royalty payments that we reversed in first quarter of 2009 following a favorable court ruling (Note 6).

	March 31, 2009		December 31, 2008

Identifiable Assets ─
Contracting Services	$	1,521,858	$	1,572,618
Shelf Contracting		1,331,359		1,309,608
Production Facilities		484,375		457,197
Oil and Gas		1,707,943		1,708,428
Net assets of discontinued operations		17,153		19,215
Total	$	5,062,688	$	5,067,066

Intercompany segment revenues during the three months ended March 31, 2009 and 2008 were as follows:

		Three Months Ended
		March 31,
		2009		2008

Contracting Services	$	23,903	$	42,220
Shelf Contracting		3,211		6,351
Total	$	27,114	$	48,571

Intercompany segment profits during the three months ended March 31, 2009 and 2008 were as follows:

		Three Months Ended
		March 31,
		2009			2008

Contracting Services	$	(104	)	$	2,863
Shelf Contracting		394			1,117
Total	$	290		$	3,980

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Note 15 – Related Party Transactions

In April 2000, we acquired a 20% working interest in Gunnison, a Deepwater Gulf of Mexico prospect of Kerr-McGee. Financing for the exploratory costs of approximately $20 million was provided by an investment partnership (OKCD Investments, Ltd. or “OKCD”), the investors of which include current and former Helix senior management, in exchange for a revenue interest that is an overriding royalty interest of 25% of Helix’s 20% working interest. Our Chief Executive Officer, Owen Kratz, through Class A limited partnership interests in OKCD, personally owns approximately 75% of the partnership. In 2000, OKCD also awarded Class B limited partnership interests to key Helix employees. Production began in December 2003. Payments to OKCD from us totaled $2.7 million and $5.5 million in the three months ended March 31, 2009 and 2008, respectively.

Note 16 – Commitments and Contingencies

Commitments

We are converting the Caesar (acquired in January 2006 for $27.5 million in cash) into a deepwater pipelay vessel. Total conversion costs are estimated to range between $210 million and $230 million, of which approximately $163 million had been incurred, with an additional $6.8 million committed, at March 31, 2009. The Caesar is expected to join our fleet in the second half of 2009.

We are also constructing the Well Enhancer, a multi-service dynamically positioned dive support/well intervention vessel that will be capable of working in the North Sea and West of Shetlands to support our expected growth in that region. Total construction cost for the Well Enhancer is expected to range between $200 million to $220 million. We expect the Well Enhancer to join our fleet early in the third quarter of 2009. At March 31, 2009, we had incurred approximately $172 million, with an additional $23.4 million committed to this project.

Further, we, along with Kommandor Rømø, a Danish corporation, formed Kommandor LLC, a joint venture, to convert a ferry vessel into a floating production unit to be named the Helix Producer I. The total cost of the ferry and the conversion is estimated to range between $160 million and $170 million. We have provided $93.6 million in construction financing through March 31, 2009 to the joint venture on terms that would equal an arms length financing transaction, and Kommandor Rømø has provided $5 million on the same terms.

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

Upon completion of the initial conversion, which occurred in April 2009, we are chartering the Helix Producer I from Kommandor LLC, and plan to install, at 100% our cost, processing facilities and a disconnectable fluid transfer system on the Helix Producer I for use on our Phoenix oil and gas field. The cost of these additional facilities is estimated to range between $180 million and $190 million and the work is expected to be completed in early 2010. As of March 31, 2009, approximately $218 million of costs related to the purchase of the Helix Producer I ($20 million), conversion of the Helix Producer I and construction of the additional facilities had been incurred, with an additional $3.2 million committed. The total estimated cost of the vessel, initial conversion and the additional facilities will range approximately between $340 million and $360 million. Kommandor LLC qualified as a variable interest entity under FIN 46(R). We determined that we were the primary beneficiary of Kommandor LLC and have consolidated its financial results in the accompanying consolidated financial statements. The operating results of Kommandor LLC are included within our Production Facilities segment. Kommandor LLC was a development stage enterprise since its formation in October 2006 until the completion of its initial conversion, which occurred in April 2009. Kommandor LLC is no longer a development stage enterprise.

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In addition, as of March 31, 2009, we have also committed approximately $12.6 million in additional capital expenditures for exploration, development, and abandonment costs related to our oil and gas properties.

Contingencies

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

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

A number of our longer term pipelay contracts have been adversely affected by delays in the delivery of the Caesar. We believe two of our contracts qualify as loss contracts as defined under SOP 81-1 “Accounting for Performance of Construction-Type and Certain Production-Type Contracts”. Accordingly, we have estimated the future shortfall between our anticipated future revenues versus future costs. For one contract expected to be completed in May 2009, our estimated loss at December 31, 2008 was estimated to be approximately $0.8 million. There was no additional loss on the contract in the first quarter of 2009. Under a second contract, which was terminated, we have a potential future liability of up to $25 million with our estimated future loss under this contract totaling $9.0 million, which was accrued for as of December 31, 2008. We have prepaid $7.2 million of such potential damages related to this terminated contact. If the potential damages exceed $7.2 million we will be required to pay additional funds but to the extent they are less that $7.2 million we would be entitled to cash refund from the contracting party. Although no new losses were identified with this contract in the first quarter of 2009, we will continue to monitor our exposure under this contract over the remainder of 2009.

In March 2009, we were notified of a third party’s intention to terminate an international construction contract under a claimed breach of that contract by one of our subsidiaries. Under the terms of the contract, our potential liability is generally capped for actual damages at approximately $27 million Australian dollars (“AUS”) (approximately $18.7 million US dollars at March 31, 2009) and for liquidated damages at approximately $5 million AUS (approximately $3.5 million US dollars at March 31, 2009); however, as there are substantial defenses to this claimed breach, we cannot at this time quantify our exposure, if any, under the contract. Over the remainder of 2009, we will continue to assess our potential exposure to damages under this contract as the circumstances warrant

See Note 6 for information updating the litigation involving certain disputed royalty payments, which were recognized as oil and gas revenues in the first quarter of 2009.

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Note 17 – Derivative Instruments and Hedging Activities

We are currently exposed to market risk in three major areas: commodity prices, interest rates and foreign currency exchange. Our risk management activities involve the use of derivative financial instruments to hedge the impact of market price risk exposures primarily related to our oil and gas production, variable interest rate exposure and foreign exchange currency fluctuations. All derivatives are reflected in our balance sheet at fair value unless otherwise noted, and do not contain credit-risk related or other contingent features that could cause accelerated payments when our derivative liabilities are in net liability positions.

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

We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives, strategies for undertaking various hedge transactions and the methods for assessing and testing correlation and hedge ineffectiveness. All hedging instruments are linked to the hedged asset, liability, firm commitment or forecasted transaction. We also assess, both at the inception of the hedge and on an on-going basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows of the hedged items. We discontinue hedge accounting if we determine that a derivative is no longer highly effective as a hedge, or it is probable that a hedged transaction will not occur. If hedge accounting is discontinued, deferred gains or losses on the hedging instruments are recognized in earnings immediately if it is probable the forecasted transaction will not occur. If the forecasted transaction continues to be probable of occurring, any deferred gains or losses in accumulated other comprehensive income are amortized to earnings over the remaining period of the original forecasted transaction.

Commodity Price Risks

We manage commodity price risks through various financial costless collars and swap instruments and forward sales contracts that require physical delivery. We utilize these instruments to stabilize cash flows relating to a portion of our expected oil and gas production. Our costless collars and swap contracts were designated as hedges and qualified for hedge accounting. However, due to disruptions in our production as a result of damages caused by the hurricanes in third quarter 2008, most of them no longer qualified for hedge accounting at March 31, 2009. Our forward sales contracts were not within the scope of SFAS No. 133 as they qualified for the normal purchases and sales scope exception. However, due to disruptions in our production as a result of damages caused by the hurricanes, as mentioned above, they no longer qualified for the scope exception. As a result, future changes in the fair value of these instruments are now recorded through earnings as a component of our income from operations in the period the changes occur.

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

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As of March 31, 2009, we have the following volumes under derivatives and forward sales contracts related to our oil and gas producing activities totaling 1,547 MBbl of oil and 31,601 Mmcf of natural gas:

Production Period	Instrument Type	Average Monthly Volumes	Weighted Average Price
Crude Oil:			(per barrel)
April 2009 — June 2009	Collar(1)	65.7 MBbl	$	75.00 — $89.55
April 2009 — December 2009	Forward Sales(2)	150 MBbl	$	71.79

Natural Gas:			(per Mcf)
April 2009 — December 2009	Collar(3)	947 Mmcf	$	7.0