SEC Filing | Helix Energy Solutions Group, Inc.

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form8k616-09.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): June 16, 2009

Helix Energy Solutions Group, Inc.

(Exact name of registrant as specified in its charter)

Minnesota (State or other jurisdiction of incorporation)	001-32936 (Commission File Number)		95-3409686 (IRS Employer Identification No.)
400 North Sam Houston Parkway East, Suite 400 Houston, Texas (Address of principal executive offices)		281-618-0400 (Registrant’s telephone number, including area code)	77060 (Zip Code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

|_| Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

|_| Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

|_| Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

|_| Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 8.01 Other Events.

Helix Energy Solutions Group, Inc. (“Helix” or the “Company”) is filing this Current Report on Form 8-K to reflect certain required accounting adjustments following the implementation of new accounting standards effective January 1, 2009 as disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008 (the “2008 Form 10-K”) filed on March 2, 2009. Except for the effect of the Company’s sale of its reservoir and well technology services business, Helix Energy Limited and its subsidiary, Helix RDS Limited, which occurred in late April 2009 and the Company’s reduction of its investment in Cal Dive International Inc., which occurred in June 2009, this Current Report on Form 8-K and the Exhibits hereto do not reflect any events occurring after March 2, 2009, or update or modify the disclosures in the 2008 Form 10-K. This Current Report on Form 8-K should be read in conjunction with the 2008 Form 10-K and the Company’s filings made with the Securities and Exchange Commission subsequent to the filing of the 2008 Form 10-K, including the Company’s filing of the Quarterly Report on Form 10-Q for the three month period ended March 31, 2009 that was filed on May 11, 2009 (“First-Quarter 2009 Form 10-Q”).

As previously disclosed in the Company’s 2008 Form 10-K, in May 2008, the FASB issued FASB Staff Position (“FSP”) APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion” (Including Partial Cash Settlement) (“FSP APB 14-1”). The FSP requires the proceeds from the issuance of convertible debt instruments be allocated between a liability component (issued at a discount) and an equity component. The resulting debt discount would be amortized as additional non-cash interest expense over the period the convertible debt is expected to be outstanding. The Company adopted FSP APB 14-1 on January 1, 2009 and early adoption was not permitted. FSP APB 14-1 requires retrospective application to all periods reported (with the cumulative effect of the change reported in retained earnings as of the beginning of the first period presented). The adoption of FSP APB 14-1 affects the accounting treatment for our Convertible Senior Notes issued in 2005 and due in 2025. The retrospective application of FSP APB 14-1 affected the years 2005 through 2008.

Also as previously disclosed in the Company’s 2008 Form 10-K, in June 2008, the FASB issued FSP Emerging Issues Task Force 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”). This FSP requires unvested share-based payment awards containing non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) to be included in the computation of basic earnings per share (“EPS”) according to the two-class method. The Company adopted FSP EITF 03-6-1 on January 1, 2009 and early adoption was not permitted. FSP EITF 03-06-1 requires all prior-period EPS data presented to be adjusted retrospectively (including interim financial statements, summaries of earnings, and selected financial data) to conform to the provisions of FSP EITF 03-06-1.

On January 1, 2009, the Company adopted Statement No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB 51” (“SFAS No. 160”), which was issued by the FASB in December 2007. 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. SFAS No. 160 was required to be adopted prospectively, except the following provisions must be adopted retrospectively:

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

2.	Recast consolidated net income to include net income attributable to both 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.”

Finally, as disclosed in the Company’s First-Quarter 2009 Form 10-Q, in April 2009, the Company sold its reservoir and well technology services business, Helix Energy Limited and its subsidiary, Helix RDS Limited, for $25 million. As a result of this sale, the accompanying financial statements in this Current Report on Form 8-K have been revised to reflect the operating results and financial position of Helix Energy Limited as discontinued operations for all periods presented. Helix Energy Limited was previously a component of the Company’s Contracting Services segment. Also as previously disclosed in the Company’s Current Report on Form 8-K dated June 10, 2009, the Company completed an underwritten secondary public offering of 20 million shares of Cal Dive International, Inc. (“Cal Dive”) common stock held by the Company. The underwriters also have a thirty-day option to sell up to an additional 3 million shares of Cal Dive common stock held by the Company to cover over-allotments, if any. The Company also sold Cal Dive $14 million of additional shares of Cal Dive common stock at $8.50 per share, the sales price the common stock was sold pursuant to the terms of the secondary offering. The Company will use the net proceeds from these transactions for general corporate purposes. The Company currently owns 26,294,964 shares of Cal Dive common stock representing approximately 28% of Cal Dive’s issued and outstanding shares of common stock. For additional information regarding these common stock sales transactions see Exhibit 99.2 “Subsequent Events” and Exhibit 99.3 - Note 25.

The Company has adjusted in Exhibits 99.1, 99.2 and 99.3 to this Current Report on Form 8-K the following information contained in its 2008 Form 10-K to reflect (1) the Company’s retrospective application of FSP APB 14-1, (2) the Company’s retrospective application of FSP EITF 03-06-1, (3) the Company’s retrospective application of SFAS No. 160, and (4) the Company’s presentation of the financial results and position of Helix Energy Limited as discontinued operations:

·	Item 6. Selected Financial Data

·	Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

·	Item 8. Financial Statements and Supplementary Data

Item 9.01 Financial Statements and Exhibits.

Number Description

---------- --------------

23.1

Consent of Ernst & Young LLP

23.2

Consent of Huddleston & Co., Inc.

99.1

Item 6. Selected Financial Data (adjusted to reflect the retrospective application of FSP APB 14-1, FSP EITF 03-06-1, SFAS No. 160 and presentation of results and financial position of Helix Energy Limited as discontinued operations).

99.2

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (adjusted to reflect the retrospective application of FSP APB 14-1, FSP EITF 03-06-1, SFAS No. 160 and presentation of the results and financial position of Helix Energy Limited as discontinued operations).

99.3

Item 8. Financial Statements and Supplementary Data (adjusted to reflect the retrospective application of FSP APB 14-1, SFAS No. 160 and FSP EITF 03-06-1 and presentation of the results and financial position of Helix Energy Limited as discontinued operations).

SIGNATURE

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 hereunto duly authorized.

Date: June 16, 2009

HELIX ENERGY SOLUTIONS GROUP, INC.

By: /s/ Anthony Tripodo

Anthony Tripodo

Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

Index to Exhibits

Exhibit No. Description

23.1

Consent of Ernst & Young LLP

23.2

Consent of Huddleston & Co., Inc.

99.1

Item 6. Selected Financial Data (adjusted to reflect the retrospective application of FSP APB 14-1,FSP EITF 3-06-1 and SFAS No. 160, and to present the results and financial position of Helix RDS Limited as discontinued operations).

99.2

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (adjusted to reflect the retrospective application of FSP APB 14-1, FSP EITF 03-06-1, SFAS No. 160 and to present the results and financial position of Helix RDS Limited as discontinued operations).

99.3

Item 8. Financial Statements and Supplementary Data (adjusted to reflect the retrospective application of FSP APB 14-1, FSP EITF 03-06-1, and SFAS No. 160, and to present the results and financial position of Helix RDS Limited as discontinued operations).

exhibit23-1.htm

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the Registration Statement Forms S-3 (Nos. 333-157785, 333-103451 and 333-125276) and in the related Prospectuses and Forms S-8 (Nos. 333-126248, 333-58817, 333-50289 and 333-50205) of Helix Energy Solutions Group, Inc. of our report dated March 2, 2009 (except for Notes 2 and 25, as to which the date is June 12, 2009), with respect to the consolidated financial statements of Helix Energy Solutions Group, Inc. and subsidiaries for the year ended December 31, 2008, included in the Current Report (Form 8-K) of Helix Energy Solutions Group, Inc. dated June 16, 2009, filed with the Securities and Exchange Commission.

/s/ Ernst & Young LLP

Houston, Texas

June 12, 2009

exhibit23-2.htm

Exhibit 23.2

[Letterhead of Huddleston & Co., Inc.]

June 15, 2009

Helix Energy Solutions Group, Inc.

400 North Sam Houston Parkway East

Suite 400

Houston, TX 77060


		Re:		Helix Energy Solutions Group, Inc.
				Securities and Exchange Commission
				Form 8-K
				Consent Letter

Gentlemen:

The firm of Huddleston & Co., Inc. consents to the naming of it as experts and to the incorporation by reference of its report letter dated February 5, 2009 concerning the proved reserves as of January 1, 2009 attributable to Energy Resource Technology GOM, Inc. in the Current Report of Helix Energy Solutions Group, Inc. on Form 8-K to be filed with the Securities and Exchange Commission. Huddleston & Co., Inc. has no interests in Helix Energy Solutions Group, Inc. or in any of its affiliated companies or subsidiaries and is not to receive any such interest as payment for such report and has no director, officer, or employee employed or otherwise connected with Helix Energy Solutions Group, Inc. We are not employed by Helix Energy Solutions Group, Inc. on a contingent basis.


Very truly yours, HUDDLESTON & CO., INC.
By:	/s/ PETER D. HUDDLESTON
	Name:	Peter D. Huddleston, P.E.
	Title:	President

exhibit99-1.htm

EXHIBIT 99.1

As further discussed in Note 2 to our consolidated financial statements (located in Exhibit 99.3 of this Current Report on Form 8-K), our consolidated financial statements for the periods presented have been adjusted (1) for the retrospective application of Financial Accounting Standards Board Staff Position No. APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement),” (FSP APB 14-1”) (2) for the retrospective application of Financial Staff Position Emerging Issue Task Force 03-06-1, “Determining Whether Instruments Granted in Share Based Payment Transactions Are Participating Securities,”(“EITF 03-06-1”) (3) for the retrospective application of Financial Accounting Standards Board Statement No. 160 “Noncontrolling Interests in Consolidated Financial Statements,” (“SFAS No. 160”) and (4) for the presentation of the operations and financial position of Helix Energy Limited and its subsidiary, Helix RDS Limited, as discontinued operations following its sale in April 2009. In this Current Report on Form 8-K, the retrospective application of SFAS No. 160 affected each of the years ended December 31, 2008, 2007 and 2006. The presentation of the operating results and financial position of Helix Energy Limited as discontinued operations affected the years ending December 31, 2008, 2007, 2006 and 2005. The retrospective application of FSP APB 14-1 affected the years ending December 31, 2008, 2007, 2006 and 2005; however, since we elected a Financial Statement Approach when adopting this standard only the years ended December 31, 2008, 2007 and 2006 are affected in the selected financials data table below with a cumulative effect of change in accounting treatment adjustment to the opening retained earnings on January 1, 2006. Every period presented in this Current Report on Form 8-K is affected by the retrospective application of EITF 03-06-1.

Item 6. Selected Financial Data.

The financial data presented below for each of the five years ended December 31, 2008, should be read in conjunction with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data included elsewhere in the Exhibits to this Current Report on Form 8-K and our 2008 Form 10-K.

		Year Ended December 31,
		2008			2007(1)			2006(2)			2005			2004

		(In thousands, except per share amounts)

Net revenues	$	2,114,074		$	1,732,420		$	1,328,136		$	793,860		$	543,392
Gross profit		372,191			505,907			503,478			281,737			171,912
Operating income (loss) (3)		(435,821	)		411,279			392,061			221,233			123,031
Equity in earnings of investments		31,854			19,573			17,927			13,425			7,927
Income (loss) from continuing operations		(580,245	)		343,639			338,816			152,199			82,659
Income (loss) from discontinued operations, net of taxes		(9,812	)		1,347			4,806			369			─
Net income (loss), including noncontrolling interests(2)		(590,057	)		344,986			343,622			152,568			82,659
Net income loss applicable to noncontrolling interests		(45,873	)		(29,288	)		(725	)		─			─
Net income (loss) applicable to Helix		(635,930	)		315,698			342,897			152,568			82,659
Preferred stock dividends and accretion		(3,192	)		(3,716	)		(3,358	)		(2,454	)		(2,743	)
Net income (loss) applicable to Helix common shareholders(4)		(639,122	)		311,982			339,539			150,114			79,916

Basic earnings (loss) per share of common stock (5):
Continuing operations	$	(6.94	)	$	3.40		$	3.92		$	1.93		$	1.05
Discontinued operations		(0.11	)		0.02			0.06			─
Net income per common share	$	(7.05	)	$	3.42		$	3.98		$	1.93		$	1.05

Diluted earnings (loss) per share of common stock (5):
Continuing operations	$	(6.94	)	$	3.25		$	3.74		$	1.85		$	1.03
Discontinued operations		(0.11	)		0.01			0.05			0.01			─
Net income per common share	$	(7.05	)	$	3.26		$	3.79		$	1.86		$	1.03

Weighted average common shares outstanding(5):
Basic		90,650			90,086			84,613			77,444			76,409
Diluted		90,650			95,647			89,714			81,965			79,062

(1)	Includes effect of the Horizon acquisition since December 11, 2007. See Item 8. Financial Statements and Supplementary Data “— Note 5 — Acquisition of Horizon Offshore, Inc.” for additional information.

(2)	Includes effect of the Remington acquisition since July 1, 2006. See Item 8. Financial Statements and Supplementary Data “— Note 4 — Acquisition of Remington Oil and Gas Corporation” for additional information.

(3)	Includes $896.9 million of impairment charges to reduce goodwill ($704.3 million) and certain oil and gas properties ($192.6 million) to their estimated fair value in fourth quarter of 2008. Total impairment charges totaled $920.0 million, $64.1 million, $0.8 million and $3.9 million for each of the years ending December 31, 2008, 2007, 2005 and 2004, respectively. There were no impairments in 2006. Also includes exploration expenses totaling $32.9 million ($27.1 million in fourth quarter of 2008) in 2008, $26.7 million in 2007, $43.1 million in 2006, $6.5 million in 2005. We did not have any exploration expense in 2004.

(4)	Includes the impact of gains on subsidiary equity transactions of $98.5 million and $96.5 million for the year ended December 31, 2007 and 2006, respectively. The gains were derived from the difference in the value of our investment in CDI immediately before and after its issuance of stock as related to its acquisition of Horizon and its initial public offering.

(5)	All earnings per share information reflects a two-for-one stock split effective as of the close of business on December 8, 2005.

		As of December 31,
		2008(1)			2007(2)		2006(3)			2005		2004
		(In thousands)
Working capital	$	287,225		$	48,290	$	310,524		$	120,388	$	112,799
Total assets		5,067,066	(1)		5,449,515		4,287,783			1,660,864		1,038,758
Long-term debt and capital leases (including current maturities)		2,027,226			1,758,186		1,431,235			447,171		148,560
Convertible preferred stock		55,000	(4)		55,000		55,000			55,000		55,000
Total controlling interest shareholders’ equity		1,191,149	(1)		1,829,951		1,556,314			629,300		485,292
Noncontrolling interests		322,627			263,926		59,802			─		─
Total equity		1,513,776			2,093,877		1,616,116	(5)		629,300		485,292

(1)	Includes the $907.6 million of impairment charges recorded in fourth quarter to reduce goodwill, intangible assets with indefinite lives and certain oil and gas properties to their estimated fair values. See Item 8. Financial Statements and Supplementary Data “— Note 2 — Summary of Significant Accounting Policies.” for additional information.

(2)	Includes effect of the Horizon acquisition since December 11, 2007. See Item 8. Financial Statements and Supplementary Data “— Note 5 — Acquisition of Horizon Offshore, Inc.” for additional information.

(3)	Includes effect of the Remington acquisition since July 1, 2006. See Item 8. Financial Statements and Supplementary Data “— Note 4— Acquisition of Remington Oil and Gas Corporation” for additional information.

(4)	The holder of the convertible preferred stock redeemed $30 million of our convertible preferred stock into 5.9 million shares of our common stock in January 2009. See Item 8. Financial Statements and Supplementary Data “— Note 13 — Convertible Preferred Stock” for additional information.

(5)	Total equity amount includes a January 1, 2006 $34.9 million cumulative effect on change of accounting principle to reflect the adoption of FSP ABP 14-1.

exhibit99-2.htm

EXHIBIT 99.2

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation

The following management’s discussion and analysis should be read in conjunction with our historical consolidated financial statements, located herein as Exhibit 99.3 to this Current Report on Form 8-K and in Item 8. “Financial Statements and Supplementary Data” of our 2008 Annual Report on Form 10-K (“2008 Form 10-K”). Any reference to Notes in the following management’s discussion and analysis refers to the Notes to Consolidated Financial Statements located in Exhibit 99.3 to this Current Report on Form 8-K and in Item 8. “Financial Statements and Supplementary Data” of our 2008 Form 10-K. The results of operations reported and summarized below are not necessarily indicative of future operating results. This discussion also contains forward-looking statements that reflect our current views with respect to future events and financial performance. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of certain factors, such as those set forth under Item 1A. “Risk Factors” which can be found in our 2008 Form 10-K.

As further discussed in Note 2, our consolidated financial statements for the periods presented have been adjusted (1) for the retrospective application of Financial Accounting Standards Board Staff Position No. APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement),” (2) for the retrospective application of Financial Staff Position Emerging Issue Task Force 03-06-1, “Determining Whether Instruments Granted in Share Based Payment Transactions Are Participating Securities,” (3) for the retrospective application of Financial Accounting Standards Board Statement No. 160 “Noncontrolling Interests in Consolidated Financial Statements,” and (4) for the presentation ot the consolidated operations and financial position of Helix Energy Limited as discontinued operations following its sale in April 2009. The financial information contained in the management discussion and analysis below reflects only the adjustments described in Note 2 and any modifications associated with the two subsequent events disclosed in “Subsequent Events” below and in Note 25 of Exhibit 99.3 of this Current Report on Form 8-K. Except as discussed in “Subsequent Events” below and Note 25, no other modifications or updates to these disclosures for events occurring after March 2, 2009, the date of the filing of our 2008 Form 10-K, have been made in this Current Report on Form 8-K.

Subsequent Events

On April 27, 2009, we sold our reservoir and well technology services business held by 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 sale of HEL and Helix RDS Limited, we have presented the results of Helix RDS as discontinued operations in the accompanying consolidated financial statements. HEL and Helix RDS were previously components of our Contracting Services segment.

On June 10, 2009, we completed an underwritten secondary public offering by selling 20 million shares of common stock of our majority owned subsidiary Cal Dive International, Inc (“Cal Dive,” “CDI,” or “DVR”) held by us (“the Offering”). Proceeds from the Offering totaled $161.9 million, net of underwriting fees. The Offering remains subject to a thirty day option period under which the underwriters may sell up to an additional 3 million shares of our Cal Dive shares of common stock at $8.50 per share, the price per share under the Offering. Separately, pursuant to a Stock Repurchase Agreement with Cal Dive, upon closing of the Offering, Cal Dive simultaneously repurchased from us approximately 1.6 million shares of its shares for net proceeds of $14 million at $8.50 per share. Following the closing of these two transactions, our ownership of Cal Dive common stock has been reduced to approximately 28%. We intend to use all the proceeds from the Offering and the Cal Dive stock repurchase for general corporate purposes.

Executive Summary

Our Business

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

Our Strategy

In December 2008, we announced the intention to focus and shape the future direction of the Company around our deepwater construction and well intervention services. We intend to achieve this strategic focus by seeking and evaluating strategic opportunities to:

1)	Divest all or a portion of our oil and gas assets;

2)	Divest our ownership interests in one or more of our production facilities; and

3)	Dispose of our remaining interest in our majority owned subsidiary, CDI.

We have engaged financial advisors to assist us in these efforts. The current economic and financial market conditions may affect the timing of any strategic dispositions by us and will require a degree of patience in order to execute any transactions. As a result, we are unable to be specific with respect to a timetable for any disposition, but we intend to aggressively focus on reducing debt levels through monetization of non-core assets and allocation of free cash flow in order to accelerate our strategic goals.

Consistent with this strategy, in December 2008 we announced the sale of our 17.5% non-operating working interest in the Bass Lite oil and gas field for $49 million in gross proceeds and in January 2009 we entered into a stock repurchase agreement with Cal Dive that resulted in us selling CDI approximately 13.6 million of CDI common shares held by us for $86 million in gross proceeds. This sale reduced our ownership interest in CDI to approximately 51%. We owned approximately 57% of CDI at December 31, 2008. Our ownership in CDI is currently approximately 28% (see “Subsequent Events” above and Note 25).

Demand for our contracting services operations is primarily influenced by the condition of the oil and gas industry, and in particular, the willingness of oil and gas companies to make capital expenditures for offshore exploration, drilling and production operations. Generally, spending for our contracting services fluctuates directly with the direction of oil and natural gas prices. The performance of our oil and gas operations is also largely dependent on the prevailing market prices for oil and natural gas, which are impacted by global economic conditions, hydrocarbon production and excess capacity, geopolitical issues, weather and several other factors.

Economic Outlook and Industry Influences

that resulted in us recording an aggregate of $896.9 million of impairment charges ($704.3 million for goodwill and indefinite-lived intangible assets and $192.6 million for oil and gas property impairments) (Note 2). The aggregate of all impairment charges for 2008 was $920.0 million. Further, our contracting services also may be negatively impacted by declining commodity prices as such may cause our customers, primarily oil and gas companies, to curtail or eliminate capital spending. At the moment, it is still too soon to predict to what extent current events may affect our overall activity levels in 2009 and beyond. The long-term fundamentals for our business remain generally favorable as the need for the continual replenishment of oil and gas production should drive the demand for our services. In addition, as our subsea construction operations primarily support capital projects with long lead times, that are less likely to be impacted by temporary economic downturns. We have hedged approximately 73% of our anticipated production for 2009 with a combination of forward sale and financial hedge contracts. The prices for these contracts are significantly higher than the prices for both crude oil and natural gas as of December 31, 2008 and as of the time of the filing of our 2008 Form 10-K on March 2, 2009. If the prices for crude oil and natural gas do not increase from current levels, and we have not entered into additional forward sale or financial hedge contracts to stabilize our cash flows, our oil and gas revenues may decrease in 2010 and beyond, perhaps significantly, absent offsetting increases in production amounts.

In light of the current credit crisis, in October 2008, we drew down an additional $175 million on our Revolving Credit Facility to ensure adequate and readily available liquidity to mitigate the cash flow impacts of production shut-in from Hurricanes Gustav and Ike, to fund ongoing capital projects and for hurricane remediation and repair costs. After this draw down, we had approximately $44 million (approximately $59 million as of February 27, 2009) of additional capacity remaining under our Revolving Credit Facility (including letters of credit). Further, we have reduced our planned capital expenditures for 2009 to include primarily the completion of major vessel construction projects and limited oil and gas expenditures. If we successfully implement the business plan outlined above, we believe we have sufficient liquidity without incurring additional indebtedness beyond the existing capacity under the Revolving Credit Facility.

Our business is substantially dependent upon the condition of the oil and natural gas industry and, in particular, the willingness of oil and natural gas companies to make capital expenditures for offshore exploration, drilling and production operations. The level of capital expenditures generally depends on the prevailing views of future oil and natural gas prices, which are influenced by numerous factors, including but not limited to:

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

Global economic conditions have deteriorated significantly over the past year with declines in the oil and gas market accelerating during the fourth quarter of 2008. Predicting the timing of any recovery is subjective and highly uncertain. Although we are currently in a recession, we believe that the long-term industry fundamentals are positive based on the following factors: (1) long term

increasing world demand for oil and natural gas; (2) peaking global production rates; (3) globalization of the natural gas market; (4) increasing number of mature and small reservoirs; (5) increasing ratio of contribution to global production from marginal fields; (6) increasing offshore activity, particularly in Deepwater; and (7) increasing number of subsea developments. Our strategy of combining contracting services operations and oil and gas operations allows us to focus on trends (4) through (7) in that we pursue long-term sustainable growth by applying specialized subsea services to the broad external offshore market but with a complementary focus on marginal fields and new reservoirs in which we have an equity stake.

Activity Summary

Over the last few years we continued to evolve our model by completing a variety of transactions and events that have had, and we believe will continue to have, significant impacts on our results of operations and financial condition. In 2005, we substantially increased the size of our Shelf Contracting fleet and deepwater pipelay fleet through the acquisition of assets from Torch Offshore, Inc. and Acergy US Inc. for a combined purchase price of $210.2 million. We also acquired a significant mature property package in the Gulf of Mexico OCS from Murphy Oil Corporation for $163.5 million cash and assumption of abandonment liability of $32 million. Finally, we established our Reservoir and Well Technology Services group through the acquisition of Helix Energy Limited for $32.7 million and the assumption of $7.5 million of liabilities. In April 2009, we sold our interests in Helix Energy Limited for $25 million (Notes 2 and 25). In 2006, we acquired Remington, an exploration, development and production company, for approximately $1.4 billion in cash and Helix common stock and the assumption of $358.4 million of liabilities. In March 2006, we changed our name from Cal Dive International, Inc. to Helix Energy Solutions Group, Inc., leaving the “Cal Dive” name to our Shelf Contracting subsidiary, and in December 2006 completed a carve-out initial public offering of Cal Dive, selling a 26.5% stake and receiving pre-tax net proceeds of $264.4 million and a pre-tax dividend of $200 million from additional borrowings under the Cal Dive revolving credit facility.

During 2006 we committed to four capital projects which will significantly expand our contracting services capabilities: conversion of the Caesar into a deepwater pipelay vessel, upgrading of the Q4000 to include drilling capability, conversion of a ferry vessel into a DP floating production unit (Helix Producer I) and construction of a multi-service DP dive support/well intervention vessel (Well Enhancer). During 2007, we successfully completed the drilling of exploratory wells in our Bushwood prospect located in Garden Banks Blocks 462, 463, 506 and 507 in the Gulf of Mexico. In January 2009, we announced an additional discovery at the Bushwood field (see “Oil and Gas Operations” in Item 2. “Properties” elsewhere in our 2008 Form 10-K). Initial sustained production from Bushwood commenced in January 2009.

In December 2007, Cal Dive acquired Horizon for approximately $650 million. CDI issued an aggregate of approximately 20.3 million shares of its common stock and paid approximately $300 million in cash in the merger. The cash portion of the merger consideration was paid from CDI’s cash on hand and from borrowings under its $675 million credit facility consisting of a $375 million senior secured term loan and a $300 million senior secured revolving credit facility, each of which is non-recourse to Helix. As a result of CDI’s equity issued, we recorded a $98.6 million gain, net of $53.1 million of taxes. The non-cash gain was calculated as the difference in the value of our investment in CDI immediately before and after CDI’s stock issuance.

Results of Operations

Our business consists of contracting services and oil and gas operations. We have disaggregated our contracting services operations into three reportable segments in accordance with SFAS No. 131 “Disclosures about Segments of an Enterprise and Related Information”. As a result, our reportable segments consist of the following: Contracting Services, Shelf Contracting, Production Facilities, and Oil and Gas. The Contracting Services segment includes operations such as deepwater pipelay, well operations, robotics and reservoir and well technology services. The Shelf Contracting segment represent the results and operations of Cal Dive, in which we owned 57.2% at December 31, 2008 and approximately 51% at the time of the filing of the 2008 Form 10-K. As discussed in “Subsequent Events” above and Note 25 in Exhibit 99.3 of this Current Report of Form 8-K, in June 10, 2009 we sold approximately 21.6 million of the Cal Dive shares of common stock owned by us for net proceeds of $175.9 million.. As a result of these transactions our ownership interest in Cal Dive currently approximates 28%. All material intercompany transactions between the segments have been eliminated in our consolidated financial statements, including our consolidated results of operations.

Comparison of Years Ended December 31, 2008 and 2007

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

		Year Ended December 31,						Increase/ (Decrease)
		2008			2007			Increase/ (Decrease)
Revenues (in thousands) –
Contracting Services	$	961,926		$	673,808		$	288,118
Shelf Contracting(1)		856,906			623,615			233,291
Oil and Gas		545,853			584,563			(38,710	)
Intercompany elimination		(250,611	)		(149,566	)		(101,045	)
	$	2,114,074		$	1,732,420		$	381,654

Gross profit (loss) (in thousands) –
Contracting Services	$	204,796		$	180,656		$	24,140
Shelf Contracting(1)		254,007			227,398			26,609
Oil and Gas(2)		(60,601	)		120,861			(181,462	)
Intercompany elimination		(26,011	)		(23,008	)		(3,003	)
	$	372,191		$	505,907		$	(133,716	)

Gross Margin –
Contracting Services		21	%		27	%		(6	)pts
Shelf Contracting(1)		30	%		36	%		(6	)pts
Oil and Gas (2)		(11)	%		21	%		(32	)pts

Total company		18	%		29	%		(11	)pts

Number of vessels(3)/ Utilization(4) –
Contracting Services:
Pipelay		9/92	%		6/79	%
Well operations		2/70	%		2/71	%
ROVs		46/73	%		39/78	%
Shelf Contracting		30/60	%		34/65	%

1)	Represented by our consolidated, majority owned subsidiary, CDI. At December 31, 2008 and 2007, our ownership interest in CDI was approximately 57.2% and 58.5%, respectively. Our interest in CDI decreased to approximately 51% in January 2009. Our ownership interest in CDI decreased to approximately 28% following the completion of the Offering and the repurchase of shares by CDI (see “Subsequent Events” above and Note 25).

2)	Includes asset impairment charges of oil and gas properties totaling $215.7 million ($192.6 million in fourth quarter of 2008). These impairment charges do not have any impact on current or future cash flow.

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

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

Intercompany segment revenues during the years ended December 31, 2008 and 2007 were as follows (in thousands):

		Year Ended December 31,				Increase/ (Decrease)
		2008		2007		Increase/ (Decrease)
Contracting Services	$	195,207	$	115,864	$	79,343
Shelf Contracting		55,404		33,702		21,702
	$	250,611	$	149,566	$	101,045

Intercompany segment profit (which only relates to intercompany capital projects) during the years ended December 31, 2008 and 2007 were as follows (in thousands):

		Year Ended December 31,				Increase/ (Decrease)
		2008		2007		Increase/ (Decrease)
Contracting Services	$	20,945	$	10,026	$	10,919
Shelf Contracting		5,066		12,982		(7,916	)
	$	26,011	$	23,008	$	3,003

As disclosed in Item 2 “Properties” of our 2008 Form 10-K, virtually all of our oil and gas operations are located in the U.S. Gulf of Mexico. We have one property located offshore of the United Kingdom, Camelot, that is capable of production but has been shut-in since the third quarter of 2008. Revenues associated with our U.K oil and gas operations totaled $3.9 million in 2008 and $2.7 million in 2007 on production volumes of 0.3 Bcfe and 0.6 Bcfe, respectively. We had no production from U.K properties in 2006. The total operating costs associated with our U.K oil and gas operations totaled $4.1 million in 2008, $7.3 million in 2007 and $4.9 million in 2006.

The following table details various financial and operational highlights related to our Oil and Gas segment for the periods presented (U.S. operations only as U.K. operations were immaterial for the periods presented, see above):

		Year Ended December 31,					Increase/ (Decrease)
		2008			2007		Increase/ (Decrease)

Oil and Gas information–
Oil production volume (MBbls)		2,751			3,723		(972	)
Oil sales revenue (in thousands)	$	253,656		$	251,955	$	1,701
Average oil sales price per Bbl (excluding hedges)	$	98.61		$	70.17	$	28.44
Average realized oil price per Bbl (including hedges)	$	92.22		$	67.68	$	24.54
Increase (decrease) in oil sales revenue due to:
Change in prices (in thousands)	$	91,360
Change in production volume (in thousands)		(89,659	)
Total increase in oil sales revenue (in thousands)	$	1,701

Gas production volume (MMcf)		30,490			42,163		(11,673	)
Gas sales revenue (in thousands)	$	283,269		$	324,282	$	(41,013	)
Average gas sales price per mcf (excluding hedges)	$	9.48		$	7.46	$	2.02
Average realized gas price per mcf (including hedges)	$	9.29		$	7.69	$	1.60
Increase (decrease) in gas sales revenue due to:
Change in prices (in thousands)	$	67,441
Change in production volume (in thousands)		(108,454	)
Total increase in gas sales revenue (in thousands)	$	(41,013	)

Total production (MMcfe)		46,993			64,500		(17,507	)
Price per Mcfe	$	11.43		$	8.93	$	2.50
Oil and Gas revenue information (in thousands)-
Oil and gas sales revenue	$	536,925		$	576,237	$	(39,312	)
Miscellaneous revenues(1)	$	5,058		$	5,667	$	(609	)

(1)	Miscellaneous revenues primarily relate to fees earned under our process handling agreements.

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

	Year Ended December 31,
	2008				2007
	Total		Per Mcfe		Total		Per Mcfe

Oil and gas operating expenses(1):
Direct operating expenses(2)	$	80,710	$	1.72	$	80,410	$	1.25
Workover		28,982		0.62		11,840		0.18
Transportation		5,095		0.11		4,560		0.07
Repairs and maintenance		20,731		0.44		12,191		0.19
Overhead and company labor		4,798		0.10		9,031		0.14
Total	$	140,316	$	2.99	$	118,032	$	1.83

Depletion and amortization	$	185,373	$	3.94	$	217,382	$	3.37
Abandonment		15,985		0.34		21,073		0.33
Accretion		12,771		0.27		10,701		0.17
Impairments (3)		215,675		4.59		64,072		0.99
Total	$	429,804	$	9.14	$	313,228	$	4.86

(1)	Excludes exploration expense of $32.9 million and $26.7 million for the years ended December 31, 2008 and 2007, respectively. Exploration expense is not a component of lease operating expense. Also excludes the impairment charge to goodwill of $704.3 million in fourth quarter of 2008.

(2)	Includes production taxes.

(3)	Includes impairment charges for certain oil and gas properties totaling $215.7 million ($192.6 million in fourth quarter of 2008).

Revenues. During the year ended December 31, 2008 our consolidated net revenues increased by 22% compared to 2007. Contracting Services gross revenues increased 43% over 2007 amounts primarily reflecting the following:

	•		the addition of two chartered subsea construction vessels as well as an overall increase in utilization of our subsea construction vessels;
	•		commencing performance of several longer term contracts;
	•		increases in the utilization and rates realized for our well operations vessels;
	•		strong performance by our robotics division driven by a higher number of ROVs in our fleet and additional services required following Hurricanes Gustav and Ike; and
	•		increased sales by our Shelf Contracting business (see below), resulting from its acquisition of Horizon in December 2007 and increased work following Hurricanes Gustav and Ike.

Our increases were partially offset by the following negative factors:

	•		an increase in the number of out-of-service days for the Q4000 associated with marine and drilling upgrades. The Q4000 was out of service for most of the first half of 2008;
	•		weather related downtime associated with Hurricanes Gustav and Ike.

Gross revenues for our Shelf Contracting business increased 37% in 2008 compared to 2007 primarily reflecting the revenue contribution of the Horizon assets that were acquired in December 2007 partially offset by lower vessel utilization related to winter seasonality and harsh weather conditions which continued into May 2008, and weather downtime associated with Hurricanes Gustav and Ike. Following the storm, our Shelf Contracting revenues benefitted from the increased scope of work associated with the storms including inspections, repairs and reclamation projects.

Oil and Gas revenues decreased 7% during 2008 as compared to the prior year. The decrease is primarily associated with the loss of production following the shut-in of many of our oil and gas properties following Hurricanes Gustav and Ike. Our production rates in 2008 were 27% lower than the same period last year; however our current net daily production is approximately 90% of pre-storm production volumes after adjusting for the sale of one major deepwater property in December 2008. The decrease in our revenues was partially offset by substantially higher oil and natural gas prices realized over the amounts received in 2007, which reflects near historical high prices for both oil and natural gas over the first half of 2008. Prices of both oil and natural gas decreased significantly during the second half of 2008, with price reductions accelerating in the fourth quarter of 2008.

Gross Profit. The Contracting Services gross profit increase was primarily attributable to improved contract pricing for the well operations and ROV divisions. These increases were partially offset by lower margins realized on certain longer term deepwater pipelay projects reflecting the delays in delivery of the Caesar and processing of certain change orders which prevented revenue recognition under the percentage-of-completion method (Note 2). We also recorded approximately $9.8 million of estimated losses on two contracts in which we believe the future revenue benefits will be exceeded by the estimated future costs to service the contracts (Note 2). The gross profit increase within Shelf Contracting was primarily attributable to the initial

deployment of Horizon’s assets that were acquired in December 2007 and additional work following Hurricanes Gustav and Ike, offset by increased depreciation associated with Horizon assets and weather-related delays over the first five months of 2008 and during Hurricanes Gustav and Ike. Our 2007 Shelf Contracting operations were adversely effected by an higher number of out-of-service days referred to above, lower vessel utilization as a result of seasonal weather in the fourth quarter 2007, and increased depreciation and deferred drydock amortization.

The decrease in the gross profit for our oil and gas operations in 2008 as compared to 2007 reflects the following key factors :

	•		impairment expense of approximately $215.7 million ($192.6 million recorded in the fourth quarter of 2008) related to our proved oil and gas properties primarily as a result of downward reserve revisions reflecting lower oil and natural gas prices, weak end of life well performance for some of our domestic properties, fields lost as a result of Hurricanes Gustav and Ike and the reassessment of the economics of some of our marginal fields in light of our announced business strategy to exit the oil and gas exploration and production business; we also recorded a $14.6 million asset impairment charge associated with the Devil’s Island Development well (Garden Banks Block 344) that was determined to be non-commercial in January 2008. Asset impairment expense in 2007 totaled $64.1 million, which included $20.9 million for the costs incurred on the Devil’s Island well through December 31, 2007.
	•		a decrease of $32.0 million in depletion expense in 2008 because of lower production which is primarily attributed to the effects Hurricanes Gustav and Ike had on our production during the latter part of the yea. This decrease was partially offset by higher rates resulting from a reduction in estimated proved reserves for a number of or producing fields at December 31, 2008.
	•		approximately $8.8 million of exploration expense (all in fourth quarter of 2008) compared to $9.0 million in 2007 related to reducing the carrying value of our unproved properties primarily due to management’s assessment that exploration activities for certain properties will not commence prior to the respective lease expiration dates;
	•		approximately $16.0 million of plug and abandonment overruns primarily related to properties damaged by the hurricanes, partially offset by insurance recoveries of $7.8 million; and
	•		approximately $18.8 million of dry hole exploration expense reflecting the conclusion that two exploratory wells previously classified as suspended wells (Note 7) no longer met the requirements to continue to be capitalized primarily as a result of the discontinuing of plans to progress the development of these wells in light of our announcement in December 2008 of our intention to pursue a sale of all or a portion of our oil and gas assets. In 2007, our dry hole expense totaled $10.3 million, of which $5.9 million was related to our South Marsh Island Block 123 #1 well.

Goodwill and other intangible asset impairments. In the fourth quarter of 2008 we recorded a $704.3 million of impairment charge to write off the remaining oil and gas goodwill following our annual assessment of goodwill, which took into account the significant decrease in our common stock price as well as the stock prices of our identified peers and the rapid reduction in oil and natural gas commodity prices. We also recorded an $8.3 million impairment charge in the fourth quarter of 2008 to write off the goodwill associated with our 2005 acquisition of Helix Energy Limited as well as a related $2.4 million impairment charge to write off its indefinite life asset (trademark). These amounts are reflects as a component of income (loss) from discontinued operations in the accompanying consolidated statement of operations as Helix Energy Limited was sold in April 2009 (see “Subsequent Events” and Note 25). We separately recorded $8.1 million of reductions of goodwill associated with dispositions of oil and gas properties in 2008, which are included as a component of the gain or loss on sale of assets, net as discussed below.

Gain on Sale of Assets, Net. The net gain on sale of assets increased by $23.1 million during 2008 as compared to 2007. In 2008 our oil and gas property sales included:

	•		$91.6 million gain related to the sale of a 30% working interest in the Bushwood discoveries (Garden Banks Blocks 463, 506 and 507) and East Cameron Blocks 371 and 381;
	•		$11.9 million loss related to the sale of all our onshore properties; included in the cost basis of our onshore properties was goodwill of $8.1 million; and
	•		$6.7 million loss related to the sale of our interest in the Bass Lite field in December 2008; there was no goodwill associated with this sale as all goodwill was previously written off. The sale of the remainder (approximately 10%) of our original 17.5% interest closed in January 2009 and will be reflected in our first-quarter 2009 results.

On September 30, 2007, we sold a 30% working interest in the Phoenix oilfield (Green Canyon Blocks 236/237), the Boris oilfield (Green Canyon Block 282) and the Little Burn oilfield (Green Canyon Block 238) to Sojitz GOM Deepwater, Inc. (“Sojitz”) for a cash payment of $51.2 million and recognized a gain of $40.4 million in 2007. We also recognized the following gains in 2007:

	•		$2.4 million related to the sale of a mobile offshore production unit;
	•		$1.6 million related to the sale of 50% interest in Camelot, which is located offshore of United Kingdom; and
	•		$3.9 million related to the sale of assets owned by CDI.

Selling and Administrative Expenses. Selling and administrative expenses of $177.2 million in 2008 were $32.2 million higher than the $145.0 million incurred in 2007. The increase was due primarily to higher overhead (primarily related to CDI’s Horizon acquisition) to support our growth. We also recognized approximately $7.4 million of expenses related to the separation agreements between the Company and two of its former executive officers (Note 22). Selling and administrative expenses as a percent of revenues were approximately 8.4% for both 2008 and 2007.

Equity in Earnings of Investments, Net of Impairment Charge. Equity in earnings of investments increased $12.3 million during 2008 as compared to 2007. Equity in earnings related to our 20% investment in Independence Hub increased $9.3 million as we reached mechanical completion in March 2007 and began receiving demand fees and tariffs as production began in the third quarter of 2007. In addition, equity in earnings of our 50% investment in Deepwater Gateway decreased by $3.5 million in 2008 as compared to 2007 due to downtime at the Marco Polo TLP following Hurricanes Gustav and Ike. These increases were offset by second quarter 2007 equity losses from CDI’s 40% investment in Offshore Technology Solutions Limited (“OTSL”) and a related non-cash asset impairment charge together totaling $11.8 million.

Net Interest Expense and Other. Net interest and other expense increased to $89.5 million in 2008 as compared to $67.0 million in the prior year. Gross interest expense of $137 million during 2008 was higher than the $107.8 million incurred in 2007 because of higher levels of indebtedness as a result of our Senior Unsecured Notes and CDI’s term loan, both of which closed in December 2007. Offsetting the increase in interest expense was $42.1 million of capitalized interest and $2.4 million of interest income in 2008, compared with $31.8 million of capitalized interest and $9.2 million of interest income in 2007. We expect interest expense to decrease in 2009 as a result of lower expected interest rates on our variable rate debt instruments. See Note 11 for detailed description of these notes. Our other income (expense) includes gains (losses) associated with transactions denominated in foreign currencies. Our foreign currency gains (losses) totaled ($10.0) million in 2008 and ($0.5) million in 2007.

Provision for Income Taxes. Income taxes for continuing operations decreased to $86.8 million in 2008 compared to $171.9 million in the prior year. This decrease is primarily due to lower profitability in 2008. The effective tax rate of (17.6)% is not representative because of the $704.3 million non-deductible goodwill and indefinite-lived intangible assets impairment charge as discussed above. Excluding the goodwill and other intangible asset impairments, the effective tax rate of 41.2% for 2008 was higher than the 33.3% effective tax rate for same period 2007 primarily reflecting the additional deferred tax expense recorded as a result of the increase in the equity earnings of CDI in excess of our tax basis. Further, the allocation of goodwill to the cost basis for the oil and gas properties sales prior to the fourth quarter of 2008 was not deductible for tax purposes. See Note 12 for additional information regarding income taxes.

Comparison of Years Ended December 31, 2007 and 2006

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

		Year Ended December 31,
		2007			2006			Increase/ (Decrease)
Revenues (in thousands) –
Contracting Services	$	673,808		$	446,458		$	227,350
Shelf Contracting(1)		623,615			509,917			113,698
Oil and Gas		584,563			429,607			154,956
Intercompany elimination		(149,566	)		(57,846	)		(91,720	)
	$	1,732,420		$	1,328,136		$	404,284

Gross profit (in thousands) –
Contracting Services	$	180,656		$	126,586		$	54,070
Shelf Contracting(1)		227,398			222,530			4,868
Oil and Gas		120,861			162,386			(41,525	)
Intercompany elimination		(23,008	)		(8,024	)		(14,984	)
	$	505,907		$	503,478		$	2,429

Gross Margin –
Contracting Services		27	%		28	%		(1	)pt
Shelf Contracting(1)		36	%		44	%		(8	)pts
Oil and Gas		21	%		38	%		(17	)pts

Total company		29	%		38	%		(9	)pts


Number of vessels(2)/ Utilization(3) –
Contracting Services:
Pipelay		6/79%			4/87%
Well operations		2/71%			2/81%
ROVs		39/78%			31/76%
Shelf Contracting		34/65%			25/84%

1)	Represented by our consolidated, majority owned subsidiary, CDI. At December 31, 2007 and 2006, our ownership interest in CDI was approximately 58.5% and 73.0%, respectively.

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

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

Intercompany segment revenues during the years ended December 31, 2007 and 2006 were as follows (in thousands):

		Year Ended December 31,				Increase/ (Decrease)
		2007		2006		Increase/ (Decrease)
Contracting Services	$	115,864	$	42,585	$	73,279
Shelf Contracting		33,702		15,261		18,441
	$	149,566	$	57,846	$	91,720

Intercompany segment profit (which only relates to intercompany capital projects) during the years ended December 31, 2007 and 2006 were as follows (in thousands):

		Year Ended December 31,				Increase/ (Decrease)
		2007		2006		Increase/ (Decrease)
Contracting Services	$	10,026	$	2,460	$	7,566
Shelf Contracting		12,982		5,564		7,418
	$	23,008	$	8,024	$	14,984

		Year Ended December 31,					Increase/ (Decrease)
		2007			2006		Increase/ (Decrease)

Oil and Gas information–
Oil production volume (MBbls)		3,723			3,400		323
Oil sales revenue (in thousands)	$	251,955		$	205,415	$	46,540
Average oil sales price per Bbl (excluding hedges)	$	70.17		$	61.08	$	9.09
Average realized oil price per Bbl (including hedges)	$	67.68		$	60.41	$	7.27
Increase in oil sales revenue due to:
Change in prices (in thousands)	$	24,699
Change in production volume (in thousands)		21,841
Total increase in oil sales revenue (in thousands)	$	46,540


Gas production volume (MMcf)		42,163			27,949		14,214
Gas sales revenue (in thousands)	$	324,282		$	219,674	$	104,608
Average gas sales price per mcf (excluding hedges)	$	7.46		$	7.46	$	─
Average realized gas price per mcf (including hedges)	$	7.69		$	7.86	$	(0.17	)
Increase (decrease) in gas sales revenue due to:
Change in prices (in thousands)	$	(4,718	)
Change in production volume (in thousands)		109,326
Total increase in gas sales revenue (in thousands)	$	104,608

Total production (MMcfe)		64,500			48,349		16,151
Price per Mcfe	$	8.93		$	8.79	$	0.14

Oil and Gas revenue information (in thousands)-
Oil and gas sales revenue	$	576,237		$	425,089	$	151,148
Miscellaneous revenues(1)	$	5,667		$	4,518	$	1,149

(1)	Miscellaneous revenues primarily relate to fees earned under our process handling agreements.

The following table highlights certain relevant expense items in total (in thousands) and on a cost per Mcfe of production basis:

	Year Ended December 31,
	2007				2006
	Total		Per Mcfe		Total		Per Mcfe

Oil and gas operating expenses(1):
Direct operating expenses(2)	$	80,410	$	1.25	$	50,930	$	1.05
Workover		11,840		0.18		11,462		0.24
Transportation		4,560		0.07		3,174		0.07
Repairs and maintenance		12,191		0.19		13,081		0.27
Overhead and company labor		9,031		0.14		10,492		0.22
Total	$	118,032	$	1.83	$	89,139	$	1.85

Depletion and amortization	$	217,382	$	3.37	$	126,350	$	2.61
Abandonment		21,073		0.33	─		─
Accretion		10,701		0.17		8,617		0.18
Impairments		64,072		0.99	─		─
Total	$	313,228	$	4.86	$	134,967	$	2.79

(1)	Excludes exploration expense of $26.7 million and $43.1 million for the years ended December 31, 2007 and 2006, respectively. Exploration expense is not a component of lease operating expense.

(2)	Includes production taxes.

Revenues. During the year ended December 31, 2007, our revenues increased by 30% as compared to 2006. Contracting Services revenues increased primarily due to improved contract pricing for the pipelay, well operations and ROV divisions. Shelf Contracting revenues increased primarily as a result of the initial deployment of certain assets we acquired through the Torch, Acergy and Fraser acquisitions that came into service subsequent to the first quarter of 2006 as well as the Horizon assets acquired in late 2007. These increases were partially offset by two vessels CDI did not operate (one owned and one chartered) in 2007 that were in operation in 2006 and an increased number of out-of-service days for regulatory drydock and vessel upgrades for certain vessels in our Shelf Contracting segment.

Oil and Gas revenues increased 36% during 2007 as compared to the prior year. The increase was primarily due to increases in oil and natural gas production. The production volume increase of 33% over 2006 was mainly attributable to properties acquired in connection with the Remington acquisition, which closed on July 1, 2006.

Gross Profit. The Contracting Services gross profit increase was primarily attributable to improved contract pricing for the pipelay, well operations and ROV divisions. The gross profit increase within Shelf Contracting was primarily attributable to increased gross profit derived from the initial deployment of certain assets we acquired subsequent to the first quarter 2006, offset by increased out-of-service days referred to above, lower vessel utilization as a result of seasonal weather in the fourth quarter 2007, and increased depreciation and deferred drydock amortization.

The Oil and Gas gross profit decrease in 2007 as compared to 2006 was primarily due to the following factors:

	•		impairment expenses totaling $64.1 million, which primarily reflected $59.4 million associated with property impairments related to downward reserve revisions and weak end of life well performance in some of our domestic properties and $9.6 million of increased future abandonment costs related to properties damaged by Katrina and Rita partially offset by estimated insurance recoveries of $4.9 million;
	•		an increase of $91.0 million in depletion expense in 2007 because of higher overall production based on a full year of activity from the Remington acquisition as compared to only half a year of impact in 2006 including approximately $12.5 million of increased fourth quarter 2007 depletion due to certain producing properties experiencing significant proved reserve declines;
	•		approximately $25.1 million of plug and abandonment overruns related to properties damaged by the hurricanes, partially offset by insurance recoveries of $4.0 million;
	•		approximately $9.9 million of impairment expense related to our unproved properties primarily due to management’s assessment that exploration activities for certain properties will not commence prior to the respective lease expiration dates;
	•		the gross profit decrease was partially offset by lower dry hole exploration expense in 2007 of $10.3 million, of which $5.9 million was related to our South Marsh Island 123 #1 well, as compared to $38.3 million dry hole expense in 2006 related to the Tulane prospect and two deep shelf wells commenced by Remington prior to the acquisition.

Gain on Sale of Assets, Net. Gain on sale of assets, net, increased by $47.6 million during 2007 as compared to 2006. On September 30, 2007, we sold a 30% working interest in the Phoenix oilfield (Green Canyon Blocks 236/237), the Boris oilfield (Green Canyon Block 282) and the Little Burn oilfield (Green Canyon Block 238) to Sojitz for a cash payment of $51.2 million and recognized a gain of $40.4 million in 2007. We also recognized the following gains in 2007:

	•		$2.4 million related to the sale of a mobile offshore production unit;
	•		$1.6 million related to the sale or 50% interest in Camelot; and
	•		$3.9 million related to the sale of assets owned by CDI.

Selling and Administrative Expenses. Selling and administrative expenses of $145.0 million in 2007 were $30.8 million higher than the $114.2 million incurred in 2006. The increase was due primarily to higher overhead to support our growth and increased incentive compensation accruals. Further, in June 2007, CDI recorded a $2.0 million charge for a cash settlement with the Department of Justice. Selling and administrative expenses as a percent of revenues were approximately 8.4% in 2007 and 8.6% in 2006.

Equity in Earnings of Investments, Net of Impairment Charge. Equity in earnings of investments increased by $1.6 million during 2007 as compared to 2006. Equity in earnings related to our 20% investment in Independence Hub increased $10.5 million as we reached mechanical completion in March 2007 and began receiving demand fees and tariffs as production began in the third quarter. In addition, equity in earnings of our 50% investment in Deepwater Gateway increased by $2.2 million in 2007 as compared to 2006 due to higher throughput at the Marco Polo TLP. These increases were offset by second quarter 2007 equity losses from CDI’s 40% investment in OTSL and a related non-cash asset impairment charge together totaling $11.8 million.

Gain on Subsidiary Equity Transaction. We recognized a non cash pre-tax gain of $151.7 million ($98.6 million net of taxes of $53.1 million) in 2007 as our share of CDI’s underlying equity increased as a result of CDI’s issuance of 20.3 million shares of its common stock to former Horizon stockholders in connection with CDI’s acquisition of Horizon, which reduced our ownership in CDI to 58.5%. The non-cash gain is derived from the difference in the

value of our investment in CDI immediately before and after the acquisition. In 2006, CDI received net proceeds of $264.4 million from the initial public offering of 22.2 million shares of its common stock. Together with CDI’s drawdown of its revolving credit facility, CDI paid pre-tax dividends of $464.4 million to us in December 2006. As a result of these transactions, we recorded a pre-tax gain of $223.1 million ($96.5 million net of taxes of $126.6 million) in 2006.

Net Interest Expense and Other. We reported net interest and other expense of $67.0 million in 2007 as compared to $41.6 million in the prior year. Gross interest expense of $107.8 million during 2007 was higher than the $58.8 million incurred in 2006 as a result of our Term Loan and Revolving Loans, which closed in July 2006, and CDI’s revolving credit facility, which closed in December 2006. Offsetting the increase in interest expense was $31.8 million of capitalized interest and $9.2 million of interest income in 2007, compared with $10.6 million of capitalized interest and $6.3 million of interest income in 2006.

Provision for Income Taxes. Income taxes from continuing operations decreased to $171.9 million in 2007 compared to $252.8 million in 2006. This variance includes a $126.6 million decrease of the income tax expense related to the CDI dividends paid to us in 2006, which was partially offset by increased profitability in 2007. The effective tax rate of 33.3% for 2007 was lower than the 42.7% effective tax rate for 2006 due primarily to the CDI dividends of $464.4 million received in December 2006.

Liquidity and Capital Resources

Overview

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

		2008		2007
Net working capital	$	287,225	$	48,290
Long-term debt(1)	$	1,933,686	$	1,683,340

(1)	Long-term debt does not include current maturities portion of the long-term debt as amount is included in net working capital.

The carrying amount of our debt, including current maturities as of December 31, 2008 and 2007 follow (amount in thousands):

		2008		2007
Term Loan (matures July 2013)	$	419,093	$	423,418
Revolving Credit Facility (matures July 2011)		349,500		18,000
Cal Dive Term Loan (matures December 2012)		315,000		375,000
Convertible Senior Notes (matures March 2025) (1)		265,184		257,799
Senior Unsecured Notes (matures January 2016)		550,000		550,000
MARAD Debt (matures August 2027)		123,449		127,463
Loan Notes(2)		5,000		6,506
Total	$	2,027,226	$	1,758,186

(1)	Net of the unamortized debt discount resulting from adoption of FSP 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.

(2)	Assumed to be current, represents the $5 million loan provided by Kommandor RØMØ to Kommandor LLC (Note 10).

		Year Ended December 31,
		2008			2007			2006
Net cash provided by (used in):
Operating activities	$	437,719		$	416,326		$	514,036
Investing activities	$	(557,974	)	$	(739,654	)	$	(1,379,930	)
Financing activities	$	256,216		$	206,445		$	978,260

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

We are closely monitoring the relatively recent and ongoing volatility and uncertainty in the financial markets and have intensified our internal focus on liquidity, planned spending and access to capital. Externally we have also been engaged with our clients and the lending institutions on our various debt facilities as our customers and lenders are going through similar exercises. While we believe at this stage it is premature to accurately predict to what extent these current events may affect our overall activity levels in 2009 and beyond, we do expect a significant decrease in activity as compared to 2008. To date, we have received no communication from our lenders that they are unable or unwilling to fund any commitments under our Revolving Credit Facility. Additionally, all participating banks party to our Revolving Credit Facilities have honored their commitments. We also have a reasonable basis for estimating our future cash flow supported by our contracting services backlog and the significant hedged portion of our estimated 2009 oil and gas production. We believe that internally generated cash flow and available borrowing capacity under our existing Revolving Credit Facility will be sufficient to fund our operations for 2009.

A continuing period of weak economic activity will make it increasingly difficult to comply with our covenants and other restrictions in agreements governing our debt. Our ability to comply with these covenants and other restrictions is affected by the current economic conditions and other events beyond our control. If we fail to comply with these covenants and other restrictions, it could lead to an event of default, the possible acceleration of our repayment of outstanding debt and the exercise of certain remedies by the lenders, including foreclosure on our pledged collateral. We cannot assure you that we would have access to the credit markets as needed to replace our existing debt and we could incur increased costs associated with any available replacement financing.

Some of the significant financings and corresponding uses were as follows:

	•		In January 2009, CDI borrowed $100 million under our revolving credit facility to repurchase 13.6 million shares of its common stock from us for $6.34 per share. The remaining funds will be used to fund CDI working capital requirements and other general corporate purposes. As of February 20, 2009, CDI had $415 million of debt, $67.3 million of cash on hand and $186.7 million of available under our credit facility.
	•		In July 2007, we purchased the remaining 42% of WOSEA for $10.1 million. We now own 100% of this company (see “Note 6 — Other Acquisitions” in Item 8. Financial Statements and Supplementary Data for a detailed discussion of WOSEA).
	•		In December 2007, we issued $550 million of 9.5% Senior Unsecured Notes due 2016 (“Senior Unsecured Notes”). Proceeds from the offering were used to repay outstanding indebtedness under our senior secured credit facilities. For additional information on the terms of the Senior Unsecured Notes, see “Note 11 — Long-term Debt” in Item 8. Financial Statements and Supplementary Data.

	•		Also in December 2007, CDI replaced its five-year $250 million revolving credit facility with a secured credit facility consisting of a $375 million term loan and a $300 million revolving credit facility. Proceeds from the CDI term loan were used to fund the cash portion of the Horizon acquisition. CDI expects to use the remaining capacity under the revolving credit facility for its working capital and other general corporate purposes. We do not have access to the unused portion of CDI’s revolving credit facility. See Note 11 for additional information regarding our long term debt.
	•		In July 2006, we borrowed $835 million in a term loan (“Term Loan”) and entered into a new $300 million revolving credit facility (Note 11). The proceeds of the Term Loan were used to fund the cash portion of the acquisition of Remington. We also issued approximately 13.0 million shares of our common stock to the Remington shareholders.
	•		In December 2006, we completed an IPO of our Shelf Contracting business segment (Cal Dive International, Inc.), selling 26.5% of that company and receiving pre-tax net proceeds of $264.4 million. We may sell additional shares of CDI common stock in the future. Proceeds from the offering were used for general corporate purposes, including the repayment of $71.0 million of borrowing under our Revolving Credit Facility (Note 3).
	•		In connection with the IPO, CDI Vessel Holdings LLC (“CDI Vessel”), a subsidiary of CDI, entered into a secured credit facility for up to $250 million in revolving loans under a five-year revolving credit facility. During December 2006, CDI Vessel borrowed $201 million under the revolving credit facility and distributed $200 million of those proceeds to us as a dividend. This revolving loan was replaced in December 2007 by the $300 million revolving credit facility described above.
	•		In October 2006, we initially invested $15 million for a 50% interest in Kommandor LLC, a Delaware limited liability company, to convert a ferry vessel into a dynamically-positioned minimal floating production system. We have consolidated the results of Kommandor LLC in accordance with FASB Interpretation No. 46(R), Consolidation of Variable Interest Entities (“FIN 46”). For additional information, see Note 10. We have named the vessel Helix Producer I.
	•		Also in October 2006, we acquired the original 58% interest in WOSEA for total consideration of approximately $12.7 million (including $180,000 of transaction costs), with approximately $9.1 million paid to existing shareholders and $3.4 million for subscription of new WOSEA shares (see Note 6 for a detailed discussion of WOSEA).
	•		In 2006, our Board of Directors also authorized us to discretionarily purchase up to $50 million of our common stock in the open market. In October and November 2006, we purchased approximately 1.7 million shares under this program for a weighted average price of $29.86 per share, or $50.0 million.

In accordance with our Senior Credit Facilities, Senior Unsecured Notes, the Convertible Senior Notes, the MARAD debt and Cal Dive’s credit facilities, we are required to comply with certain covenants and restrictions, including certain financial ratios such as collateral coverage, interest coverage, consolidated leverage, the maintenance of minimum net worth, working capital and debt-to-equity requirements. As of December 31, 2008, we were in compliance with these covenants. The Senior Credit Facilities and Senior Unsecured Notes also contain provisions that limit our ability to incur certain types of additional indebtedness. These provisions effectively prohibit us from incurring any additional secured indebtedness or indebtedness guaranteed by the Company. The Senior Credit Facilities do permit us to incur certain unsecured indebtedness, and also provide for our subsidiaries to incur project financing indebtedness (such as our MARAD loans) secured by the underlying asset, provided that the indebtedness is not guaranteed by us. Upon the occurrence of certain dispositions or the issuance or incurrence of certain types of indebtedness, we may be required to prepay a portion of the Term Loan equal to the amount of proceeds received from such occurrences. Such prepayments will be applied first to the Term Loan, and any excess will then be applied to the Revolving Loans.

As of December 31, 2008, we had $44.4 million ($59.4 million as of February 27, 2009) of available borrowing capacity under our Revolving Credit Facility, and CDI had $292.5 million of available borrowing capacity under its revolving credit facility. See Note 11 for additional information related to our long-term debts, including our obligations under capital commitments.

Working Capital

Net cash flows from operating activities increased $21.4 million in 2008 as compared to 2007 primarily reflecting significantly lower income taxes paid and increased gross profit from Contracting Services and Shelf Contracting businesses. These increases were partially offset by lower operating results for our Oil and Gas business reflecting the effects of Hurricanes Gustav and Ike had on its production during the third and fourth quarters of 2008 as well as our increased funding of our working capital requirements.

Net cash flow from operating activities decreased $97.7 million in 2007 as compared to 2006 primarily due to negative working capital changes in 2007. Compared to 2006, increased expenditures in other noncurrent assets, net, consisted of an additional $21.6 million in drydock expenses (net of amortization), $8.8 million for an equipment deposit and $14.6 million related to a non-current contract receivable for retainage. Working capital, net of cash, decreased approximately $145.5 million in 2007 when compared to 2006. Cash from operating activities was negatively impacted by higher income taxes paid in 2007 versus 2006 of approximately $146.9 million, of which $126.6 million was related to CDI’s initial public offering. These decreases were partially offset by increase in profitability, excluding the impact of non-cash related items, in 2007 as compared to 2006.

Investing Activities

Capital expenditures have consisted principally of the purchase or construction of DP vessels, acquisition of select businesses, improvements to existing vessels, acquisition of oil and gas properties and investments in our Production Facilities. Significant sources (uses) of cash associated with investing activities for the years ended December 31, 2008, 2008 and 2007 were as follows (in thousands):

		Year Ended December 31,
		2008			2007			2006
Capital expenditures:
Contracting services	$	(258,184	)	$	(286,362	)	$	(129,847	)
Shelf contracting		(83,108	)		(30,301	)		(38,086	)
Oil and gas		(404,308	)		(519,632	)		(282,318	)
Production facilities		(109,454	)		(106,086	)		(17,749	)
Acquisition of businesses, net of cash acquired:
Remington Oil and Gas Corporation(1)		─			─			(772,244	)
Horizon Offshore Inc. (2)		─			(137,431	)		─
Acergy US Inc. (3)		─			─			(78,174	)
Fraser Diving International Ltd. (3)		─			─			(21,954	)
WOSEA(4)		─			(10,067	)		(10,571	)
Kommandor LLC		─			─			(5,000	)
(Purchases) sale of short-term investments		─			285,395			(285,395	)
Investments in production facilities		(846	)		(17,459	)		(27,578	)
Distributions from equity investments, net(4)		11,586			6,679			─
Increase in restricted cash		(614	)		(1,112	)		(6,666	)
Proceeds from insurance		13,200			─			─
Proceeds from sale of subsidiary stock		─			─			264,401
Proceeds from sale of properties (5)		274,230			78,073			32,342
Other, net		─			(136	)		─
Net cash used in investing activities		(557,498	)		(738,439	)		(1,378,839	)
Net cash used in discontinued operations		(476	)		(1,215	)		(1,091	)
Net cash used in investing activities	$	(557,974	)	$	(739,654	)	$	(1,379,930	)


(1)	For additional information related to the Remington acquisition, see Note 4.

(2)	For additional information related to the Horizon acquisition, see Note 5.

(3)	For additional information related to these acquisitions, see Note 6.

(4)	Distributions from equity investments is net of undistributed equity earnings from our investments. Gross distributions from our equity investments are detailed in Note 9.

(5)	For additional information related to sales of properties, see Note 7.

Short-term Investments

As of December 31, 2006, we held approximately $285.4 million in municipal auction rate securities. We did not hold these types of securities at December 31, 2008 or 2007. These instruments were long-term variable rate bonds tied to short-term interest rates reset through a “Dutch Auction” process which occurred every 7 to 35 days and were classified as available-for-sale securities.

Restricted Cash

As of December 31, 2008 we had $35.4 million of restricted cash, included in other assets, net, in the accompanying consolidated balance sheet, all of which related to the escrow funds for decommissioning liabilities associated with the South Marsh Island Block 130 (“SMI 130”) acquisition in 2002. Under the purchase agreement for this property, we are 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 . We had fully escrowed the requirement as of December 31, 2008. We may use the restricted cash for decommissioning the related field.

Outlook

We anticipate capital expenditures in 2009 will range from $350 million to $400 million (of which $78 million is related to CDI). The estimates for these capital expenditures may increase or decrease based on various economic factors. However, we may reduce the level of our planned capital expenditures given a prolonged economic downturn and inability to execute sales transactions related to our non core business assets. We believe internally generated cash flow, cash from future sales of our non core business assets, and borrowings under our existing credit facilities will provide the capital necessary to fund our 2009 initiatives.

Contractual Obligations and Commercial Commitments

The following table summarizes our contractual cash obligations as of December 31, 2008 and the scheduled years in which the obligation are contractually due (in thousands):

		Total (1)		Less Than 1 year		1-3 Years		3-5 Years		More Than 5 Years

Convertible Senior Notes(2)	$	300,000	$	─	$	─	$	─	$	300,000
Senior Unsecured Notes		550,000		─		─		─		550,000
Term Loan		419,093		4,326		8,652		406,115		─
Revolving Loans		349,500		─		349,500		─		─
MARAD debt		123,449		4,214		9,069		9,997		100,169
CDI Term Loan		315,000		80,000		160,000		75,000		─
Loan note		5,000		5,000		─		─		─
Interest related to long-term debt(3)		693,364		101,093		178,169		158,881		255,221
Preferred stock dividends(4)		1,000		1,000		─		─		─
Drilling and development costs		106,300		16,800		89,500		─		─
Property and equipment(5)		47,941		47,941		─		─		─
Operating leases(6)		191,623		84,893		75,708		21,644		9,378
Total cash obligations	$	3,102,270	$	345,267	$	870,598	$	671,637	$	1,214,768

(1)	Excludes unsecured letters of credit outstanding at December 31, 2008 totaling $33.7 million. These letters of credit primarily guarantee various contract bidding, insurance activities and shipyard commitments.

(2)	Contractual maturity in 2025 (Notes can be redeemed by us or we may be required to purchase beginning in December 2012). Can be converted prior to stated maturity if closing sale price of Helix’s common stock for at least 20 days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter exceeds 120% of the closing price on that 30th trading day (i.e. $38.56 per share) and under certain triggering events as specified in the indenture governing the Convertible Senior Notes. To the extent we do not have alternative long-term financing secured to cover the conversion, the Convertible Senior Notes would be classified as a current liability in the accompanying balance sheet. As of December 31, 2008, the conversion trigger was not met.

(3)	Includes total interest obligations of $26.4 million related to CDI’s long-term debt.

(4)	Amount represents dividend payment for 2009 only. Dividends are paid annually until such time the holder elects to convert or redeem the stock. The holder redeemed $30 million of our convertible preferred stock shares into 5.9 million shares of our common stock in January 2009 (Note 13). Our first-quarter 2009 results will include a corresponding noncash dividend of $29.3 million to reflect the redemption of the incremental shares issued to the holder above the shares underlying the redemption feature. This dividend will reduce the net income available to our common shareholders for the period.

(5)	Costs incurred as of December 31, 2008 and additional property and equipment commitments (excluding capitalized interest) at December 31, 2008 consisted of the following (in thousands):

		Costs Incurred		Costs Committed		Total Project Cost
Caesar conversion	$	158,937	$	11,832	$	210,000—230,000
Well Enhancer construction		149,691		31,165		200,000—220,000
Helix Producer I conversion(a)		210,107		4,944		345,000—365,000
Total	$	518,735	$	47,941	$	755,000—815,000

(a) Represents 100% of the vessel conversion cost, of which we expect our portion to range between $301 million and $321 million.

(6)	Operating leases included facility leases and vessel charter leases. Vessel charter lease commitments at December 31, 2008 were approximately $153.9 million. Operating leases include $21.6 million related to CDI.

Contingencies

In December 2005 and in May 2006, our Oil and Gas segment received notice from the MMS that the price threshold was exceeded for 2004 oil and gas production and for 2003 gas production, respectively, and that royalties are due on such production notwithstanding the provisions of the DWRRA. In addition, in September 2008, we received notice from the MMS that price thresholds were exceeded for 2007, 2006 and 2005 oil and gas production. The total reserved amount at December 31, 2008 was approximately $69.7 million and was included in Other Long Term Liabilities in the accompanying consolidated balance sheet included herein. 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. As a result of this ruling, we believe that any future payment of these contractual royalties is not probable. Accordingly, in the first quarter of 2009 our operating results will include a $69.7 million gain from the reversal of these previously reserves amounts associated with the potential payment of the disputed royalties. See Item 3. Legal Proceedings and Note 18 for a detailed discussion of this contingency.

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 or 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, and to 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 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. We will reduce net income applicable to common shareholders by an approximate $29.3 million non-cash dividend that will be reflected in our first quarter of 2009 results. This non-cash dividend reflects 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 a conversion.

The Fletcher Agreement provides that if the volume weighted average price of our common stock on any date is 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 the holder under the Fletcher Agreement. As a result of the redemption that occurred in January, the maximum number of shares available for redemption of Series A-1 Cumulative Convertible Stock is 9,035,038. 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 Fletcher’s redemption in January 2009, and the reset of the conversion price, Fletcher would receive an aggregate of 9,035,038 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. Under the existing terms of our Senior Credit Facilities (Note 11) we are not permitted to deliver cash to the holder upon a conversion of the Convertible Preferred Stock.

Critical Accounting Estimates and Policies

Our results of operations and financial condition, as reflected in the accompanying financial statements and related footnotes, are prepared 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. We believe the most critical accounting policies in this regard are those described below. While these issues require us to make judgments that are somewhat subjective, they are generally based on a significant amount of historical data and current market data. For a detailed discussion on the application of our accounting policies, see Item 8. Financial Statements and Supplementary Data “— Notes to Consolidated Financial Statements — Note 2.”

Revenue Recognition

Contracting Services Revenues

Revenues from Contracting Services and Shelf Contracting are derived from contracts that traditionally have been of relatively short duration; however, beginning in 2007, contract durations started to become longer-term. These contracts contain either lump-sum turnkey provisions or provisions for specific time, material and equipment charges, which are billed in accordance with the terms of such contracts. We recognize revenue as it is earned at estimated collectible amounts. Further, we record revenue net of taxes collected from customers and remitted to governmental authorities.

Unbilled revenue represents revenue attributable to work completed prior to period end that has not yet been invoiced. All amounts included in unbilled revenue at December 31, 2008 and 2007 are expected to be billed and collected within one year.

Dayrate Contracts. Revenues generated from specific time, materials and equipment contracts are generally earned on a dayrate basis and recognized as amounts are earned in accordance with contract terms. In connection with these contracts, we may receive revenues for mobilization of equipment and personnel. In connection with new contracts, revenues related to mobilization are deferred and recognized over the period in which contracted services are performed using the straight-line method. Incremental costs incurred directly for mobilization of equipment and personnel to the contracted site, which typically consist of materials, supplies and transit costs, are also deferred and recognized over the period in which contracted services are performed using the straight-line method. Our policy to amortize the revenues and costs related to mobilization on a straight-line basis over the estimated contract service period is consistent with the general pace of activity, level of services being provided and dayrates being earned over the service period of the contract. Mobilization costs to move vessels when a contract does not exist are expensed as incurred.

Turnkey Contracts. Revenue on significant turnkey contracts is recognized on the percentage-of-completion method based on the ratio of costs incurred to total estimated costs at completion. In determining whether a contract should be accounted for using the percentage-of-completion method, we consider whether:

	•		the customer provides specifications for the construction of facilities or for the provision of related services;
	•		we can reasonably estimate our progress towards completion and our costs;
	•		the contract includes provisions as to the enforceable rights regarding the goods or services to be provided, consideration to be received and the manner and terms of payment;
	•		the customer can be expected to satisfy its obligations under the contract; and
	•		we can be expected to perform our contractual obligations.

Under the percentage-of-completion method, we recognize estimated contract revenue based on costs incurred to date as a percentage of total estimated costs. Changes in the expected cost of materials and labor, productivity, scheduling and other factors affect the total estimated costs. Additionally, external factors, including weather and other factors outside of our control, may also affect the progress and estimated cost of a project’s completion and, therefore, the timing of income and revenue recognition. We routinely review estimates related to our contracts and reflect revisions to profitability in earnings on a current basis. If a current estimate of total contract cost indicates an ultimate loss on a contract, we recognize the projected loss in full when it is first determined. At December 31, 2008, we had two contracts that were deemed to be in loss status and we recorded an aggregate $9.8 million charge to cost of sales to estimate the expected loss to completion of the respective contracts (Note 2). We recognize additional contract revenue related to claims when the claim is probable and legally enforceable.

Oil and Gas Revenues

We record revenues from the sales of crude oil and natural gas when delivery to the customer has occurred, prices are fixed and determinable, collection is reasonably assured and title has transferred. This occurs when production has been delivered to a pipeline or a barge lifting has occurred. We may have an interest with other producers in certain properties. In this case, we use the entitlements method to account for sales of production. Under the entitlements method, we may receive more or less than our entitled share of production. If we receive more than our entitled share of production, the imbalance is treated as a liability. If we receive less than our entitled share, the imbalance is recorded as an asset. As of December 31, 2008, the net imbalance was a $1.7 million asset and was included in Other Current Assets ($7.5 million) and Accrued Liabilities ($5.8 million) in the accompanying consolidated balance sheet.

Purchase Price Allocation

In connection with a purchase business combination, the acquiring company must allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Deferred taxes must be recorded for any differences between the assigned values and tax bases of assets and liabilities. Any excess of purchase price over amounts assigned to assets and liabilities is recorded as goodwill. The amount of goodwill recorded in any particular business combination can vary significantly depending upon the value attributed to assets acquired and liabilities assumed.

In December 2007, CDI completed the acquisition of Horizon. This acquisition was accounted for as a business combination. The allocation of the purchase price was finalized during 2008 based upon valuations using estimates and assumptions that were reviewed and approved by CDI management.

In July 2006, we acquired the assets and assumed the liabilities of Remington in a transaction accounted for as a business combination. In estimating the fair values of Remington’s assets and liabilities, we made various assumptions. The most significant assumptions related to the estimated fair values assigned to proved and unproved crude oil and natural gas properties. To estimate the fair values of these properties, we prepared estimates of crude oil and natural gas

reserves. We estimated future prices to apply to the estimated reserve quantities acquired, and estimated future operating and development costs, to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues were discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the merger. The market-based weighted average cost of capital rate was subjected to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved reserves, the estimated probable and possible reserves were reduced by additional risk-weighting factors.

Estimated deferred taxes were based on available information concerning the tax basis of Remington’s assets and liabilities and loss carryforwards at the merger date. The allocation of purchase price for Remington was finalized in 2007.

While the estimates of fair value for the assets acquired and liabilities assumed have no effect on our cash flows, they can have an effect on the future results of operations. Generally, higher fair values assigned to crude oil and natural gas properties result in higher future depreciation, depletion and amortization expense, which results in a decrease in future net earnings. Also, a higher fair value assigned to crude oil and natural gas properties, based on higher future estimates of crude oil and natural gas prices, could increase the likelihood of an impairment in the event of lower commodity prices or higher operating costs than those originally used to determine fair value. An impairment would have no effect on cash flows but would result in a decrease in net income for the period in which the impairment is recorded.

In 2006, we also completed the acquisition of Acergy, Fraser and 58% of Seatrac. These acquisitions were accounted for as business combinations as well. We finalized the purchase price allocation for Acergy and Fraser in the second quarter of 2006 and 2007, respectively. In July 2007, we purchased the remaining 42% of Seatrac. The allocation of purchase price for Seatrac was finalized in 2008.

We complete our valuation of assets and liabilities (including deferred taxes) for the purpose of allocation of the total purchase price amount to assets acquired and liabilities assumed during the twelve-month period following the acquisition date.

For more information regarding the allocation of purchase price associated with our acquisition see Notes 4, 5 and 6.

Goodwill and Other Intangible Assets

Under Statement of Financial Accounting Standard No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”), we are required to perform an annual impairment analysis of goodwill and intangible assets. We elected November 1 to be the annual impairment assessment date for goodwill and other intangible assets. However, we could be required to evaluate the recoverability of goodwill and other intangible assets prior to the required annual assessment date if we experience disruption to the business, unexpected significant declines in operating results, divestiture of a significant component of the business emergence of unanticipated competition, loss of key personnel or a sustained declined in market capitalization. SFAS No. 142 also requires testing of goodwill impairment to be at a reporting unit level and defines the reporting unit as an operating segment, as that term is used in SFAS No. 131, or one level below the operating segment (referred to as a “component”), depending on whether certain criteria are met. At the time of our annual assessment of goodwill, we had six reporting units with goodwill and our impairment analysis was conducted at this level.

Goodwill impairment is determined using a two-step process that requires management to make judgments in determining what assumptions to use in the calculation. The first step is to identify if a potential impairment exists by comparing the fair value of the reporting unit with its carrying amount, including goodwill. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered to have a potential impairment and the

second step of the impairment test is not necessary. However, if the carrying amount of a reporting unit exceeds its fair value, the second step is performed to determine if goodwill is impaired and to measure the amount of impairment loss to recognize, if any.

The second step compares the implied fair value of goodwill with the carrying amount of goodwill. If the implied fair value of goodwill exceeds the carrying amount, then goodwill is not considered impaired. However, if the carrying amount of goodwill exceeds the implied fair value, an impairment loss is recognized in an amount equal to that excess. The implied fair value of goodwill is determined in the same manner as the amount of goodwill recognized in a business combination (i.e. the fair value of the reporting unit is allocated to all the assets and liabilities, including any unrecognized intangible assets, as if the reporting unit had been acquired in a business combination).

We use both the income approach and market approach to estimate the fair value of our reporting units under the first step. Under the income approach, a discounted cash flow analysis is performed requiring us to make various judgmental assumptions about future revenue, operating margins, growth rates and discount rates. These judgmental assumptions are based on our budgets, long-term business plans, reserve reports, economic projections, anticipated future cash flows and market place data. Under the market approach, the fair value of each reporting unit is calculated by applying an average peer total invested capital EBITDA (defined as earnings before interest, income taxes and depreciation and amortization) multiple to the 2009 budgeted EBITDA for each reporting unit. Judgment is required when selecting peer companies that operate in the same or similar lines of business and are potentially subject to the same corresponding economic risks.

Based on the first step of the 2008 goodwill impairment analysis, the carrying amount of two of our reporting units exceeded its fair value as calculated under the first step, which required us to perform the second step of the impairment test. In the second step, the fair value of tangible and certain intangible assets was generally estimated using discounted cash flow analysis. The fair value of intangibles with indefinite lives, such as trademarks, was calculated using a royalty rate method. Based on our 2008 goodwill and indefinite-lived intangible impairment analysis, in the fourth quarter of 2008 we recorded a $704.3 million charge to write off the remaining goodwill of our Oil and Gas segment. The impairment charges associated with our oil and gas segment are recorded as a component of operating loss in the accompanying consolidated statements of operations. We also recorded a $10.7 million charge in the fourth quarter of 2008 to write off the remaining goodwill and indefinite-lived intangible assets associated with our acquisition of Helix Energy Limited in 2005. Those impairment charges are reflected as components of income (loss) from discontinued operations in the accompanying consolidated statements of operations included in Exhibit 99.3 of this Current Report on Form 8-K as a result of our sale of Helix Energy Limited in April 2009. These impairment charges did not have any current effect and will not have any future effect on cash flow or our results of operations.

While we believe we have made reasonable estimates and assumptions to calculate the fair value of the reporting units and other intangible assets, it is possible a material change could occur. We have $366.2 million of goodwill remaining at December 31, 2008, including $292.5 million for CDI. If our actual results are not consistent with our estimates and assumptions used to calculate fair value, our results of operations may be materially impacted as further impairments may occur. Unless there is a dramatic improvement in prevailing economic conditions, we will be required to again assess the fair value of our remaining goodwill and other intangible assets at March 31, 2009.

Income Taxes

Deferred income taxes are based on the difference between financial reporting and tax bases of assets and liabilities. We utilize the liability method of computing deferred income taxes. The liability method is based on the amount of current and future taxes payable using tax rates and laws in effect at the balance sheet date. Income taxes have been provided based upon the tax laws and rates in the countries in which operations are conducted and income is earned. A valuation allowance for deferred tax assets is recorded when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized.

We consider the undistributed earnings of our principal non-U.S. subsidiaries to be permanently reinvested. At December 31, 2008, our principal non-U.S. subsidiaries had accumulated earnings and profits of approximately $127.8 million. We have not provided deferred U.S. income tax on the accumulated earnings and profits. The deconsolidation of CDI’s net income for tax return filing purposes after its initial public offering did not have a material impact on our consolidated results of operations; however, because of our inability to recover our tax basis in CDI tax free, a long term deferred tax liability is provided for any incremental increases to the book over tax basis.

It is our policy to provide for uncertain tax positions and the related interest and penalties based upon management’s assessment of whether a tax benefit is more likely than not to be sustained upon examination by tax authorities. At December 31, 2008, we believe we have appropriately accounted for any unrecognized tax benefits. To the extent we prevail in matters for which a liability for an unrecognized tax benefit is established or are required to pay amounts in excess of the liability, our effective tax rate in a given financial statement period may be affected.

See Note 12 for discussion of net operating loss carry forwards, deferred income taxes and uncertain tax positions taken by the Company.

Accounting for Oil and Gas Properties

Acquisitions of producing offshore properties are recorded at the fair value exchanged at closing together with an estimate of their proportionate share of the decommissioning liability assumed in the purchase (based upon their working interest ownership percentage). In estimating the decommissioning liability assumed in offshore property acquisitions, we perform detailed estimating procedures, including engineering studies and then reflect the liability at fair value on a discounted basis as discussed below.

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. Capitalized costs of producing oil and gas properties are depleted to operations by the unit-of-production method based on proved developed oil and gas reserves on a field-by-field basis as determined by our engineers. Leasehold costs for producing properties are depleted using the units-of-production method based on the amount of total estimated proved reserves on a field-by-field basis. Costs incurred relating to unsuccessful exploratory wells are expensed in the period the drilling is determined to be unsuccessful (see “— Exploratory Drilling Costs” below).

We evaluate the impairment of our proved oil and gas properties on a field-by-field basis at least annually or whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. If an impairment is indicated, the cash flows are discounted at a rate approximate to our cost of capital and compared to the carrying value for determining the amount of the impairment loss to record. Estimated future cash flows are based on management’s expectations for the future and include estimates of crude oil and natural gas reserves and future commodity prices, operating costs and future capital expenditures. Downward revisions in estimates of proved reserve quantities or expectations of falling

commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate a property impairment. We recorded property impairments totaling $215.7 million in 2008 ($192.6 million in the fourth quarter of 2008) and approximately $64.1 million of property impairments in 2007, primarily related to downward reserve revisions and weak end of life well performance in some of our domestic properties. There was no impairment of proved oil and gas properties in 2006.

We also periodically assess unproved properties for impairment based on exploration and drilling efforts to date on the individual prospects and lease expiration dates. Management’s assessment of the results of exploration activities, availability of funds for future activities and the current and projected political climate in areas in which we operate also impact the amounts and timing of impairment provisions. We recorded a total of $8.9 million of exploration expense to write off certain unproved oil and gas properties reflecting management’s assessment that exploration activities will not commence prior to the respective lease expiration dates, including a $8.0 million charge in the fourth quarter of 2008. During 2007, we recorded $9.9 million of exploration expense to impair certain unproved leasehold costs. There were no asset impairments recorded in 2006.

Exploratory Drilling Costs

In accordance with the successful efforts method of accounting, the costs of drilling an exploratory well are capitalized as uncompleted or “suspended” wells temporarily pending the determination of whether the well has found proved reserves. If proved reserves are not found, these capitalized costs are charged to expense. A determination that proved reserves have been found results in the continued capitalization of the drilling costs of the well and its reclassification as a well containing proved reserves.

At times, it may be determined that an exploratory well may have found hydrocarbons at the time drilling is completed, but it may not be possible to classify the reserves at that time. In this case, we may continue to capitalize the drilling costs as an uncompleted well beyond one year when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project, or the reserves are deemed to be proved. If reserves are not ultimately deemed proved or economically viable, the well is considered impaired and its costs, net of any salvage value, are charged to expense. At December 31, 2007, we had two wells that were deemed to be suspended wells under the criteria established by SFAS 19-1 “Accounting for Suspended Well Costs”. Following the significant decrease in commodity prices in the second half of 2008 coupled with the December 2008 announcement of our intention to sell all or a part of our oil and gas business, we determined that further development of these wells was not probable. Accordingly, we recorded a total of $18.8 million to exploration expense to fully write off the capital costs associated with these two suspended wells.

Occasionally, we may choose to salvage a portion of an unsuccessful exploratory well in order to continue exploratory drilling in an effort to reach the target geological structure/formation. In such cases, we charge only the unusable portion of the well bore to dry hole expense, and we continue to capitalize the costs associated with the salvageable portion of the well bore and add the costs to the new exploratory well. In certain situations, the well bore may be carried for more than one year beyond the date drilling in the original well bore was suspended. This may be due to the need to obtain, and/or analyze the availability of equipment or crews or other activities necessary to pursue the targeted reserves or evaluate new or reprocessed seismic and geographic data. If, after we analyze the new information and conclude that we will not reuse the well bore or if the new exploratory well is determined to be unsuccessful after we complete drilling, we will charge the capitalized costs to dry hole expense. During the years ended December 31, 2008, 2007 and 2006, we incurred $27.7 million, $20.2 million and $38.3 million, respectively, of exploratory expenses (Note 7).

Estimated Proved Oil and Gas Reserves

The evaluation of our oil and gas reserves is critical to the management of our oil and gas operations. Decisions such as whether development of a property should proceed and what technical methods are available for development are based on an evaluation of reserves. These oil and gas reserve quantities are also used as the basis for calculating the unit-of-production rates for depreciation, depletion and amortization, evaluating impairment and estimating the life of our producing oil and gas properties in our decommissioning liabilities. Our proved reserves are classified as either proved developed or proved undeveloped. Proved developed reserves are those reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves include reserves expected to be recovered from new wells from undrilled proven reservoirs or from existing wells where a significant major expenditure is required for completion and production. We prepare all of our reserve information, and our independent petroleum engineers’ audit, and the estimates of our oil and gas reserves presented in this report (U.S. reserves only) based on guidelines promulgated under generally accepted accounting principles in the United States. See detailed description of our use of the term “engineering audit” and our process of preparing reserve estimates in Item 2. Properties “— Summary of Natural Gas and Oil Reserve Data.” Our estimated proved reserves in this Annual Report include only quantities that we expect to recover commercially using current prices, costs, existing regulatory practices and technology. While we are reasonably certain that the estimated proved reserves will be produced, the timing and ultimate recovery can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and changes in projections of long-term oil and gas prices. Revisions can include upward or downward changes in the previously estimated volumes of proved reserves for existing fields due to evaluation of (1) already available geologic, reservoir or production data or (2) new geologic or reservoir data obtained from wells. Revisions can also include changes associated with significant changes in development strategy, oil and gas prices, or production equipment/facility capacity.

Accounting for Decommissioning Liabilities

Our decommissioning liabilities consist of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”) requires oil and gas companies to reflect decommissioning liabilities on the face of the balance sheet at fair value on a discounted basis. Prior to the Remington acquisition, we have historically purchased producing offshore oil and gas properties that are in the later stages of production. In conjunction with acquiring these properties, we assume an obligation associated with decommissioning the property in accordance with regulations set by government agencies. The abandonment liability related to the acquisitions of these properties is determined through a series of management estimates.

Prior to an acquisition and as part of evaluating the economics of an acquisition, we will estimate the plug and abandonment liability. Our oil and gas operations personnel prepare detailed cost estimates to plug and abandon wells and remove necessary equipment in accordance with regulatory guidelines. We currently calculate the discounted value of the abandonment liability (based on an estimate of the year the abandonment will occur) in accordance with SFAS No. 143 and capitalize that portion as part of the basis acquired and record the related abandonment liability at fair value. The recognition of a decommissioning liability requires that management make numerous estimates, assumptions and judgments regarding factors such as the existence of a legal obligation for liability; estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. Decommissioning liabilities were $225.8 million and $217.5 million at December 31, 2008 and 2007, respectively.

On an ongoing basis, our oil and gas operations personnel monitor the status of wells, and as fields deplete and no longer produce, our personnel will monitor the timing requirements set forth

by the MMS for plugging and abandoning the wells and commence abandonment operations, when applicable. On an annual basis, management personnel reviews and updates the abandonment estimates and assumptions for changes, among other things, in market conditions, interest rates and historical experience. In 2008 and 2007, we incurred $16.0 million and $25.1 million of plug and abandonment overruns related to hurricanes Katrina and Rita, respectively, partially offset by insurance recoveries of $13.4 million and $4.0 million.

Derivative Instruments and 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, variable interest rate exposure and foreign currency exposure. To reduce the impact of these risks on earnings and increase the predictability of our cash flows, from time to time we have entered into certain derivative contracts, primarily collars and swaps, for a portion of our oil and gas production, interest rate swaps, and foreign currency forward contracts. Our oil and gas costless collars and swaps, interest rate swaps, and foreign currency forward exchange contracts are reflected in our balance sheet at fair value. Hedge accounting does not apply to our oil and gas forward sales contracts as these qualify for the normal purchase and sale scope exception under Statement of Financial Accounting Standard No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS No. 133”).

We engage primarily in cash flow hedges. 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 value is recognized immediately in earnings.

The fair value of our oil and gas costless collars 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. The fair value of our interest rate swaps is calculated as the discounted cash flows of the difference between the rate fixed by the hedge instrument and the LIBOR forward curve over the remaining term of the hedge instrument. The fair value of our foreign currency forward exchange contract is calculated as the discounted cash flows of the difference between the fixed payment as specified by the hedge instrument and the expected cash inflow of the forecasted transaction using a foreign currency forward curve.

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.

Property and Equipment

Property and equipment (excluding oil and gas properties and equipment), both owned and under capital leases, are recorded at cost. Depreciation is provided primarily on the straight-line method over the estimated useful lives of the assets (Note 2).

For long-lived assets to be held and used, excluding goodwill, we base our evaluation of recoverability on impairment indicators such as the nature of the assets, the future economic benefit of the assets, any historical or future profitability measurements and other external market conditions or factors that may be present. If such impairment indicators are present or other factors exist that indicate that the carrying amount of the asset may not be recoverable, we determine whether an impairment has occurred through the use of an undiscounted cash flows analysis of the asset at the lowest level for which identifiable cash flows exist. Our marine vessels are assessed on a vessel by vessel basis, while our ROVs are grouped and assessed by asset class. If an impairment has occurred, we recognize a loss for the difference between the carrying amount and the fair value of the asset. The fair value of the asset is measured using quoted market prices or, in the absence of quoted market prices, is based on management’s estimate of discounted cash flows.

Assets are classified as held for sale when we have a formalized plan for disposal of certain assets and those assets meet the held for sale criteria. Assets held for sale are reviewed for potential loss on sale when the company commits to a plan to sell and thereafter while the asset is held for sale. Losses are measured as the difference between the fair value less costs to sell and the asset’s carrying value. Estimates of anticipated sales prices are judgmental and subject to revisions in future periods, although initial estimates are typically based on sales prices for similar assets and other valuation data. We had no assets that met the criteria of being classified as assets held for sale at December 31, 2008.

Recertification Costs and Deferred Drydock Charges

Our Contracting Services and Shelf Contracting vessels are required by regulation to be recertified after certain periods of time. These recertification costs are incurred while the vessel is in drydock. In addition, routine repairs and maintenance are performed and, at times, major replacements and improvements are performed. We expense routine repairs and maintenance as they are incurred. We defer and amortize drydock and related recertification costs over the length of time for which we expect to receive benefits from the drydock and related recertification, which is generally 30 months. Vessels are typically available to earn revenue for the 30-month period between drydock and related recertification processes. A drydock and related recertification process typically lasts one to two months, a period during which the vessel is not available to earn revenue. Major replacements and improvements, which extend the vessel’s economic useful life or functional operating capability, are capitalized and depreciated over the vessel’s remaining economic useful life. Inherent in this process are estimates we make regarding the specific cost incurred and the period that the incurred cost will benefit.

As of December 31, 2008 and 2007, capitalized deferred drydock charges (Note 8) totaled $38.6 million and $48.0 million, respectively. During the years ended December 31, 2008, 2007 and 2006, drydock amortization expense was $26.0 million, $23.0 million and $12.0 million, respectively. We expect drydock amortization expense to increase in future periods due to increases in the number of vessels as a result of the acquisitions made in 2006 and 2007.

Equity Investments

We periodically review our investments in Deepwater Gateway and Independence Hub for impairment. Under the equity method of accounting, an impairment loss would be recorded whenever a decline in value of an equity investment below its carrying amount is determined to be other than temporary. In judging “other than temporary,” we would consider the length of time and extent to which the fair value of the investment has been less than the carrying amount of the equity investment, the near-term and longer-term operating and financial prospects of the equity company and our longer-term intent of retaining the investment in the entity. During 2007, CDI determined that there was an other than temporary impairment in OTSL and the full value of CDI’s investment in OTSL was impaired and CDI recognized equity losses of OTSL, inclusive of the impairment charge, of $10.8 million in 2007 (Note 9).

Worker’s Compensation Claims

Our onshore employees are covered by Worker’s Compensation. Offshore employees, including divers, tenders and marine crews, are covered by our Maritime Employers Liability insurance policy which covers Jones Act exposures. We incur worker’s compensation claims in the normal course of business, which management believes are substantially covered by insurance. Our insurers and legal counsel analyze each claim for potential exposure and estimate the ultimate liability of each claim. Actual liability can be materially different from our estimates and can have a direct impact on our liquidity and results of operations.

Recently Issued Accounting Principles

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 immaterial impact on our results of operations, financial condition and liquidity.

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

·	Level 1. Observable inputs such as quoted prices in active markets;

·	Level 2. Inputs, other than the quoted prices in active markets, that are observable either directly or indirectly; and

·	Level 3. Unobservable inputs in which there is little or no market data, which require the reporting entity to develop its own assumptions.

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

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

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

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

The following table provides additional information related to assets and liabilities measured at fair value on a recurring basis at December 31, 2008 (in thousands):

Level 1

Level 2

Level 3

Total

Valuation Technique

Assets:

Oil and gas swaps and collars

–

22,307

–

22,307

(c)

Liabilities:

Foreign currency forwards

–

940

–

940

(c)

Interest rate swaps

–

7,967

–

7,967

(c)

Total

–

8,907

–

8,907

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 assets or business. The provisions of SFAS No. 141(R) are effective for fiscal years beginning after December 15, 2008 and should be adopted prospectively. 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. The provisions of SFAS No. 160 are required to be adopted prospectively, except the following provisions must be accepted retrospectively:

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.”

equity in our consolidated balance sheet. Any future transactions would result in us losing control of CDI and accordingly the gain or loss on those transactions will flow through our earnings. As discussed in “Subsequent Events” above and in Note 25 of Exhibit 99.3 to this Current Report on Form 8-K, in June 2009 we sold approximately 21.6 million shares of CDI common stock held by us upon completion of an underwritten secondary public offering and a stock repurchase transaction with CDI. As a result of these transactions, at the time of the filing of this Current Report on Form 8-K we own approximately 28% of CDI’s issued and outstanding shares of common stock.

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 asks entities to provide qualitative disclosures about the objectives and strategies for using derivatives, quantitative data about the fair value of and gains and losses on derivative contracts, and details of credit-risk-related contingent features in their hedged positions. The standard is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged, but not required. We adopted the provisions of SFAS No. 161 on January 1, 2009 and it had no impact on our results of operations, cash flows and financial condition.

In May 2008, the FASB issued FASB Staff Position (“FSP”) APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement) (“FSP APB 14-1”). The FSP would require the proceeds from the issuance of convertible debt instruments to be allocated between a liability component (issued at a discount) and an equity component. The resulting debt discount would be amortized over the period the convertible debt is expected to be outstanding as additional non-cash interest expense. We adopted FSP APB 14-1 on January 1, 2009. FSP APB 14-1 requires retrospective application to all periods reported (with the cumulative effect of the change reported in retained earnings as of the beginning of the first period presented). The FSP does not permit early application. This FSP changes the accounting treatment for our Convertible Senior Notes. FSP APB 14-1 will increase our non-cash interest expense for our past and future reporting periods. The effects of the adoption of this accounting standard are summarized in Note 2 of Exhibit 99.3 of this Current Report on Form 8-K.

In June 2008, the FASB issued FSP Emerging Issues Task Force 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (“FSP EITF 03-6-1”). This FSP would require unvested share-based payment awards containing non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) to be included in the computation of basic EPS according to the two-class method. We adopted FSP EITF 03-06-1 on January 1, 2009. FSP EITF 03-06-1 requires all prior-period EPS data presented to be adjusted retrospectively (including interim financial statements, summaries of earnings, and selected financial data) to conform with the provisions of this FSP. FSP EITF 03-6-1 does not permit early application. This FSP changes our calculation of basic and diluted EPS and lowered our previously reported basic and diluted EPS as summarized in Note 2 of Exhibit 99.3 of this Current Report on Form 8-K.

Also in June 2008, the FASB issued Emerging Issues Task Force Issue No. 07-5, Determining Whether an Instrument (or Embedded Feature) is Indexed to an Entity’s Own Stock (“EITF 07-5”). This issue addresses the determination of whether an instrument (or an embedded feature) is indexed to an entity’s own stock, which is the first part of the scope exception in paragraph 11(a) of SFAS No. 133. If an instrument (or an embedded feature) that has the characteristics of a derivative instrument under paragraphs 6–9 of SFAS No. 133 is indexed to an entity’s own stock, it is still necessary to evaluate whether it is classified in shareholders’ equity (or would be classified in shareholders’ equity if it were a freestanding instrument). This issue is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Earlier application by an entity that has previously adopted an

alternative accounting policy is not permitted. While we do not believe the adoption of this statement will have a material effect on our financial statements, we continue to assess its potential impact on our financial statements.

exhibit99-3.htm

EXHIBIT 99.3

Item 8. Financial Statements and Supplementary Data.

INDEX TO FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	1
Consolidated Balance Sheets as of December 31, 2008 and 2007	2
Consolidated Statements of Operations for the Years Ended December 31, 2008, 2007 and 2006	3
Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2008, 2007 and 2006	4
Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006	6
Notes to the Consolidated Financial Statements	8

Index to Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Helix Energy Solutions Group, Inc.

We have audited the accompanying consolidated balance sheets of Helix Energy Solutions Group, Inc. and subsidiaries as of December 31, 2008 and 2007, and the related consolidated statements of operations, shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Helix Energy Solutions Group, Inc. and subsidiaries at December 31, 2008 and 2007, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 2, the consolidated financial statements have been adjusted for the retrospective application of FASB Staff Position APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement), FASB Staff Position EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities and FASB Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements an Amendment of ARB No. 51, which all became effective January 1, 2009. Also, as discussed in Note 25 to the consolidated financial statements, on April 27, 2009, the Company completed the sale of Helix Energy Limited and its subsidiaries. The Company has adjusted its consolidated financial statements to classify the assets, liabilities and results of operations of Helix Energy Limited and its subsidiaries as discontinued operations.

As discussed in Note 12 to the consolidated financial statements, in 2007 the Company adopted FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Helix Energy Solutions Group, Inc.’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 2, 2009 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Houston, Texas

March 2, 2009, except for Notes 2 and 25

as to which the date is June 12, 2009

Index to Financial Statements

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(As Adjusted (Note 2))

	December 31,
	2008			2007
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	223,613		$	89,555
Accounts receivable — Trade, net of allowance for uncollectible accounts of $5,905 and $2,874		427,856			439,738
Unbilled revenue		42,889			10,388
Costs in excess of billing		74,361			53,915
Other current assets		172,089			123,971
Current assets of discontinued operations		19,215			9,702
Total current assets		960,023			727,269
Property and equipment		4,742,051			4,084,366
Less — Accumulated depreciation		(1,323,608	)		(841,459	)
		3,418,443			3,242,907
Other assets:
Equity investments		196,660			212,845
Goodwill, net		366,218			1,078,712
Other assets, net		125,722			158,872
Assets of discontinued operations		—			28,910
	$	5,067,066		$	5,449,515

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	344,807		$	381,182
Accrued liabilities		231,679			219,167
Current maturities of long-term debt		93,540			74,846
Current liabilities from discontinued operations		2,772			3,784
Total current liabilities		672,798			678,979
Long-term debt		1,933,686			1,683,340
Deferred income taxes		615,504			639,285
Decommissioning liabilities		194,665			193,650
Other long-term liabilities		81,637			63,183
Total liabilities		3,498,290			3,258,437

Convertible preferred stock		55,000			55,000
Redeemable portion of equity component of convertible notes		—			42,201
Commitments and contingencies
Shareholders’ equity:
Common stock, no par, 240,000 shares authorized, 91,972 and 91,385 shares issued		806,905			751,627
Retained earnings		417,940			1,057,062
Accumulated other comprehensive income (loss)		(33,696	)		21,262
Total controlling interest shareholders’ equity		1,191,149			1,829,951
Noncontrolling interests		322,627			263,926
Total equity		1,513,776			2,093,877
	$	5,067,066		$	5,449,515

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

Index to Financial Statements

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(As Adjusted (Note 2))

		Year Ended December 31,
		2008			2007			2006
		(In thousands, except per share amounts)
Net revenues:
Contracting services	$	1,568,221		$	1,147,857		$	898,529
Oil and gas		545,853			584,563			429,607
		2,114,074			1,732,420			1,328,136

Cost of sales:
Contracting services		1,135,429			762,812			557,437
Oil and gas		357,853			372,904			224,106
Oil and gas property impairments		215,675			64,072			—
Exploration expense		32,926			26,725			43,115
		1,741,883			1,226,513			824,658

Gross profit		372,191			505,907			503,478

Goodwill and other indefinite-lived intangible impairments		704,311			—			—
Gain on sale of assets, net		73,471			50,368			2,817
Selling and administrative expenses		177,172			144,996			114,234
Income (loss) from operations		(435,821	)		411,279			392,061
Equity in earnings of investments		31,854			19,573			17,927
Gain on subsidiary equity transaction		—			151,696			223,134
Net interest expense and other		89,499			67,047			41,553
Income (loss) before income taxes		(493,466	)		515,501			591,569
Provision for income taxes		(86,779	)		(171,862	)		(252,753	)
Income (loss) from continuing operations		(580,245	)		343,639			338,816
Income (loss) from discontinued operations, net of tax		(9,812	)		1,347			4,806
Net income (loss), including noncontrolling interests		(590,057	)		344,986			343,622
Net income applicable to noncontrolling interests		(45,873	)		(29,288	)		(725	)
Net income (loss) applicable to Helix		(635,930	)		315,698			342,897
Preferred stock dividends		(3,192	)		(3,716	)		(3,358	)
Net income (loss) applicable to Helix common shareholders	$	(639,122	)	$	311,982		$	339,539

Basic earnings (loss) per share of common stock:
Continuing operations	$	(6.94	)	$	3.40		$	3.92
Discontinued operations		(0.11	)		0.02			0.06
Net income (loss) per common share	$	(7.05	)	$	3.42		$	3.98

Diluted earnings (loss) per share of common stock:
Continuing operations	$	(6.94	)	$	3.25		$	3.74
Discontinued operations		(0.11	)		0.01			0.05
Net income (loss) per common share	$	(7.05	)	$	3.26		$	3.79

Weighted average common shares outstanding:
Basic		90,650			90,086			84,613
Diluted		90,650			95,647			89,714

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

Index to Financial Statements

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(As Adjusted (Note 2))

	Helix Energy Solutions Shareholders’ Equity
	Common Stock
	Shares			Amount			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Unearned Comp-ensation			Total controlling interest shareholders’ equity		Non-controlling Interest			Total Equity
Balance, December 31, 2005	77,694		$	229,796		$	408,748		$	(1,729	)	$	(7,515	)	$	629,300	$	—	$	629,300
Impact of adoption of FSP APB 14-1 (Note 2)	—			38,070			(3,207	)		—			—			34,863		—			34,863
Comprehensive income:
Net income	—			—			342,897			—			—			342,897		725			343,622
Foreign currency translations adjustments	—			—			—			17,601			—			17,601		—			17,601
Unrealized gain on hedges, net	—			—			—			11,364			—			11,364		—			11,364
Comprehensive income																371,862		725			372,587
Convertible preferred stock dividends	—			—			(3,358	)		—			—			(3,358	)	—			(3,358	)
Stock compensation expense	—			9,364			—			—			—			9,364		—			9,364
Adoption of SFAS 123R	—			(7,515	)		—			—			7,515			—		—			—
Stock issuance	13,033			553,570			—			—			—			553,570		—			553,570
Stock repurchase	(1,682	)		(50,266	)		—			—			—			(50,266	)	—			(50,266	)
Activity in company stock plans, net	1,583			8,319			—			—			—			8,319		—			8,319
Excess tax benefit from stock- based compensation	—			2,660			—			—			—			2,660		—			2,660
Investments in or dispositions of common stock of consolidated subsidiaries in which Helix has a noncontrolling interest (Note 2)	—			—			—			—			—			—		59,077			59,077
Balance, December 31, 2006	90,628			783,998			745,080			27,236			—			1,556,314		59,802			1,616,116
Comprehensive income:
Net income	—			—			315,698			—			—			315,698		29,288			344,986
Foreign currency translations adjustments	—			—			—			3,680			—			3,680		—			3,680
Unrealized loss on hedges, net	—			—			—			(9,654	)		—			(9,654	)	—			(9,654	)
Comprehensive income																309,724		29,288			339,012
Reclass unamortized discount on convertible senior notes to reflect temporary equity status (Note 2)	—			(42,201	)		—			—			—			(42,201	)	—			(42,201	)
Convertible preferred stock dividends	—			—			(3,716	)		—			—			(3,716	)	—			(3,716	)
Stock compensation expense	—			14,607			—			—			—			14,607		—			14,607
Stock repurchase	(282	)		(9,904	)		—			—			—			(9,904	)	—			(9,904	)
Activity in company stock plans, net	1,039			4,547			—			—			—			4,547		—			4,547
Excess tax benefit from stock- based compensation	—			580			—			—			—			580		—			580
Investments in or dispositions of common stock of consolidated subsidiaries in which Helix has a noncontrolling interest (Note 2)	—			—			—			—			—			—		174,836			174,836
Balance, December 31, 2007	91,385		$	751,627		$	1,057,062		$	21,262			—		$	1,829,951	$	263,926	$		2,093,877

Index to Financial Statements

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(As Adjusted (Note 2)) (Continued)

	Helix Energy Solutions Shareholder’s Equity
	Common Stock
	Shares			Amount			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Unearned Comp-ensation		Total controlling interest shareholders’ equity		Non-controlling Interest		Total Equity
Balance, December 31, 2007	91,385		$	751,627		$	1,057,062		$	21,262		$	—	$	1,829,951	$	263,926	$	2,093,877
Comprehensive income (loss)
Net income (loss )	—			—			(635,930	)		—			—		(635,930	)	45,873		(590,057	)
Foreign currency translations adjustments	—			—			—			(71,134	)		—		(71,134	)	(93	)	(71,227	)
Unrealized loss (gain) on hedges, net	—			—			—			16,176			—		16,176		(480	)	15,696
Comprehensive loss															(690,888	)	45,300		(645,588	)
Reclass unamortized discount on convertible senior notes to shareholders’ equity (Note 2)	—			42,201			—			—			—		42,201		—		42,201
Convertible preferred stock dividends	—			—			(3,192	)		—			—		(3,192	)	—		(3,192	)
Other	—			(3,952	)		—			—			—		(3,952	)	—		(3,952	)
Stock compensation expense	—			15,506			—			—			—		15,506		—		15,506
Stock repurchase	(110	)		(3,925	)		—			—			—		(3,925	)	—		(3,925	)
Activity in company stock plans, net	697			4,113			—			—			—		4,113		—		4,113
Excess tax benefit from stock- based compensation	—			1,335			—			—			—		1,335		—		1,335
Investments in or dispositions of common stock of consolidated subsidiaries in which Helix has a noncontrolling interest (Note 2)	—			—			—			—			—		—		13,401		13,401
Balance, December 31, 2008	91,972		$	806,905		$	417,940		$	(33,696	)	$	—	$	1,191,149		322,627	$	1,513,776

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

Index to Financial Statements

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(As Adjusted (Note 2))

		Year Ended December 31,
		2008			2007			2006
		(In thousands)
Cash flows from operating activities:
Net income (loss), including noncontrolling interests	$	(590,057	)	$	344,986		$	343,622
Adjustments to reconcile net income (loss), including noncontolling interests to net cash provided by operating activities —
Depreciation and amortization		333,726			329,798			191,705
Asset impairment charge		215,675			64,072			—
Goodwill and other indefinite-lived intangible impairments		704,311			—			—
Exploratory drilling and related expenditures		27,703			20,187			38,335
Equity in earnings of investments, net of distributions		2,846			697			(1,897	)
Equity in (earnings) losses of OTSL, inclusive of impairment charge		—			10,841			487
Amortization of deferred financing costs		5,641			6,939			2,711
(Income) loss from discontinued operations		9,658			(1,345	)		(4,806	)
Stock compensation expense		21,412			17,302			9,364
Amortization of debt discount		7,385			6,920			6,485
Deferred income taxes		(5,402	)		125,083			55,274
Excess tax benefit from stock-based compensation		(1,335	)		(580	)		(2,660	)
Hedge ineffectiveness		(1,669	)		—			—
Gain on subsidiary equity transaction		—			(151,696	)		(223,134	)
Gain on sale of assets		(73,471	)		(50,368	)		(2,817	)
Changes in operating assets and liabilities:
Accounts receivable, net		(36,956	)		(6,758	)		(65,523	)
Other current assets		(4,958	)		(22,351	)		9,392
Income tax payable		(12,937	)		(153,804	)		142,302
Accounts payable and accrued liabilities		(126,082	)		(52,362	)		39,914
Other noncurrent, net		(41,076	)		(66,786	)		(29,176	)
Cash provided by operating activities		434,414			420,775			509,578
Cash provided by (used in) discontinued operations		3,305			(4,449	)		4,458
Net cash provided by operating activities		437,719			416,326			514,036

Cash flows from investing activities:
Capital expenditures		(855,054	)		(942,381	)		(468,000	)
Acquisition of businesses, net of cash acquired		—			(147,498	)		(887,943	)
(Purchases) sale of short-term investments		—			285,395			(285,395	)
Investments in equity investments		(846	)		(17,459	)		(27,578	)
Distributions from equity investments, net		11,586			6,679			—
Increase in restricted cash		(614	)		(1,112	)		(6,666	)
Proceeds from insurance		13,200			—			—
Proceeds from sale of subsidiary stock		—			—			264,401
Proceeds from sales of property		274,230			78,073			32,342
Other, net		—			(136	)		—
Cash used in investing activities		(557,498	)		(738,439	)		(1,378,839	)
Cash used in discontinued operations		(476	)		(1,215	)		(1,091	)
Net cash used in investing activities	$	(557,974	)	$	(739,654	)	$	(1,379,930	)

Index to Financial Statements

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(As Adjusted (Note 2)) (Continued)

		Years Ended December 31,
		2008			2007			2006
		(in thousands)
Cash flows from financing activities:
Borrowings under Helix term loan	$	—		$	—		$	835,000
Repayment of Helix term loan		(4,326	)		(405,408	)		(2,100	)
Borrowings on Helix Revolver		1,021,500			472,800			209,800
Repayments on Helix Revolver		(690,000	)		(454,800	)		(209,800	)
Borrowings on unsecured senior debt		—			550,000			—
Repayment of MARAD borrowings		(4,014	)		(3,823	)		(3,641	)
Borrowings on CDI Revolver		61,100			31,500			201,000
Repayments on CDI Revolver		(61,100	)		(332,668	)		—
Borrowings on CDI term loan		—			375,000			—
Repayments on CDI term loan		(60,000	)		—			—
Borrowing under loan notes		—			5,000			5,000
Deferred financing costs		(1,796	)		(17,165	)		(11,839	)
Capital lease payments		(1,505	)		(2,519	)		(2,827	)
Preferred stock dividends paid		(3,192	)		(3,716	)		(3,613	)
Repurchase of common stock		(3,925	)		(9,904	)		(50,266	)
Excess tax benefit from stock-based compensation		1,335			580			2,660
Exercise of stock options, net		2,139			1,568			8,886
Net cash provided by) financing activities		256,216			206,445			978,260

Effect of exchange rate changes on cash and cash equivalents		(1,903	)		174			2,818
Net (decrease) increase in cash and cash equivalents		134,058			(116,709	)		115,184
Cash and cash equivalents:
Balance, beginning of year		89,555			206,264			91,080
Balance, end of year	$	223,613		$	89,555		$	206,264

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

Index to Financial Statements

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(As Adjusted (Note 2))

Note 1 — Organization

Effective March 6, 2006, we changed our name from Cal Dive International, Inc. to Helix Energy Solutions Group, Inc. (“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, including Cal Dive International, Inc. (collectively with its subsidiaries referred to as “Cal Dive” or “CDI”). 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 deepwater construction, well operations and reservoir and well technology services 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). In June 2009, our ownership interest was further reduced to approximately 28% (Notes 2 and 25). Our Production Facilities business includes our investments in Deepwater Gateway, L.L.C. (“Deepwater Gateway”) and Independence Hub, LLC (“Independence Hub”).

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. Over the last 16 years we have evolved this business model to include not only mature oil and gas properties but also proved and unproved reserves yet to be developed and explored. This has led to the assembly of services that allows us to create value at key points in the life of a reservoir from exploration through development, life of field management and operating through abandonment.

Index to Financial Statements

Economic Outlook

The recent 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 probable decrease in the near-term global demand for oil and gas has resulted in commodity price declines over the second half of 2008, with significant declines occurring in the fourth quarter of 2008. Declines in oil and gas prices negatively impacts our operating results and cash flows. Our stock price significantly declined in the fourth quarter of 2008 ($24.28 per share at September 30, 2008 and $7.24 per share at December 31, 2008). The decline in our stock price and declines in the prices of oil and natural gas, were considered in association with our required annual impairment assessment of goodwill as of November 1, 2008, at which time we assessed the fair value of our goodwill, indefinite-lived intangible assets and certain of our oil and gas properties, which resulted in our continuing operations recording an aggregate of $896.9 million of asset impairment charges in the fourth quarter of 2008 (Note 2). If the price of our common stock does not increase over the near-term, we may be required to record additional impairment charges associated with our remaining $366.2 million of goodwill as of December 31, 2008 that is related to our Contracting Services ($73.7 million) and Shelf Contracting ($292.5 million) businesses. Further, our contracting services also may be negatively impacted by declining commodity prices as such 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 will enable us to minimize our near-term cash flow risks related to declining commodity prices (Note 2). The prices for these contracts are significantly higher than the prices for both crude oil and natural gas as of December 31, 2008 and as of the time of the filing of our 2008 Annual Report on Form 10-K (“2008 Form 10-K”) on March 2, 2009. 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 2 — Adjustments and Summary of Significant Accounting Policies

Adjustments to Consolidated Financial Statements

The accompanying consolidated financial statements have been adjusted (1) for the retrospective application of Financial Accounting Standards Board (“FASB”) Staff Position No. APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement) (“FSP APB 14-1”),” (2) for the retrospective application of FASB Staff Position EITF 03-06-1, “Determining Whether Instruments Granted in Share Based Payment Transactions Are Participating Securities,” (“FSP EITF 03-06-1”) and(3) for the retrospective application of FASB Statement No. 160 “Noncontrolling Interests in Consolidated Financial Statements,” (“SFAS No. 160”), all of which became effective January 1, 2009. As discussed below and in Note 25, on April 27, 2009 we completed the sale of Helix Energy Limited and its subsidiary, Helix RDS Limited, We have also adjusted our consolidated financial statements to classify the assets and liabilities and results of operations of Helix Energy Limited and Helix RDS Limited as discontinued operations.

The financial information contained in the financial statements and the accompanying consolidated notes to financial statements reflect only the adjustments described below and any modifications associated with the two subsequent events disclosed below and in Note 25. No other modifications or update to these disclosures for events that occurred after March 2, 2009, the date of the filing of our 2008 Form 10-K, have been made in this Current Report on Form 8-K.

Index to Financial Statements

FSP APB 14-1

FSP APB 14-1 requires issuers to account separately for the liability (issued at a discount) and equity components of certain convertible debt instruments in a manner that reflects the issuer’s unsecured debt borrowing rate when interest expense is recognized. The resulting debt discount is amortized over the period the convertible debt is expected to be outstanding as additional non-cash interest expense. The rate at which debt discount is amortized reflects the issurer’s unsecured borrowing rate when the debt was issued. We adopted FSP APB 14-1 on January 1, 2009 and early adoption was not permitted. However, once adopted FSP APB 14-1 requires retrospective application. The adoption of FSP APB 14-1 affects the accounting for our 3.25% Convertible Senior Notes (Note 11) issued in 2005 and due in 2025. The retrospective application of FSP ABP 14-1 affects years ended December 31, 2006, 2007 and 2008 with the cumulative effect of the change in accounting principle being reported as an adjustment to retained earnings as of January 1, 2006.

FSP EITF 03-06-1

FSP EITF 03-06-1 requires unvested share-based payment awards containing non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) to be included in the computation of basic earning per share (“EPS”) according to the two-class method. We adopted FSP 03-06-1 on January 1, 2009 and early adoption was not permitted. FSP EITF 03-6-1 also requires all prior-period EPS data presented to be adjusted retrospectively (including interim financial statements, summaries of earnings, and selected financial data) to conform with the provisions of FSP EITF 03-06-1. Adoption of FSP EITF 03-06-1 lowered our previously reported basic and diluted EPS except for the year ended December 31, 2008, which was not affected given the net loss for the period and the fact the participating securities are not responsible for sharing in losses of the Company.

SFAS No. 160

SFAS No. 160 requires all entities to report noncontrolling (minority) interests in subsidiaries as equity in the balance sheet . We adopted SFAS No. 160 on January 1, 2009 and its provisions are required to be adopted prospectively, except the following provisions must be adopted retrospectively:

1.	Reclassifying noncontrolling interest from “mezzanine” to equity, separate from the parent’s 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.”

Further, effective January 1, 2009, we have 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, pursuant to 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 and reduced our ownership in CDI to approximately 51%. Since we retained control of CDI immediately after the transaction, the approximate $2.9 million loss on this sale will be treated as a reduction of our equity in our consolidated balance sheet. On June 10, 2009, we completed an underwritten secondary public offering by selling 20 million shares of CDI common stock held by us (“the Offering”). Proceeds from the Offering totaled $161.9 million, net of underwriting fees. The Offering remains subject to a thirty day option period under which the underwriters may sell up to an additional 3 million shares of our CDI shares of common stock at $8.50 per share, the price per share under the Offering. Separately, pursuant to a Stock Repurchase Agreement with CDI, upon closing of the Offering, CDI simultaneously repurchased from us approximately 1.6 million shares of its common stock shares for $14 million in net proceeds at $8.50 per share. Following the closing of these two transactions, our ownership of Cal Dive common stock has been reduced to approximately 28%.

Index to Financial Statements

Discontinued Operations

On April 27, 2009, we sold Helix Energy Limited to a subsidiary of Baker Hughes Incorporated for $25 million. Helix Energy Limited 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 sale of our reservoir and well technology services business represented by Helix Energy Limited, and its subsidiary Helix RDS Limited, we have presented its results and financial position as discontinued operations in the accompanying consolidated financial statements. Helix Energy Limited was previously a component of our Contracting Services segment. A summary of the consolidated results of operations of Helix Energy Limited is as follows:

		Year Ended December 31,
		2008			2007			2006
		(in thousands)
Revenues	$	34,275		$	35,025		$	38,788
Cost of sales		25,798			27,176			26,858
Gross profit		8,477			7,849			11,930
Goodwill and other indefinite-lived intangible impairments		(10,677	)		—			—
Selling and administrative expenses		(7,536	)		(6,384	)		(5,346	)
Income (loss) from operations		(9,736	)		1,465			6,584
Equity in income (loss) of investments		117			125			203
Net interest expense and other		268			249			—
Provision for income taxes		(461	)		(492	)		(1,981	)
Income (loss) from discontinued operations	$	(9,812	)	$	1,347		$	4,806

A summary of the consolidated financial position of Helix Energy Limited is as follows:

		December 31,
		2008		2007
		(in thousands)
Accounts receivable	$	6,558	$	8,091
Other current assets		2,941		1,611
Property and equipment, net		1,147		1,781
Equity investments		627		584
Goodwill		—		11,046
Other assets		7,942		15,499
Total assets	$	19,215	$	38,612

Accounts payable	$	1,428	$	1,585
Accrued liabilities		1,344		2,199
Deferred income liability		1,440		2,381

Index to Financial Statements

Summary of Adjustments

The following table sets forth the effect of the adjustments on certain previously reported line items (in thousands, except for per share data):

	Years Ended December 31,
	2008						2007						2006
	As Previously Reported			As Adjusted			As Previously Reported			As Adjusted			As Previously Reported			As Adjusted
Net interest expense and other	$	(81,412	)	$	(89,499	)	$	(59,444	)	$	(67,047	)	$	(34,634	)	$	(41,553	)

Provision for income taxes		(89,977	)		(86,779	)		(174,928	)		(171,862	)		(257,156	)		(252,753	)

Net income (loss) from continuing operations		(584,975	)		(580,245	)		349,766			343,639			348,119			338,816

Income (loss) from discontinued operations, net of tax		-			(9,812	)		-			1,347			-			4,806

Net income (loss) applicable to common shareholders	$	(634,040	)	$	(639,122	)	$	316,762		$	311,982		$	344,036		$	339,539

Net income (loss) Per Share of common stock
Basic	$	(6.99	)	$	(7.05	)	$	3.52		$	3.42		$	4.07		$	3.98
Diluted	$	(6.99	)	$	(7.05	)	$	3.34			3.26		$	3.87		$	3.79

The following table sets forth the effect on the aforementioned adjustments on certain previously reported line items in our accompanying consolidated balance sheets (in thousands):

	December 31, 2008				December 31, 2007
	As Reported		As Adjusted		As Reported		As Adjusted
Current assets from discontinued operations	$	-	$	19,215	$	-	$	9,702
Assets from discontinued operations		-		-		-		28,910
Current liabilities from discontinued operations		-		2,772		-		3,784
Long-term debt		1,968,502		1,933,686		1,725,541		1,683,340
Deferred income tax liability		604,464		615,504		625,508		639,285
Reedeemable portion of equity component of convertible notes (a)		-		-		-		42,201
Common stock, no par value		768,835		806,905		755,758		751,627
Retained earnings		435,506		417,940		1,069,546		1,057,062
Noncontrolling interests		-		322,627		-		263,926
Total equity		1,170,645		1,513,776		1,846,566		2,093,877

a) Reflects unamortized debt discount at reporting date when the conversion triggers for Convertible Senior Notes have been met, allowing the holders to redeem the instruments for cash or other assets. Amount is included in common stock, no par value and is classified as permanent equity in all periods when the conversion trigger is not met.

Index to Financial Statements

In addition, the adjustments resulted in changes to our consolidated statements of cash flows and Notes 1,2,3,5,6,8,11,12,15,19,20,23, 24 and 25.

Principles of Consolidation

Our consolidated financial statements include the accounts of majority-owned subsidiaries and variable interest entities in which we are the primary beneficiary. The equity method is used to account for investments in affiliates in which we do not have majority ownership, but have the ability to exert significant influence. We account for our Deepwater Gateway and Independence Hub investments under the equity method of accounting. Noncontrolling interests represent minority shareholders’ proportionate share of the equity in CDI and Kommandor LLC. As noted above in “Adjustments” and in Note 25, we sold a substantial portion of our investment in CDI on June 10, 2009. All material intercompany accounts and transactions have been eliminated. Certain reclassifications were made to previously reported amounts in the consolidated financial statements and notes thereto to make them consistent with the current presentation format, including the separate line disclosures of goodwill, oil and gas property impairment charges and exploration expense in the consolidated statements of operations reflecting the material amount of such charges in 2008.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash and Cash Equivalents

Cash and cash equivalents are highly liquid financial instruments with original maturities of three months or less. They are carried at cost plus accrued interest, which approximates fair value.

Statement of Cash Flow Information

As of December 31, 2008 and 2007, we had $35.4 million and $34.8 million, respectively, of restricted cash included in other assets (Note 8), all of which was related to funds required to be escrowed to cover decommissioning liabilities associated with the acquisition of the South Marsh Island Block 130 property in 2002. Under the purchase agreement for that property, we are obligated to escrow 50% of revenues on the first $20 million of production escrow and then 37.5% of revenues on production until a total of $33 million is escrowed. At December 31, 2008 the full escrow requirement under this agreement has been met and is available for the future decommissioning of this field.

The following table provides supplemental cash flow information for the periods stated (in thousands):

		Year Ended December 31,
		2008		2007		2006
Interest paid, net of interest capitalized	$	53,000	$	71,706	$	26,104
Income taxes paid	$	106,624	$	203,873	$	56,972

Non-cash investing activities for the years ended December 31, 2008, 2007 and 2006 included $78.5 million, $90.7 million and $39.0 million, respectively, related to accruals of capital expenditures. The accruals have been reflected in the consolidated balance sheet as an increase in property and equipment and accounts payable.

Index to Financial Statements

Short-term Investments

Short-term investments are available-for-sale instruments that we expect to realize in cash within one year. These investments are stated at cost, which approximates market value. Any unrealized holding gains or losses are reported in accumulated other comprehensive income (loss) until realized. We did not hold these types of securities at December 31, 2008 and 2007.

Accounts Receivable and Allowance for Uncollectible Accounts

Accounts receivable are stated at the historical carrying amount net of write-offs and allowance for uncollectible accounts. The amount of our net accounts receivable approximate fair value. We establish an allowance for uncollectible accounts receivable based on historical experience and any specific customer collection issues that we have identified. Uncollectible accounts receivable are written off when a settlement is reached for an amount that is less than the outstanding historical balance or when we have determined that the balance will not be collected (Note 20).

Inventories

We had inventory totaling $32.2 million at December 31, 2008 and $29.9 million at December 31, 2007. Our inventory primarily represents the cost of supplies to be used in our oil and gas drilling and development activities, primarily drilling pipe, tubulars and certain wellhead equipment, including two subsea trees. These costs will be partially reimbursed by third party participants in wells supplied with these materials. Our inventories are stated at the lower of cost or market. At December 31, 2008, we recorded $2.4 million of charges to cost of sales to reduce our inventory to its lower of cost or market value as of that date.

Property and Equipment

Overview. Property and equipment, both owned and under capital leases, are recorded at cost. The following is a summary of the components of property and equipment (dollars in thousands):

	Estimated Useful Life		2008		2007

Vessels	10 to 30 years	$	1,941,733	$	1,566,720
Oil and gas leases and related equipment	Units-of-Production		2,564,851		2,354,392
Machinery, equipment, buildings and leasehold improvements	5 to 30 years		235,467		163,254
Total property and equipment		$	4,742,051	$	4,084,366

The cost of repairs and maintenance is charged to expense as incurred, while the cost of improvements is capitalized. Total repair and maintenance expenses totaled $72.4 million, $44.1 million and $51.0 million for the years ended December 31, 2008, 2007 and 2006, respectively. Included in machinery, equipment, buildings and leasehold improvements were $19.1 million and $9.8 million of capitalized software costs at December 31, 2008 and 2007, respectively. Total amount charged to income related to such costs was $1.2 million, $0.3 million and $0.2 million for the year ended December 31, 2008, 2007 and 2006, respectively.

Index to Financial Statements

For long-lived assets to be held and used, excluding goodwill, we base our evaluation of recoverability on impairment indicators such as the nature of the assets, the future economic benefit of the assets, any historical or future profitability measurements and other external market conditions or factors that may be present. If such impairment indicators are present or other factors exist that indicate the carrying amount of the asset may not be recoverable, we determine whether an impairment has occurred through the use of an undiscounted cash flow analysis of the asset at the lowest level for which identifiable cash flows exist. Our marine vessels are assessed on a vessel by vessel basis, while our ROVs are grouped and assessed by asset class. If an impairment has occurred, we recognize a loss for the difference between the carrying amount and the fair value of the asset The fair value of the asset is measured using quoted market prices or, in the absence of quoted market prices, is based on an estimate of discounted cash flows. There were no such impairments related to our vessels during 2008, 2007 and 2006.

Assets are classified as held for sale when we have a formalized plan for disposal of certain assets and those assets meet the held for sale criteria. Assets classified as held for sale are included in other current assets. Similarly, when we are formally committed to sell an entire reporting business andwe will have no continuing involvement in said reporting unit, we record those assets and liabilities separately in the balance sheet as assets and liabilities associated with discontinued operations. The accompanying consolidated balance sheets reflect the assets and liabilities of Helix Energy Limited and its subsidiaries as discontinued operations.

Depreciation and Depletion. Depletion for our oil and gas properties is calculated on a unit-of-production basis. The calculation is based on the estimated remaining oil and gas proved and proved developed reserves. Depreciation for all other property and equipment is provided on a straight-line basis over the estimated useful lives of the assets.

Oil and Gas Properties. Almost all of our interests in oil and gas properties are located offshore in the Gulf of Mexico and located in waters regulated by the United States. We follow the successful efforts method of accounting for our natural gas and oil exploration and development activities. Under this 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 and are reflected as a reduction of investing cash flow in the accompanying consolidated statements of cash flow. Costs incurred relating to unsuccessful exploratory wells are expensed in the period when the drilling is determined to be unsuccessful and are included as a reconciling item to net income (loss) in operating activities in the accompanying consolidated statements of cash flow. See “— Exploratory Costs” below.

Proved Properties. We assess proved oil and gas properties for possible impairment at least annually or when events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. We recognize an impairment loss as a result of a triggering event and when the estimated undiscounted future cash flows from a property are less than the carrying value. If an impairment is indicated, the cash flows are discounted at a rate approximate to our cost of capital and compared to the carrying value for determining the amount of the impairment loss to record. Estimated future cash flows are based on management’s expectations for the future and include estimates of crude oil and natural gas reserves and future commodity prices and operating costs. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate a property impairment. We recorded approximately $215.7 million and $64.1 million of property impairments in 2008 and 2007, respectively, primarily related to downward reserve revisions, weak end of life well performance in some of our domestic properties and fields lost as a result of Hurricanes Gustav and Ike and the reassessment of the economics of some of our marginal fields in light of current oil and gas market conditions. During 2006, no impairment of proved oil and gas properties was recorded.

Index to Financial Statements

Unproved Properties. We also periodically assess unproved properties for impairment based on exploration and drilling efforts to date on the individual prospects and lease expiration dates. Management’s assessment of the results of exploration activities, availability of funds for future activities and the current and projected political climate in areas in which we operate also impact the amounts and timing of impairment provisions. During 2008 and 2007, we recorded $8.9 million and $9.9 million, respectively, of impairment related to unproved oil and gas properties. Such impairments were included in exploration expenses for our Oil and Gas segment. During 2006, no impairment of unproved oil and gas properties was recorded.

Exploratory Costs. The costs of drilling an exploratory well are capitalized as uncompleted or “suspended” wells temporarily pending the determination of whether the well has found proved reserves. If proved reserves are not found, these capitalized costs are charged to expense. A determination that proved reserves have been found results in the continued capitalization of the drilling costs of the well and its reclassification as a well containing proved reserves. At times, it may be determined that an exploratory well may have found hydrocarbons at the time drilling is completed, but it may not be possible to classify the reserves at that time. In this case, we may continue to capitalize the drilling costs as an uncompleted, or “suspended,” well beyond one year if we can justify its completion as a producing well and we are making sufficient progress assessing the reserves and the economic and operating viability of the project. If reserves are not ultimately deemed proved or economically viable, the well is considered impaired and its costs, net of any salvage value, are charged to expense.

Occasionally, we may choose to salvage a portion of an unsuccessful exploratory well in order to continue exploratory drilling in an effort to reach the target geological structure/formation. In such cases, we charge only the unusable portion of the well bore to dry hole exploration expense, and we continue to capitalize the costs associated with the salvageable portion of the well bore which increase the capital cost basis of the new exploratory well. In certain situations, the well bore may be carried for more than one year beyond the date drilling in the original well bore was suspended. This may reflect the need to obtain, and/or analyze the availability of, equipment or crews or other activities necessary to pursue the targeted reserves or evaluate new or reprocessed seismic and geographic data. If, after we analyze the new information and conclude that we will not reuse the well bore or if the new exploratory well is determined to be unsuccessful after we complete drilling, we will charge all the capitalized costs to dry hole exploration expense. During the year ended December 31, 2008, 2007 and 2006, we incurred $27.7 million, $20.2 million and $38.3 million, respectively, of exploratory expense; including $18.8 million, $10.3 million and $38.3 million of dry hole expense. See “— Note 7 — Oil and Gas Properties” for detailed discussion of our exploratory activities.

Property Acquisition Costs. Acquisitions of producing properties are recorded at the value exchanged at closing together with an estimate of our proportionate share of the discounted decommissioning liability assumed in the purchase based upon the working interest ownership percentage.

Properties Acquired from Business Combinations. Properties acquired through business combinations are recorded at their fair value. In determining the fair value of the proved and unproved properties, we prepare estimates of oil and gas reserves. We estimate future prices to apply to the estimated reserve quantities acquired and the estimated future operating and development costs to arrive at our estimates of future net revenues. For the fair value assigned to proved reserves, the future net revenues are discounted using a market-based weighted average cost of capital rate determined to be appropriate at the time of the acquisition. To compensate for inherent risks of estimating and valuing unproved reserves, probable and possible reserves are reduced by additional risk weighting factors. See Note 4 for a detailed discussion of our acquisition of Remington.

Capitalized Interest. Interest from external borrowings is capitalized on major projects until the assets are ready for their intended use. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful lives of the assets in the same manner as the underlying assets. The total of our interest expense capitalized during each of the three years ended December 31, 2008, 2007 and 2006 was $42.1 million, $31.8 million and $10.6 million, respectively.

Index to Financial Statements

Equity Investments

We periodically review our investments in Deepwater Gateway and Independence Hub for impairment. Under the equity method of accounting, an impairment loss would be recorded whenever the fair value of an equity investment is determined to be below its carrying amount and the reduction is considered to be other than temporary. In judging “other than temporary,” we would consider the length of time and extent to which the fair value of the investment has been less than the carrying amount of the equity investment, the near-term and long-term operating and financial prospects of the equity company and our longer-term intent of retaining the investment in the entity. During 2007, CDI determined that there was an other than temporary impairment in its investment of Offshore Technology Solutions Limited (“OTSL”) and the full value of CDI’s investment in OTSL was impaired and CDI recognized equity losses of OTSL, inclusive of the impairment charge, of $10.8 million in 2007 (Note 9).

Goodwill and Other Intangible Assets

Under Statement of Financial Accounting Standard No. 142, Goodwill and Other Intangible Assets (“SFAS No. 142”), we are required to perform an annual impairment analysis of goodwill and intangible assets. We elected November 1 to be the annual impairment assessment date for goodwill and other intangible assets. However, we could be required to evaluate the recoverability of goodwill and other intangible assets prior to the required annual assessment date if we experience disruption to the business, unexpected significant declines in operating results, divestiture of a significant component of the business, emergence of unanticipated competition, loss of key personnel or a sustained decline in market capitalization. Our goodwill impairment test involves a comparison of the fair value with our carrying amount. The fair value is determined using discounted cash flows and other market-related valuation models.

We completed our annual goodwill impairment test as of November 1, 2008 based on six reporting units. Goodwill impairment is determined using a two-step process. The first step is to identify if a potential impairment exists by comparing the fair value of the reporting unit with its carrying amount, including goodwill. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered to have a potential impairment and the second step of the impairment test is not necessary. However, if the carrying amount of a reporting unit exceeds its fair value, the second step is performed to determine if goodwill is impaired and to measure the amount of impairment loss to recognize, if any.

We used both the income approach and market approaches to estimate the fair value of our reporting units under the first step. Under the income approach, a discounted cash flow analysis is performed requiring us to make various judgmental assumptions about future revenue, operating margins, growth rates and discount rates. These judgmental assumptions are based on our budgets, long-term business plans, reserve reports, economic projections, anticipated future cash flows and market place data. Under the market approach, the fair value of each reporting unit is calculated by applying an average peer total invested capital EBITDA (defined as earnings before interest, income taxes and depreciation and amortization) multiple to the 2009 budgeted EBITDA for each reporting unit. Judgment is required when selecting peer companies that operate in the same or similar lines of business and are potentially subject to the same corresponding economic risks.

Index to Financial Statements

The recent 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 probable decrease in the near-term global demand for oil and gas has resulted in commodity price declines over the second half of 2008, with significant declines occurring in the fourth quarter of 2008. Declines in oil and gas prices negatively impacts our operating results and cash flow. We believe that these events have contributed to a significant decline in our stock price and corresponding market capitalization. Based on the first step of the 2008 goodwill impairment analysis, the carrying amount of two of our reporting units exceeded their fair value as calculated under the first step, which required us to perform the second step of the impairment test. In the second step, the fair value of tangible and certain intangible assets was generally estimated using discounted cash flow analysis. The fair value of intangibles with indefinite lives such as trademark was calculated using a royalty rate method. Based on our 2008 goodwill impairment analysis, we recorded a $704.3 million charge to impairment expense in our Oil and Gas segment. In addition, we eliminated all the goodwill associated with Helix Energy Limited and its subsidiaries by recording an $8.3 million charge. We also recorded a $2.4 million charge related to a trade name used by Helix RDS. These charges related to Helix Energy Limited and its subsidiary, Helix RDS Limited, are reflected as a component of income (loss) from discontinued operations in the accompanying consolidated statements of operations.

The changes in the carrying amount of goodwill are as follows (in thousands):

	Contracting Services			Shelf Contracting		Oil and Gas			Total
Balance at December 31, 2006	$	77,404		$	26,666	$	707,596		$	811,666
Remington acquisition (Note 4)		—			—		4,796			4,796
Well Ops SEA Pty Ltd. acquisition (Note 6)		6,001			—		—			6,001
Horizon acquisition (Note 5)		—			257,340		—			257,340
Tax and other adjustments		(1,226	)		135		—			(1,091	)
Balance at December 31, 2007		82,179			284,141		712,392			1,078,712
Impairment expense (1)		—			—		(704,311	)		(704,311	)
Goodwill written off related to sale of business		—			—		(8,081	)		(8,081	)
Horizon acquisition (Note 5)		—			8,328		—			8,328
Well Ops SEA Pty Ltd. acquisition (Note 6)		1,029			—		—			1,029
Other adjustments(2)		(9,459	)		—		—			(9,459	)
Balance at December 31, 2008	$	73,749		$	292,469	$	—		$	366,218

(1)	Reflects foreign currency adjustment for certain amount of our goodwill.

A summary of other intangible assets, net, is as follows (in thousands):

	As of December 31, 2008					As of December 31, 2007
	Gross Amount		Accumulated Amortization			Gross Amount		Accumulated Amortization
Contract backlog	$	2,960	$	(1,330	)	$	2,960	$	(387	)
Customer relationships		6,758		(2,294	)		6,753		(1,034	)
Non-compete agreements		4,800		(4,500	)		4,800		(1,069	)
Trade name		490		(74	)		490		(3	)
Intellectual property		1,458		(668	)		2,007		(778	)
Total	$	16,466	$	(8,866	)	$	17,010	$	(3,271	)

Total amortization expenses for intangible assets for the years ended December 31, 2008, 2007, and 2006 was $5.8 million, $1.8 million and $1.0 million, respectively. A summary of the estimated amortization expense for the next five years is as follows (in thousands):

Index to Financial Statements

Years Ended December 31,
2009	$	2,992
2010		1,243
2011		1,243
2012		1,210
2013		555

Recertification Costs and Deferred Drydock Charges

Our Contracting Services and Shelf Contracting vessels are required by regulation to be recertified after certain periods of time. These recertification costs are incurred while the vessel is in drydock. In addition, routine repairs and maintenance are performed and, at times, major replacements and improvements are performed. We expense routine repairs and maintenance as they are incurred. We defer and amortize drydock and related recertification costs over the length of time for which we expect to receive benefits from the drydock and related recertification, which is generally 30 months but can be as long as 60 months if the appropriate permitting is obtained. Vessels are typically available to earn revenue for the period between drydock and related recertification processes. A drydock and related recertification process typically lasts one to two months, a period during which the vessel is not available to earn revenue. Major replacements and improvements, which extend the vessel’s economic useful life or functional operating capability, are capitalized and depreciated over the vessel’s remaining economic useful life. Inherent in this process are estimates we make regarding the specific cost incurred and the period that the incurred cost will benefit.

As of December 31, 2008 and 2007, capitalized deferred drydock charges included within Other Assets in the accompanying consolidated balance sheet (Note 8) totaled $38.6 million and $48.0 million, respectively. During the years ended December 31, 2008, 2007 and 2006, drydock amortization expense was $26.0 million, $23.0 million and $12.0 million, respectively.

Accounting for Decommissioning Liabilities

We account for our decommissioning liabilities in accordance with Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS No. 143”). This statement requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying cost of the asset. Our asset retirement obligations consist of estimated costs for dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. An asset retirement obligation and the related asset retirement cost are recorded when an asset is first constructed or purchased. The asset retirement cost is determined and discounted to present value using a credit-adjusted risk-free rate. After the initial recording, the liability is increased for the passage of time, with the increase being reflected as accretion expense in the statement of operations. Subsequent adjustment in the cost estimates are reflected in the liability and the amounts continue to be accreted over the useful life of the related long-lived asset.

SFAS No. 143 calls for measurements of asset retirement obligations to include, as a component of expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties and unforeseeable circumstances inherent in the obligations, sometimes referred to as a market-risk premium. To date, the oil and gas industry has no examples of credit-worthy third parties who are willing to assume this type of risk, for a determinable price, on major oil and gas production facilities and pipelines. Therefore, because determining such a market-risk premium would be an arbitrary process, we excluded it from our SFAS No. 143 estimates.

Index to Financial Statements

The following table describes the changes in our asset retirement obligations for the year ended 2008 and 2007 (in thousands):

		2008			2007
Asset retirement obligation at January 1,	$	217,479		$	167,671
Liability incurred during the period		6,819			27,822
Liability settled during the period		(47,703	)		(41,892	)
Revision in estimated cash flows		36,121			52,903
Accretion expense (included in depreciation and amortization)		13,065			10,975
Asset retirement obligations at December 31,	$	225,781		$	217,479

Revenue Recognition

Contracting Services Revenues

Revenues from Contracting Services and Shelf Contracting are derived from contracts that traditionally have been of relatively short duration; however, beginning in 2007, contract durations have started to become longer-term. These contracts contain either lump-sum turnkey provisions or provisions for specific time, material and equipment charges, which are billed in accordance with the terms of such contracts. We recognize revenue as it is earned at estimated collectible amounts. Further, we record revenues net of taxes collected from customers and remitted to governmental authorities.

Dayrate Contracts. Revenues generated from specific time, materials and equipment contracts are generally earned on a dayrate basis and recognized as amounts are earned in accordance with contract terms. In connection with these contracts, we may receive revenues for mobilization of equipment and personnel. In connection with contracts, revenues related to mobilization are deferred and recognized over the period in which contracted services are performed using the straight-line method. Incremental costs incurred directly for mobilization of equipment and personnel to the contracted site, which typically consist of materials, supplies and transit costs, are also deferred and recognized over the period in which contracted services are performed using the straight-line method. Our policy to amortize the revenues and costs related to mobilization on a straight-line basis over the estimated contract service period is consistent with the general pace of activity, level of services being provided and dayrates being earned over the service period of the contract. Mobilization costs to move vessels when a contract does not exist are expensed as incurred.

	•		the customer provides specifications for the construction of facilities or for the provision of related services;
	•		we can reasonably estimate our progress towards completion and our costs;
	•		the contract includes provisions as to the enforceable rights regarding the goods or services to be provided, consideration to be received and the manner and terms of payment;
	•		the customer can be expected to satisfy its obligations under the contract; and
	•		we can be expected to perform our contractual obligations.

Index to Financial Statements

Under the percentage-of-completion method, we recognize estimated contract revenue based on costs incurred to date as a percentage of total estimated costs. Changes in the expected cost of materials and labor, productivity, scheduling and other factors affect the total estimated costs. Additionally, external factors, including weather and other factors outside of our control, may also affect the progress and estimated cost of a project’s completion and, therefore, the timing of income and revenue recognition. We routinely review estimates related to our contracts and reflect revisions to profitability in earnings on a current basis. If a current estimate of total contract cost indicates an ultimate loss on a contract, we recognize the projected loss in full when it is first determined. We recognize additional contract revenue related to claims when the claim is probable and legally enforceable. If dependable, estimates of progress cannot be made or for which inherent hazards make estimates doubtful, the completed contract method is used instead of percentage-of-completion method.

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 is anticipated to be approximately $0.8 million. 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. We will continue to monitor our exposure under this contract in 2009.

Oil and Gas Revenues

We record revenues from the sales of crude oil and natural gas when delivery to the customer has occurred, title has transferred, prices are fixed and determinable and collection is reasonably assured. This occurs when production has been delivered to a pipeline or a barge lifting has occurred. We may have an interest with other producers in certain properties. In this case, we use the entitlements method to account for sales of production. Under the entitlements method, we may receive more or less than our entitled share of production. If we receive more than our entitled share of production, the imbalance is treated as a liability. If we receive less than our entitled share, the imbalance is recorded as an asset. As of December 31, 2008, the net imbalance was a $1.7 million asset and was included in Other Current Assets ($7.5 million) and Accrued Liabilities ($5.8 million) in the accompanying consolidated balance sheet.

Income Taxes

Deferred income taxes are based on the differences between financial reporting and tax bases of assets and liabilities. We utilize the liability method of computing deferred income taxes. The liability method is based on the amount of current and future taxes payable using tax rates and laws in effect at the balance sheet date. Income taxes have been provided based upon the tax laws and rates in the countries in which operations are conducted and income is earned. A valuation allowance for deferred tax assets is recorded when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. We consider the undistributed earnings of our principal non-U.S. subsidiaries to be permanently reinvested. The deconsolidation of CDI’s net income for tax return filing purposes after its initial public offering did not have a material impact on our consolidated results of operations; however, because of our inability to recover our tax basis in CDI tax free, a long term deferred tax liability is provided for any incremental increases to the book over tax basis.

Index to Financial Statements

Foreign Currency

The functional currency for our foreign subsidiaries, Well Ops (U.K.) Limited and Helix RDS, is the applicable local currency (British Pound), and the functional currency of Well Ops SEA Pty. Ltd. is its applicable local currency (Australian Dollar). 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 December 31, 2008 and 2007 and the resulting translation adjustment, which was an unrealized (loss) gain of $(71.1) million and $3.7 million, respectively, is included in accumulated other comprehensive income, a component of shareholders’ equity. All foreign currency transaction gains and losses are recognized currently in the statements of operations.

Canyon Offshore, Inc., our ROV subsidiary, has operations in the United Kingdom and Asia Pacific. Further, CDI has subsidiaries with operations in the Middle East, Southeast Asia, the Mediterranean, Australia and Latin America. Canyon’s and CDI’s international subsidiaries conduct the majority of their operations in these regions in U.S. dollars which is considered to be their 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 each of the years ended December 31, 2008, 2007 and 2006 were not material to our results of operations or cash flows.

Our foreign currency gains (losses) totaled ($10.0) million in 2008, ($0.5) million in 2007 and $0.3 million in 2006.

Derivative Instruments and Hedging Activities

We are currently exposed to market risk in three major areas: commodity prices, interest rates and foreign currency exchange risks. 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 risks. All derivatives are reflected in our balance sheet at fair value, unless otherwise noted.

We engage primarily 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.

Index to Financial Statements

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

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 estimations of future prices, price correlation and market volatility and liquidity. Our actual results may differ from our estimates, and these differences can be positive or negative.

We have entered into various costless collar and swap contracts to stabilize cash flows relating to a portion of our expected oil and gas production. These contracts qualified for hedge accounting. The aggregate fair value of these derivative instruments was a net asset (liability) of $22.3 million and $(8.1) million as of December 31, 2008 and 2007, respectively.

For the years ended December 31, 2008, 2007 and 2006, we recorded unrealized gains (losses) of approximately $15.0 million, $(8.7) million and $12.1 million, net of tax expense (benefit) of $8.1 million, $(4.7) million and $6.5 million, respectively, in accumulated other comprehensive income, a component of shareholders’ equity, as these hedges were highly effective. All unrealized losses recorded in other comprehensive income in 2008 are expected to be reclassified into earnings within the next 12 months. During 2008, 2007 and 2006, we reclassified approximately $(17.1) million, $0.5 million and $9.0 million, respectively, of gains (losses) from other comprehensive income to Oil and Gas revenues upon the sale of the related oil and gas production. In addition, during 2008 we recorded a gain of approximately $6.4 million in other non-operating income/expense as a result of the discontinuation of hedge accounting due to production shut-ins and the resultant deferrals caused by Hurricanes Gustav and Ike. No hedge ineffectiveness was recorded during the years ended December 31, 2007 and 2006.

As of December 31, 2008, we have the following volumes under derivatives and forward sales contracts related to our oil and gas producing activities totaling 2,222 MBbl of oil and 30,489 Mmcf of natural gas:

Production Period	Instrument Type	Average Monthly Volumes	Weighted Average Price
Crude Oil:			(per barrel)
January 2009 — June 2009	Collar	50.25 MBbl	$	75.00 — $89.95
January 2009 — March 2009	Swap	40 MBbl	$	57.16
January 2009 — December 2009	Forward Sales	150 MBbl	$	71.79

Natural Gas:			(per Mcf)
January 2009 — December 2009	Collar	1,029 Mmcf	$	7.00 — $7.90
January 2009 — March 2009	Swap	529 Mmcf	$	6.69
January 2009 — December 2009	Forward Sales	1,379 Mmcf	$	8.23

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.

Index to Financial Statements

Variable Interest Rate Risks

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

In September 2006, we entered into various interest rate swaps to stabilize cash flows relating to a portion of our interest payments on our Term Loan (Note 11). These interest rate swaps qualified for hedge accounting. On December 21, 2007, we prepaid a portion of our Term Loan which reduced the notional amount of our interest rate swaps and caused our hedges to become ineffective. As a result, the interest rate swaps no longer qualified for hedge accounting treatment under SFAS No. 133. On January 31, 2008, we re-designated these swaps as cash flow hedges with respect to our outstanding LIBOR-based debt; however, at September 30, 2008, based on the hypothetical derivatives method, we assessed the hedges were not highly effective, and as such, no longer qualified for hedge accounting. During the year ended December 31, 2008 and 2007, we recognized $5.3 million and $0.6 million, respectively, of unrealized losses as other expense as a result of the change in fair value of our interest rate swaps. As of December 31, 2008 and December 31, 2007, the aggregate fair value of the derivative instruments was a net liability of $8.0 million and $4.7 million, respectively. During the year ended December 31, 2008 and 2007, we reclassified approximately $1.7 million and $(0.4) million of (gains) losses, respectively, from other accumulated comprehensive income (loss), a component of shareholders’ equity, to interest expense.

In addition, in April 2008, CDI entered into a two-year interest rate swap to stabilize cash flows relating to a portion of its variable interest payments on the CDI term loan. As of December 31, 2008, this interest rate swap was highly effective and qualified for hedge accounting. The fair value of the hedge instrument was a liability of $1.7 million as of December 31, 2008. Based on future three-month LIBOR interest rate curves as of December 31, 2008, $0.9 million of the unrealized loss from CDI’s interest rate swap recorded in other comprehensive income at December 31, 2008 would be reclassified into earnings within the next 12 months.

Foreign Currency Exchange Risks

Because we operate in various regions in the world, we conduct a portion of our business in currencies other than the U.S. dollar. We entered into various foreign currency forwards to stabilize expected cash outflows relating to certain shipyard contracts where the contractual payments are denominated in euros and expected cash outflows relating to certain vessel charters denominated in British pounds. The aggregate fair value of the foreign currency forwards as of December 31, 2008 and December 31, 2007 was a net asset (liability) of ($0.9) million and $1.4 million, respectively. For the year ended December 31, 2008 we recorded unrealized gains of approximately $0.1 million in accumulated other comprehensive income, a component of shareholders’ equity, all of which are expected to be reclassified into earnings within the next 12 months. For the year ended December 31, 2007, we recorded unrealized gains of approximately $1.1 million, net of tax expense of $0.5 million, in accumulated other comprehensive income. In 2008, we recorded approximately $0.8 million of unrealized losses, net of tax benefit of $0.4 million, as other expense as a result of the change in fair value of our foreign currency forwards that did not qualify for hedge accounting.

Index to Financial Statements

Earnings per Share (As Adjusted (Note 2))

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 basic earnings per share (“EPS”) amounts under the two class method. We have adjusted the prior periods EPS amounts in the table below to reflect the adoption of FSP 03-06-1 on January 1, 2009 (Note 2).

Basic earnings per share is computed by dividing the net income (loss) available to common shareholders by the weighted-average shares of common stock outstanding. 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 for the years ended December 31, 2008, 2007 and 2006 were as follows (in thousands):

		Year Ended December 31,
		2008				2007				2006
		Loss		Shares		Income		Shares		Income		Shares
Basic:
Net income (loss) applicable to common shareholders	$	(639,122	)		$	311,982			$	339,539
Less: Undistributed net income allocable to participating securities		─				(4,189	)			(2,628	)
Undistributed net income (loss) applicable to common shareholders		(639,122	)			307,793				336,911
(Income) loss from discontinued operations		9,812				(1,347	)			(4,806	)
Add undistributed income from discontinued operations allocable to participating securities		─				18				37
Net income (loss) per common share – continuing operations	$	(629,310	)	90,650	$	306,464		90,086	$	332,142		84,613


Diluted:
Net income (loss) per common share – continuing operations	$	(629,310	)	90,650	$	306,464	90,086	$	332,142	84,613
Effect of dilutive securities:
Stock options		─		─		─	382		─	461
Undistributed earnings reallocated to participating securities		─		─		239	─		146	─
Convertible Senior Notes		─		─		─	1,548		─	1,009
Convertible preferred stock		─		─		3,716	3,631		3,358	3,631
Income (loss) per common share – continuing operations		(629,310	)			310,419			335,646
Income (loss) per common share – discontinued operations		(9,812	)			1,347			4,806
Net income (loss) per common share		(639,122	)	90,650		311,766	95,647		340,452	89,714

Index to Financial Statements

We had a net loss applicable to common shareholders in 2008. Accordingly, our diluted per share calculation for 2008 is equivalent to our basic loss per share calculation because it excludes any assumed exercise or conversion of common stock equivalents because they are deemed to be anti-dilutive, meaning their inclusion would have reduced the reported net loss per share for 2008. Shares that otherwise would have been included in the diluted per share amount include, 0.3 million shares associated with stock options whose exercise price was less than the average price for our common stock for 2008, 0.1 million shares associated with unvested restricted shares and 3.6 million equivalent shares of common stock from the assumed conversion of our convertible preferred stock. The diluted earnings (loss) per share calculation also excludes the consideration of adding back the $3.2 million of dividends and related costs associated with the convertible preferred stock that otherwise would have been added back to net income if assumed conversion of the shares was dilutive during 2008. There were no stock options outstanding whose exercise price was greater than the average price for our common stock for each of the years ending December 31, 2008, 2007 and 2006. Net income for the diluted earnings per share calculation for the years ended December 31, 2007 and 2006 were adjusted to add back the preferred stock dividends and accretion on 3.6 million shares.

Stock Based Compensation Plans

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 and all other terms were fixed. 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 business day prior to the grant date, and expense was recognized over the vesting period of each grant on a straight-line basis.

We did not grant any stock options during the three-year period ended December 31, 2008. The fair value of shares issued under the Employee Stock Purchase Plan was based on the 15% discount received by the employees. The estimated fair value of the options is amortized to expense over the vesting period. See “— Note 14 — Employee Benefit Plans” for discussion of our stock compensation.

Accounting for Sales of Stock by Subsidiary

We recognize a gain or loss upon the direct sale or issuance of equity by our subsidiaries if the sales price differs from our carrying amount, provided that the sale of such equity is not part of a broader corporate reorganization. See “— Note 3” and “— Note 5” for discussion of CDI’s initial public offering and common stock issuance as part of the acquisition of Horizon Offshore, Inc. (“Horizon”). Effective January 1, 2009, we have 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. If we retain control, the gain or loss is recorded as a component of total equity See “Adjustments to Consolidated Financial Statements” above.

Consolidation of Variable Interest Entities

FASB Interpretation No. 46 (R), Consolidation of 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. See Note 10 related to our consolidated variable interest entities.

Index to Financial Statements

Fair Value of Financial Instruments

Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and our long-term debt. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the highly liquid nature of these instruments. The carrying amount and estimated fair value of our debt, including current maturities as of December 31, 2008 and 2007 follow (amount in thousands):

	2008				2007
	Carrying Value		Fair Value		Carrying Value		Fair Value
Term Loan(2)	$	419,093	$	251,455	$	423,418	$	410,715
Revolving Credit Facility(3)		349,500		349,500		18,000		18,000
Cal Dive Term Loan(3)		315,000		315,000		375,000		375,000
Convertible Senior Notes(1,2)		265,184		136,383		257,799		442,485
Senior Unsecured Notes(2)		550,000		261,250		550,000		559,625
MARAD Debt(4)		123,449		132,609		127,463		126,061
Loan Notes(5)		5,000		5,000		6,506		6,506
Total	$	2,027,226	$	1,451,197	$	1,758,186	$	1,938,392

(1)	Carrying value is net of unamortized discount on issuance of debt resulting from adoption of APB 14-1 on January 1, 2009. The unamortized debt discount totaled $34.8 million at December 31, 2008 and $42.2 million at December 31, 2007. The fair values of these instruments were based on quoted market prices as of December 31, 2008 and 2007.

(2)	The fair values of these instruments were based on quoted market prices as of December 31, 2008 and 2007. The fair values were estimated using level 1 inputs as defined by SFAS No. 157 using the market approach (see “Recently Issued Accounting Principles” below).

(3)	The carrying values of these credit facilities approximate fair value.

(4)	The fair value of the MARAD debt was determined by a third-party evaluation of the remaining average life and outstanding principal balance of the MARAD indebtedness as compared to other government guaranteed obligations in the market place with similar terms. The fair value of the MARAD debt was estimated using level 2 inputs as defined by SFAS 157 using the cost approach (see “Recently Issued Accounting Principles” below).

(5)	The carrying value of the loan notes approximates fair value as the maturity date of the loan notes is less than one year.

Major Customers and Concentration of Credit Risk

The market for our products and services is primarily the offshore oil and gas industry. Oil and gas companies spend capital on exploration, drilling and production operations expenditures, the amount of which is generally dependent on the prevailing view of the future oil and gas prices that are subject to many external factors which may contribute to significant volatility in future prices. Our customers consist primarily of major oil and gas companies, well-established oil and pipeline companies and independent oil and gas producers and suppliers. We perform ongoing credit evaluations of our customers and provide allowances for probable credit losses when necessary. The percent of consolidated revenue of major customers, those whose total represented 10% or more of our consolidated revenues, was as follows: 2008 — Louis Dreyfus Energy Services (10%) and Shell Offshore, Inc. (12%); 2007 — Louis Dreyfus Energy Services (14%) and Shell Offshore, Inc. (10%); and 2006 — Louis Dreyfus Energy Services (10%) and Shell Trading (US) Company (10%). All of these customers were purchasers of our oil and gas production. We estimate that in 2008 we provided subsea services to over 200 customers.

Index to Financial Statements

Recently Issued Accounting Principles

	•		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 December 31, 2008 (in thousands):

	Level 1		Level 2		Level 3		Total		Valuation Technique
Assets:
Oil and gas swaps and collars	$	–	$	22,307	$	–	$	22,307	(c)

Liabilities:
Foreign currency forwards		–		940		–		940	(c)
Interest rate swaps		–		7,967		–		7,967	(c)
Total	$	–	$	8,907	$	–	$	8,907

Index to Financial Statements

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. The provisions of SFAS No. 141(R) are effective for fiscal years beginning after December 15, 2008 and should be adopted prospectively. 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 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. The standard is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged, but not required. We 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.

Also in June 2008, the FASB issued Emerging Issues Task Force Issue No. 07-5, Determining Whether an Instrument (or Imbedded Feature) is Indexed to an Entity’s Own Stock (“EITF 07-5”). This issue addresses the determination of whether an instrument (or an embedded feature) is indexed to an entity’s own stock, which is the first part of the scope exception in paragraph 11(a) of SFAS No. 133. If an instrument (or an embedded feature) that has the characteristics of a derivative instrument under paragraphs 6–9 of SFAS No. 133 is indexed to an entity’s own stock, it is still necessary to evaluate whether it is classified in shareholders’ equity (or would be classified in shareholders’ equity if it were a freestanding instrument). This issue is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Earlier application by an entity that has previously adopted an alternative accounting policy is not permitted. While we do not believe the adoption of this statement will have a material effect on our financial statements, we continue to assess its potential impact on our financial statements.

Note 3 — Initial Public Offering of Cal Dive International, Inc.

In December 2006, we contributed the assets of our Shelf Contracting segment into Cal Dive, our then wholly owned subsidiary. Cal Dive subsequently sold approximately 22.2 million shares of its common stock in an initial public offering and distributed the net proceeds of $264.4 million to us as a dividend. In connection with the offering, CDI also entered into a $250 million revolving credit facility (Note 11). In December 2006, Cal Dive borrowed $201 million under the facility and distributed $200 million of the proceeds to us as a dividend. We recognized an after-tax gain of $96.5 million, net of taxes of $126.6 million as a result of these transactions. We used the proceeds for general corporate purposes. In connection with the offering, together with shares issued to CDI employees immediately after the offering, our ownership of CDI decreased to approximately 73.0% as of December 31, 2006. Our ownership in CDI was further reduced in December 2007 as a result of CDI’s stock issuance related to the Horizon acquisition (Note 5). Our ownership in CDI as of December 31, 2008 was approximately 57.2%. In January 2009, we sold CDI approximately 13.6 million shares of its common stock held by us for $86 million. Subsequent to this transaction, we held an approximate 51% ownership interest in CDI. See Note 25 for transactions that resulted in a substantial decrease in our ownership interest in CDI.

Index to Financial Statements

Further, in conjunction with the offering, the tax basis of certain CDI’s tangible and intangible assets was increased to fair value. The increased tax basis should result in additional tax deductions available to CDI over a period of two to five years. Under the Tax Matters Agreement with CDI, for a period of up to ten years to the extent CDI generates taxable income sufficient to realize the additional tax deductions, it will be required to pay us 90% of the amount of tax savings actually realized from the step-up of the assets. As of December 31, 2008 and 2007, we have a receivable from CDI of approximately $4.5 million and $6.2 million, respectively, related to the Tax Matters Agreement (Note 12).

Note 4 — Acquisition of Remington Oil and Gas Corporation

On July 1, 2006, we acquired 100% of Remington, an independent oil and gas exploration and production company headquartered in Dallas, Texas, with operations concentrated in the onshore and offshore regions of the Gulf Coast, for approximately $1.4 billion in cash and Helix common stock and the assumption of $358.4 million of liabilities. The merger consideration was 0.436 of a share of our common stock and $27.00 in cash for each share of Remington common stock. On July 1, 2006, we issued approximately 13.0 million shares of our common stock to Remington stockholders and funded the cash portion of the Remington acquisition (approximately $806.8 million) and transaction costs (approximately $18.5 million) through a credit.

The Remington acquisition was accounted for as a business combination with the acquisition price allocated to the assets acquired and liabilities assumed based upon their estimated fair values, with the excess being recorded in goodwill. The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition (in thousands):

Current assets	$	154,293
Property and equipment		863,935
Goodwill		712,392
Other intangible assets(1)		6,800
Total assets acquired	$	1,737,420

Current liabilities	$	130,409
Deferred income taxes		204,096
Decommissioning liabilities (including current portion)		22,137
Other non-current liabilities		1,800
Total liabilities assumed	$	358,442

Net assets acquired	$	1,378,978

(1)

The intangible asset was related to a favorable drilling rig contract and several non-compete agreements between the Company and certain members of senior management. The fair value of the drilling rig contract was $5.0 million at the date of the acquisition, which was capitalized as property and equipment following the drilling of certain successful exploratory wells in 2007. The fair value of the non-compete agreements was $1.8 million, which is being amortized over the term of the agreements (three years) on a straight-line basis, with $0.3 million remaining unamortized at December 31, 2008.

Our oil and gas segment includes the results of the Remington acquisition since the date of purchase. See Note 6 for pro forma combined operating results of the Company and the Remington acquisition for the year ended December 31, 2006.

Index to Financial Statements

Note 5 — Acquisition of Horizon Offshore, Inc.

On December 11, 2007, CDI acquired 100% of Horizon, a marine construction services company headquartered in Houston, Texas. Under the terms of the merger, each share of common stock, par value $0.00001 per share, of Horizon was converted into the right to receive $9.25 in cash and 0.625 shares of CDI’s common stock. All shares of Horizon restricted stock that had been issued but had not vested prior to the effective time of the merger became fully vested at the effective time of the merger and converted into the right to receive the merger consideration. CDI issued approximately 20.3 million shares of its common stock and paid approximately $300 million in cash to the former Horizon stockholders upon completion of the acquisition. The cash portion of the merger consideration was paid with cash on hand and $375 million of borrowings under CDI’s $675 million credit facility, which consists of the fully drawn $375 million senior secured term loan and an additional $300 million senior secured revolving credit facility (Note 11).

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

Cash	$	170,607
Other current assets		164,664
Property and equipment		336,147
Other long-term assets		15,133
Goodwill		265,668
Intangible assets		9,510
Total assets acquired	$	961,729

Current liabilities	$	184,678
Deferred income taxes		59,322
Long-term debt		87,641
Other non-current liabilities		100
Total liabilities assumed	$	331,741

Net assets acquired	$	629,988

The intangible assets relate to the fair value of contract backlog, customer relationships and non-compete agreements between CDI and certain members of Horizon’s senior management as follows (dollars in thousands):

	Fair Value		Amortization Period
Customer relationships	$	3,060	1.5 years
Contract backlog		2,960	5.0 years
Non-compete agreements		3,000	1.0 year
Trade name		490	9.0 years
Total	$	9,510

At December 31, 2008, the net carrying amount for these intangibles was $4.3 million.

Index to Financial Statements

The results of Horizon are included in our Shelf Contracting segment in the accompanying consolidated and combined statements of operations since the date of purchase. See Note 6 pro forma combined operating results of the Company and the Horizon acquisition for the years ended December 31, 2007 and 2006.

We recognized a non-cash pre-tax gain of $151.7 million ($98.6 million net of taxes of $53.1 million) in 2007 as our share of CDI’s underlying equity increased as a result of CDI’s issuance of 20.3 million shares of common stock to former Horizon stockholders, which reduced our ownership to 58.5%. The gain was calculated as the difference in the value of our investment in CDI immediately before and after CDI’s stock issuance. As disclosed in Note 3, our ownership of CDI decreased from the approximate 57% at December 31, 2008 to approximately 51% in January 2009.

Note 6 — Other Acquisitions

2007

Well Ops SEA Pty Ltd.

In October 2006, we acquired a 58% interest in Seatrac Pty Ltd. (“Seatrac”) for total consideration of approximately $12.7 million (including $0.2 million of transaction costs), with approximately $9.1 million paid to existing Seatrac shareholders and $3.4 million for subscription of new Seatrac shares. We renamed this entity Well Ops SEA Pty Ltd. (“WOSEA”). WOSEA is a subsea well intervention and engineering services company located in Perth, Australia. On July 1, 2007, we exercised an option to purchase the remaining 42% of WOSEA for approximately $10.1 million and potential additional consideration of approximately $4.6 million, which the former shareholders would be entitled to if WOSEA meets certain financial performance objectives over a five-year period commencing on our date of purchase. This purchase was accounted for as a business combination with the acquisition price allocated to the assets acquired and liabilities assumed based upon their estimated fair value, with the excess being recorded as goodwill. The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at July 1, 2007 (in thousands):

Cash and cash equivalents	$	2,631
Other current assets		4,279
Property and equipment		9,571
Goodwill		11,328
Total assets acquired	$	27,809

Accounts payable and accrued liabilities	$	5,059

Net assets acquired	$	22,750

Pro forma combined operating results for the years ended December 31, 2007 and 2006 (adjusted to reflect the results of operations of WOSEA prior to its acquisition) are not provided because the pre-acquisition results related to WOSEA were not material to the historical results of the Company.

Index to Financial Statements

2006

Fraser Diving International Ltd.

In July 2006, we acquired the business of Singapore-based Fraser Diving International Ltd. (“Fraser”) for an aggregate purchase price of approximately $29.3 million, subject to post-closing adjustments, and the assumption of $2.2 million of liabilities. Fraser owned six portable saturation diving systems and 15 surface diving systems that operate primarily in Southeast Asia, the Middle East, Australia and the Mediterranean. Included in the purchase price is a payment of $2.5 million made in December 2005 to Fraser for the purchase of one of the portable saturation diving systems. The acquisition was accounted for as a business combination with the acquisition price allocated to the assets acquired and liabilities assumed based upon their estimated fair values. The final valuation of net assets was completed in the second quarter of 2007. The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition (in thousands):

Cash and cash equivalents	$	2,332
Accounts receivable		1,817
Prepaid expenses and deposits		691
Portable saturation diving systems and surface diving systems		23,685
Diving support equipment, support facilities and other equipment		3,004
Total assets acquired	$	31,529

Accounts payable and accrued liabilities	$	2,243

Net assets acquired	$	29,286

The results of Fraser have been included in the accompanying consolidated statements of operations in our Shelf Contracting segment since the date of purchase. Pro forma combined operating results for the year ended December 31, 2006 (adjusted to reflect the results of operations of Fraser prior to its acquisition) are not provided because the pre-acquisition results related to Fraser were not material to the historical results of the Company.

Pro forma combined operating results of the Company and the Horizon and Remington acquisitions for the years ended December 31, 2007 and 2006 were presented as if the acquisitions had been completed as of January 1, 2006. The unaudited pro forma combined results were as follows (in thousands, except per share data):

	Year Ended December 31,
	2007		2006

Net revenues	$	2,115,016	$	2,001,812
Income before income taxes(1)		487,446		659,648
Net income applicable to Helix(1)		293,414		365,392
Net income applicable to Helix common shareholders(1)		289,698		362,034
Earnings per common share(1):
Basic	$	3.17	$	3.95
Diluted	$	3.03	$	3.77

(1)	Includes pre-tax gain of $151.7 million and $223.1 million related to CDI’s issuance of stock during the year ended December 31, 2007 and 2006, respectively. The taxes associated with this gain were approximately $53.1 million and $126.6 million, respectively.

Index to Financial Statements

Note 7 — Oil and Gas Properties

At December 31, 2007, we had certain capitalized exploratory drilling costs associated with ongoing exploration and/or appraisal activities. In the fourth quarter of 2008, we charged the costs associated with the Huey and Castleton exploration wells to dry hole exploration expense, when it became unlikely that we would pursue additional development of these wells. Other capitalized costs may be charged against earnings in future periods if management determines that commercial quantities of hydrocarbons have not been discovered or that future appraisal drilling or development activities are not likely to occur. The following table provides a detail of our capitalized exploratory project costs at December 31, 2008 and 2007 (in thousands):

		2008		2007
Huey	$	—	$	11,556
Castleton (part of Gunnison)		—		7,071
Wang		1,545		—
Other		560		469
Total	$	2,105	$	19,096

The following table reflects net changes in suspended exploratory well costs during the year ended December 31, 2008, 2007 and 2006 (in thousands):

		2008			2007			2006
Beginning balance at January 1,	$	19,096		$	49,983		$	12,014
Additions pending the determination of proved reserves		2,305			213,699			138,679
Reclassifications to proved properties		(463	)		(234,277	)		(62,375	)
Charged to dry hole expense		(18,833	)		(10,309	)		(38,335	)
Ending balance at December 31,	$	2,105		$	19,096		$	49,983

Further, the following table details the components of exploration expense for the years ended December 31, 2008, 2007 and 2006 (in thousands):

		Years Ended December 31,
		2008		2007		2006
Delay rental and geological and geophysical costs	$	5,223	$	6,538	$	4,780
Dry hole expense, including impairment of unproved properties		27,703		20,187		38,335
Total exploration expense	$	32,926	$	26,725	$	43,115

Our oil and gas activities in the United States are regulated by the federal government and require significant third-party involvement, such as refinery processing and pipeline transportation. We record revenue from our offshore properties net of royalties paid to the MMS. Royalty fees paid totaled approximately $66.3 million, $57.1 million and $41.0 million for the years ended December 31, 2008, 2007 and 2006, respectively. In accordance with federal regulations that require operators in the Gulf of Mexico to post an area wide bond of $3 million, the MMS has allowed us to fulfill such bonding requirements through an insurance policy.

In July 2006 we sold our interest in Atwater Block 63 (Telemark) and surrounding fields for $15 million in cash and we also retained a reservation of an overriding royalty interest in the Telemark development. We recorded a gain of $2.2 million in 2006 related to this sale.

In August 2006, we acquired a 100% working interest in the Typhoon oil field (Green Canyon Blocks 236/237), the Boris oil field (Green Canyon Block 282) and the Little Burn oil field (Green Canyon Block 238) for assumption of certain decommissioning liabilities. We have received suspension of production (“SOP”) approval from the MMS. We will also have farm-in rights on five near-by blocks where three prospects have been identified in the Typhoon mini-basin. Following the acquisition of the Typhoon field and MMS approval, we renamed the field Phoenix. We expect to deploy a minimal floating production system in 2010 in the Phoenix field.

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

In 2007, we incurred $25.1 million of plug and abandonment overruns related to hurricanes Katrina and Rita, partially offset by insurance recoveries of $4.0 million. In addition, we increased our abandonment liability at December 31, 2007 for work yet to be done for certain properties damaged by the hurricanes totaling $9.6 million, partially offset by estimated insurance recoveries of $4.9 million. Further, in 2006, we expensed inspection and repair costs related to damages sustained by Hurricanes Katrina and Rita for our oil and gas properties totaling approximately $16.8 million, partially offset by $9.7 million of insurance recoveries received. In 2005, we expensed approximately $7.1 million of inspection and repair costs as a result of damages caused by these hurricanes.

On September 30, 2007, we sold a 30% working interest in the Phoenix, Boris oilfield and the Little Burn oilfield (Green Canyon Block 238) to Sojitz GOM Deepwater, Inc. (“Sojitz”), a wholly owned subsidiary of Sojitz Corporation, for a cash payment of $40 million and the proportionate recovery of all past and future capital expenditures related to the re-development of the fields, excluding the conversion of the Helix Producer I, which we plan to use as a redeployable floating production unit (“FPU”). Proceeds of $51.2 million from the sale were collected in October 2007. Sojitz will also pay its proportionate share of the operating costs including fees payable for the use of the FPU. A gain of approximately $40.4 million was recorded in 2007.

Also in 2007, we recorded impairment expense of approximately $64.1 million related to our proved oil and gas properties primarily as a result of downward reserve revisions and weak end of life well performance in some of our domestic properties. In addition, we recorded approximately $9.9 million of impairment expense related to our unproved properties primarily due to management’s assessment that exploration activities would not commence prior to the respective lease expiration dates. Further, we expensed approximately $5.9 million of dry hole exploratory costs in fourth quarter related to our South Marsh Island 123 #1 well drilled in 2007 due to management’s decision not to execute previous development plans prior to the lease expiring. Lastly, 2007 depletion was impacted by certain producing properties that experienced significant proved reserve declines, thus causing a significant increase in the depletion rate for these properties.

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. As a result of these sales, we recognized a pre-tax gain of $91.6 million in the first half of 2008.

Index to Financial Statements

In May 2008, we sold all our interests in our onshore proved and unproved oil and gas properties located in the states of Texas, Mississippi, Louisiana, New Mexico and Wyoming (“Onshore Properties”) to an unrelated investor. We sold these Onshore Properties for cash proceeds of $47.3 million and recorded a related loss of $11.9 million in the second quarter of 2008. Proceeds from the sale of these properties were used to reduce amounts under our outstanding loans in May 2008. Included in the cost basis of the Onshore Properties was an $8.1 million allocation of goodwill from our Oil and Gas segment.

As a result of our unsuccessful development well in January 2008 on Devil’s Island (Garden Banks Block 344), we recognized impairment expense of $14.6 million in 2008 related to the cost incurred subsequent to December 31, 2007. The $20.9 million of the costs incurred related to this well through December 31, 2007, were charged to earnings in 2007.

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 involves damage to third party pipelines and onshore processing facilities. The timing of when these facilities reestablished 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 deductable 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 2008, we incurred hurricane-related repair cost totaling $22.8 million. As of December 31, 2008, the aggregate amount of hurricane reimbursements associated with Hurricanes Gustav and Ike totaled $12.1 million, with $4.3 million of this amount reflected as a reimbursement in the accompanying statements of operations and the remainder as a reduction of our property and equipment.

Note 8 — Details of Certain Accounts (in thousands)

Other current assets consisted of the following as of December 31, 2008 and 2007:

		2008		2007

Other receivables	$	22,977	$	6,490
Prepaid insurance		18,327		21,133
Other prepaids		23,956		14,294
Spare parts inventory		32,195		29,925
Current deferred tax assets		3,978		13,542
Hedging assets		26,800		1,424
Insurance claims to be reimbursed		7,880		10,173
Income tax receivable		23,485		8,365
Gas imbalance		7,550		6,654
Other		4,941		11,971
	$	172,089	$	123,971

Other assets, net, consisted of the following as of December 31, 2008 and 2007:

		2008		2007
Restricted cash	$	35,402	$	34,788
Deposits		1,890		8,417
Deferred drydock costs, net		38,620		47,964
Deferred financing costs		33,431		36,452
Intangible assets with finite lives		7,600		13,739
Intangible asset with indefinite life		—		—
Contracts receivable		—		14,635
Other		8,779		2,877
	$	125,722	$	158,872

Index to Financial Statements

Accrued liabilities consisted of the following as of December 31, 2008 and 2007:

		2008		2007
Accrued payroll and related benefits	$	46,224	$	50,389
Royalties payable		10,265		21,974
Current decommissioning liability		31,116		23,829
Unearned revenue		9,353		1,140
Billings in excess of costs		13,256		20,403
Insurance claims to be reimbursed		7,880		14,173
Accrued interest		34,299		7,090
Accrued severance(1)		1,953		14,786
Deposits		25,542		13,600
Hedging liability		7,687		10,308
Other		44,104		41,475
	$	231,679	$	219,167

(1)	Related to payments to be made to former Horizon personnel as a result of the acquisition by CDI.

Note 9 — Equity Investments

In June 2002, we formed Deepwater Gateway with Enterprise Products Partners, L.P., in which we each own a 50% interest, to design, construct, install, own and operate a tension leg platform “TLP” production hub in deepwater of the Gulf of Mexico. Deepwater Gateway primarily services the Marco Polo field, which is owned and operated by Anadarko Petroleum Corporation. Our share of the Deepwater Gateway construction costs was approximately $120 million and our investment totaled $106.3 million and $112.8 million as of December 31, 2008 and 2007, respectively, and was included in our Production Facilities segment. The investment balance at December 31, 2008 and 2007 included approximately $1.6 million and $1.7 million, respectively, of capitalized interest and insurance paid by us.

In December 2004, we acquired a 20% interest in Independence Hub, an affiliate of Enterprise. Independence Hub owns the Independence Hub platform located in Mississippi Canyon Block 920 in a water depth of 8,000 feet. The platform reached mechanical completion in May 2007. As a result, our performance guaranty related to Independence Hub terminated in May 2007 with no further obligations. First production began in July 2007. Our investment in Independence Hub was $90.2 million and $95.7 million as of December 31, 2008 and 2007, respectively (including capitalized interest of $5.9 million and $6.2 million at December 31, 2008 and 2007, respectively), and was included in our Production Facilities segment.

During 2007, CDI determined that there was an other than temporary impairment of its equity investment in OTSL and the full value of its investment was impaired. CDI recorded equity losses in OTSL of $10.8 million, inclusive of the impairment charge, and $0.5 million for the fiscal years ended December 31, 2007, and 2006, respectively. CDI sold its equity interest in OTSL to a third party in January 2009 for $0.4 million.

We made the following contributions to our equity investments during the years ended December 31, 2008, 2007 and 2006 (in thousands):

		Year Ended December 31,
		2008		2007		2006
Independence Hub	$	—	$	12,475	$	27,578
Other		846		4,984		—
Total	$	846	$	17,459	$	27,578

We received the following distributions from our equity investments during the years ended December 31, 2008, 2007 and 2006 (in thousands):

		Year Ended December 31,
		2008		2007		2006

Deepwater Gateway	$	23,500	$	27,000	$	16,250
Independence Hub		25,000		10,800		—
Total	$	48,500	$	37,800	$	16,250

Note 10 — Consolidated Variable Interest Entities

In October 2006, we partnered with Kommandor RØMØ, a Danish corporation to form Kommandor LLC, a Delaware limited liability company, whose purpose is to convert a ferry vessel into a dynamically-positioned construction services vessel. Upon completion of the conversion, this vessel will be leased to us under a bareboat charter and we plan to perform additional capital modifications in order to utilize the vessel for future use as a floating production system servicing the Deepwater Gulf of Mexico, with initial service being provided for the Phoenix field, in which we hold an approximate 70% working interest. The initial investment for our 50% interest in Kommandor LLC was $15 million. Further, we provided an initial loan facility of up to $84.7 million at December 31, 2008 and Kommandor RØMØ loaned $5 million to the entity for purposes of completing the conversion. The vessel is expected to be completed in two phases. The first phase, the initial conversion, is expected to be completed in second quarter 2009 and its total cost is estimated to range between $150 million and $160 million. The second phase, our capital modifications, is expected to be completed by early 2010. Estimated costs for the capital modifications to the vessel in the second phase, in which we expect to fund 100%, will range between $195 and $205 million.

The operating agreement with Kommandor RØMØ, provides that for a period of two months immediately following the fifth anniversary of the completion of the initial conversion, we may purchase Kommandor RØMØ’s membership interest at a value specified in the agreement (“Helix Option Period”). In addition, for a period of two months starting from 30 days after the Helix Option Period, Kommandor RØMØ can require us to purchase its share of the company at a value specified in the operating agreement. We estimate the cash outlay to Kommandor RØMØ for its interest in Kommandor LLC at the time the put or call is exercised to be approximately $28 million.

Kommandor LLC qualifies as a VIE under FIN 46 and we determined that we are the primary beneficiary and, thus, we have consolidated the financial results of Kommandor LLC as of December 31, 2008 and 2007. The results of Kommandor LLC are included in our Production Facilities segment. Kommandor LLC has been a development stage enterprise since its inception in October 2006.

Note 11 — Long-Term Debt

Senior Unsecured Notes

On December 21, 2007, we issued $550 million of 9.5% Senior Unsecured Notes due 2016 (“Senior Unsecured Notes”). 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 guarantee of our or any of our restricted subsidiaries’ indebtedness is also required to guarantee the Senior Unsecured Notes. CDI, the subsidiaries of CDI, and our foreign subsidiaries are not guarantors of the Senior Unsecured Notes. We used the proceeds from the Senior Unsecured Notes to repay outstanding indebtedness under our senior secured credit facilities (see below).

The Senior Unsecured Notes are junior in right of payment to all our existing and future secured indebtedness and obligations and rank equally in right of payment with all existing and future senior unsecured indebtedness of the Company. The Senior Unsecured Notes rank senior in right of payment to any of our future subordinated indebtedness and are fully and unconditionally guaranteed by the guarantors listed above on a senior basis.

The Senior Unsecured Notes mature on January 15, 2016. Interest on the Senior Unsecured Notes accrues at the fixed rate of 9.5% per annum and is payable semiannually in arrears on each January 15 and July 15, commencing July 15, 2008. Interest is computed on the basis of a 360-day year comprising twelve 30-day months.

Included in the Senior Unsecured Notes indenture are terms, conditions and covenants that are customary for this type of offering. The covenants include limitations on our and our subsidiaries’ ability to incur additional indebtedness, pay dividends, repurchase our common stock, and sell or transfer assets. As of December 31, 2008, we were in compliance with these covenants.

The Senior Unsecured Notes may be redeemed prior to the stated maturity under the following circumstances:

•

After January 15, 2012, we may redeem all or a portion of the Senior Unsecured Notes, on not less than 30 days’ nor more than 60 days’ prior notice, at the redemption prices (expressed as percentages of the principal amount) set forth below, plus accrued and unpaid interest, if any, thereon, to the applicable redemption date.

Year	Redemption Price
2012		104.750	%
2013		102.375	%
2014 and thereafter		100.000	%

•

In addition, at any time prior to January 15, 2011, we may use the net proceeds from any equity offering to redeem up to an aggregate of 35% of the total principal amount of Senior Unsecured Notes at a redemption price equal to 109.5% of the cumulative principal amount of the Senior Unsecured Notes redeemed, plus accrued and unpaid interest, if any, to the redemption date, provided that this redemption provision shall not be applicable with respect to any transaction that results in a change of control of the Company. At least 65% of the aggregate principal amount of Senior Unsecured Notes must remain outstanding immediately after the occurrence of such redemption.

In the event a change of control of the Company occurs, each holder of the Senior Unsecured Notes will have the right to require us to purchase all or any part of such holder’s Senior Unsecured Notes. In such event, we are required to offer to purchase all of the Senior Unsecured Notes at a purchase price in cash in an amount equal to 101% of the principal amount, plus accrued and unpaid interest, if any, to the date of purchase.

Senior Credit Facilities

On July 3, 2006, we entered into a credit agreement (the “Senior Credit Facilities”) under which we borrowed $835 million in a term loan (the “Term Loan”) and were initially able to borrow up to $300 million (the “Revolving Loans”) under a revolving credit facility (the “Revolving Credit Facility”). The proceeds from the Term Loan were used to fund the cash portion of the Remington acquisition. 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. On May 29, 2008, we completed a $120 million increase in the Revolving Credit Facility utilizing this accordion feature. Total borrowing capacity under the Revolving Credit Facility now totals $420 million. The full amount of the Revolving Credit Facility may be used for issuances of letters of credit.

Index to Financial Statements

The Term Loan and the Revolving Loans (together, the “Loans”) bear interest either to the Bank of America’s base rate or to LIBOR, at our election. Our current election is to bear interest based on LIBOR. The Term Loan or portions thereof bear interest at one, two, three or six-month LIBOR rate at our election plus an applicable margin of 2.00%. Our interest rate for year ended December 31, 2008 and 2007 was approximately 6.0% and 7.1%, respectively (including the effects of our interest rate swaps). The Revolving Loans or portions thereof bear interest based on one, two, three or six-month LIBOR rates or on Base Rate at our election plus an applicable 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 our consolidated leverage ratio as provided under the Credit Agreement.

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 scheduled quarterly principal payment was reduced from $2.1 million to $1.1 million. The Revolving Loans mature on July 1, 2011. We may elect to prepay amounts outstanding under the Term Loan without prepayment penalty, but may not reborrow any amounts prepaid. We may prepay amounts outstanding under the Revolving Loans without prepayment penalty, and may reborrow amounts prepaid prior to maturity. We had $44.4 million ($59.4 million as of February 27, 2009) and $240.8 million available under the Revolving Loans (including unsecured letters of credit of $26.1 million and $41.2 million) at December 31, 2008 and 2007, respectively. In addition, upon the occurrence of certain dispositions or the issuance or incurrence of certain types of indebtedness, we may be required to prepay a portion of the Term Loan equal to the amount of proceeds received from such occurrences. Such prepayments will be applied first to the Term Loan, and any remaining excess will then be applied to the Revolving Loans.

The Credit Agreement and the other documents entered into in connection with the Credit Agreement (together, the “Loan Documents”) include terms, conditions and covenants that we consider customary for this type of transaction. The covenants include restrictions on the Company’s and our subsidiaries’ ability to grant liens, incur indebtedness, make investments, merge or consolidate, sell or transfer assets and pay dividends. The credit facility also places certain annual and aggregate limits on expenditures for acquisitions, investments in joint ventures and capital expenditures. The Credit Agreement requires us to meet certain minimum financial ratios for interest coverage, consolidated leverage and, until we achieve investment grade ratings from S&P and Moody’s, collateral coverage.

If we or any of our subsidiaries do not pay any amounts owed to the Lenders under the Loan Documents when due, breach any other covenant to the Lenders or fail to pay other debt above a stated threshold, in each case, subject to applicable cure periods, then the Lenders have the right to stop making advances to us and to declare the Loans immediately due. The Credit Agreement includes other events of default that are customary for this type of transaction. As of December 31, 2008, we were in compliance with all debt covenants.

The Loans and our other obligations to the Lenders under the Loan Documents are guaranteed by all of our U.S. subsidiaries other than CDI and its subsidiaries and Cal Dive I-Title XI, Inc., and are secured by a lien on substantially all of our assets and properties and all the assets and properties of our U.S. subsidiaries, other than those of CDI and its subsidiaries and Cal Dive I-Title XI, Inc.. In addition, we have pledged a portion of the shares of our significant foreign subsidiaries to the lenders as additional security. The Senior Credit Facilities also contain provisions that limit our ability to incur certain types of additional indebtedness. These provisions effectively prohibit us from incurring any additional secured indebtedness or indebtedness guaranteed by the Company. The Senior Credit Facilities do however permit us to incur certain unsecured indebtedness, and also provide for our subsidiaries to incur project financing indebtedness (such as our MARAD loans) secured by the underlying asset, provided that the indebtedness is not guaranteed by us.

Index to Financial Statements

As the rates for our Term Loan are subject to market influences and will vary over the term of the credit agreement, we entered into various cash flow hedging interest rate swaps to stabilize cash flows relating to a portion of our interest payments for our Term Loan. The interest rate swaps were effective October 3, 2006, and qualified for hedge accounting. On December 21, 2007, a prepayment made to a hedged portion of our Term Loan brought the balance of that portion below the amount hedged by interest rate swaps. As a result, the hedge instruments became ineffective and no longer qualify for hedge accounting as of that date. The future changes in the fair value of these contracts will impact our future earnings as they occur.

Cal Dive International, Inc. Credit Facility

In December 2007, CDI replaced its five-year $250 million revolving credit facility by entering into a secured credit facility with a bank group led by Bank of America, N.A., which also serves as administrative agent, consisting of a $375 million term loan and a $300 million revolving credit facility. Both the term loan and the revolving loans mature on December 11, 2012. Loans under this CDI facility are non-recourse to us. The term loan and the revolving loans may consist of loans bearing interest in relation to the Federal Funds Rate or to Bank of America’s base rate, known as Base Rate Loans, and loans bearing interest in relation to a LIBOR rate, known as Eurodollar Rate Loans, in each case plus an applicable margin. The margins on the revolving loans range from 0.75% to 1.50% on Base Rate Loans and 1.75% to 2.50% on Eurodollar Rate Loans. The margins on the term loan are 1.25% on Base Rate Loans and 2.25% on Eurodollar Rate Loans. If a default exists, the interest rates may be increased.

The credit agreement and the other documents entered into in connection with the credit agreement include terms and conditions, including covenants, which we consider customary for this type of transaction. The covenants include restrictions on CDI and CDI’s subsidiaries’ ability to grant liens, incur indebtedness, make investments, merge or consolidate, sell or transfer assets and pay dividends. In addition, the credit agreement obligates CDI to meet minimum financial requirements specified in the agreement. 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 66% of the stock of two of CDI’s foreign subsidiaries, and a security interest in, among other things, all of CDI’s equipment, inventory, accounts and general intangible assets. At December 31, 2008, CDI was in compliance with all debt covenants.

On December 11, 2007, CDI borrowed $375 million under their term loan and used those proceeds to fund the cash portion of its merger consideration in connection with CDI’s acquisition of Horizon and to retire Horizon’s existing debt. The term loan requires quarterly principal payments of $20 million beginning June 20, 2008. For the years ended December 31, 2008 and 2007 there was $292.5 million and $273.3 million, respectively, available under the revolving credit facility (including $7.5 million and $26.7 million, respectively, of unsecured letters of credit). CDI expects to use the remaining availability under the revolving credit facility for its working capital and other general corporate purposes.

On January 26, 2009, CDI borrowed $100 million under its revolving credit facility to purchase from us shares of its common stock representing approximately 13.6 million shares at $6.34 per share. As of February 20, 2009, CDI has $186.7 million available under the revolving credit facility. CDI expects to use the remaining availability under its revolving credit facility for working capital and other general corporate purposes.

Index to Financial Statements

Convertible Senior Notes

In March 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. As a result of our two for one stock split in December 2005, the initial conversion rate of the Convertible Senior Notes of 15.56 shares of common stock per $1,000 principal amount of the Convertible Senior Notes, which was equivalent to a conversion price of approximately $64.27 per share of common stock, was changed to 31.12 shares of common stock per $1,000 principal amount of the Convertible Senior Notes equivalent to a conversion price of approximately $32.14 per share of common stock. We may redeem the Convertible Senior Notes on or after December 20, 2012. Beginning with the period commencing on December 20, 2012 to June 14, 2013 and for each six-month period thereafter, in addition to the stated interest rate of 3.25% per annum, we will pay contingent interest of 0.25% of the market value of the Convertible Senior Notes if, during specified testing periods, the average trading price of the Convertible Senior Notes exceeds 120% or more of the principal value. In addition, holders of the Convertible Senior Notes may require us to repurchase the notes at 100% of the principal amount on each of December 15, 2012, 2015, and 2020, and upon certain events. The effective interest rate for the Convertible Senior Notes was 6.6% following the adoption of FSP APB 14-1 (Note 2).

The Convertible Senior Notes can be converted prior to the stated maturity under the following circumstances:

	•		during any fiscal quarter (beginning with the quarter ended March 31, 2005) if the closing sale price of our common stock for at least 20 trading days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter exceeds 120% of the conversion price on that 30th trading day (i.e., $38.56 per share);
	•		upon the occurrence of specified corporate transactions; or
	•		if we have called the Convertible Senior Notes for redemption and the redemption has not yet occurred.

To the extent we do not have alternative long-term financing secured to cover such conversion notice, the Convertible Senior Notes would be classified as a current liability in the accompanying balance sheet.

In connection with any conversion, we will satisfy our obligation to convert the Convertible Senior Notes by delivering to holders in respect of each $1,000 aggregate principal amount of notes being converted a “settlement amount” consisting of:

	•		cash equal to the lesser of $1,000 and the conversion value; and
	•		to the extent the conversion value exceeds $1,000, a number of shares equal to the quotient of (A) the conversion value less $1,000, divided by (B) the last reported sale price of our common stock for such day.

The conversion value means the product of (1) the conversion rate in effect (plus any applicable additional shares resulting from an adjustment to the conversion rate) or, if the Convertible Senior Notes are converted during a registration default, 103% of such conversion rate (and any such additional shares), and (2) the average of the last reported sale prices of our common stock for the trading days during the cash settlement period. At December 31, 2008, the conversion trigger was not met; however, the trigger was met at December 31, 2007.

Index to Financial Statements

Our weighted average share price for 2008 was below the conversion price of $32.14 per share. The maximum number of shares of common stock which may be issued upon conversion of the Convertible Senior Notes is 13,303,770. We registered the 13,303,770 shares of common stock that may be issued upon conversion of the Convertible Senior Notes as well as an indeterminate number of shares of common stock issuable upon conversion of the Convertible Senior Notes by means of an antidilution adjustment of the conversion price pursuant to the terms of the Convertible Senior Notes. Proceeds from the offering were used to make a capital contribution of $72 million, made in March 2005, to Deepwater Gateway to enable it to repay its term loan, and strategic acquisitions in 2005 and for general corporate purposes.

MARAD Debt

At December 31, 2008 and 2007, $123.4 million and $127.5 million, respectively, was outstanding on our long-term financing used for construction of the Q4000. This U.S. Government guaranteed financing is pursuant to Title XI of the Merchant Marine Act of 1936 which is administered by the Maritime Administration (“MARAD Debt”). The MARAD Debt is payable in equal semi-annual installments which began in August 2002 and matures 25 years from such date. The MARAD Debt is collateralized by the Q4000, with us guaranteeing 50% of the debt, and initially bore interest at a floating rate which approximated AAA Commercial Paper yields plus 20 basis points. As provided for in the existing 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. At December 31, 2008, we are in compliance with these debt covenants.

Other

We paid financing costs associated with our issuance of debt totaling $2.2 million in 2008 and $17.2 million in 2007. Deferred financing costs of $33.4 million and $36.5 million at December 31, 2008 and 2007, respectively, are included within the caption “Other Assets, Net” in the accompanying consolidated balance sheets and are being amortized over the life of the respective agreements. In December 2007, as a result of prepaying $400 million of borrowing under our Term Loan, we charged $3.5 million to interest expense representing the proportionate share of the deferred financing cost related to the prepaid amount of the Term Loan.

Scheduled maturities of long-term debt and capital lease obligations outstanding as of December 31, 2008 were as follows (in thousands):

		Helix Term Loan			Helix Revolving Loans		CDI Term Loan			Senior Unsecured Notes		Convertible Senior Notes(1)			MARAD Debt			Loan Note(2)			Total
Less than one year	$	4,326		$	─	$	80,000		$	─	$	─		$	4,214		$	5,000		$	93,540
One to two years		4,326			─		80,000			─		─			4,424			—			88,750
Two to three years		4,326			349,500		80,000			─		─			4,645			—			438,471
Three to four years		4,326			─		75,000			─		─			4,877			—			84,203
Four to five years		401,789			─		─			─		─			5,120			—			406,909
Over five years		─			─		─			550,000		300,000			100,169			—			950,169
Total debt		419,093			349,500		315,000			550,000		300,000			123,449			5,000			2,062,042
Current maturities		(4,326	)		─		(80,000	)		─		─			(4,214	)		(5,000	)		(93,540	)
Long-term debt, less current maturities		414,767			349,500		235,000			550,000		300,000			119,235			─			1,968,502
Unamortized debt discount (3)		─			─		─			─		(34,816	)		─			─			(34,816	)
Long-term debt	$	414,767		$	349,500	$	235,000		$	550,000	$	265,184		$	119,235		$	─		$	1,933,686

Index to Financial Statements

(1)	Beginning in December 2012, we may at our option, repurchase notes or the holders may require repurchase of notes.

(2)	Represents the $5 million loan provided by Kommandor RØMØ to Kommandor LLC as of December 31, 2008.

(3)	Reflects unamortized debt discount on the convertible notes resulting from adoption of APB 14-1 on January 1, 2009 (Note 1). The initial discount on the convertible notes was $60.2 million. The notes will increase to $300 million face amount through accretion of non-cash interest charges through 2012. The amount of the unamortized discount totaled $34.8 million at December 31, 2008 and $42.2 million at December 31, 2007.

We had unsecured letters of credit outstanding at December 31, 2008 totaling approximately $33.7 million. These letters of credit primarily guarantee various contract bidding and insurance activities. The following table details our interest expense and capitalized interest for the years ended December 31, 2008, 2007 and 2006 (in thousands):

		Year Ended December 31,
		2008			2007			2006
Interest expense	$	136,989		$	107,752		$	58,833
Interest income		(2,416	)		(9,231	)		(6,259	)
Capitalized interest		(42,125	)		(31,790	)		(10,609	)
Interest expense, net	$	92,448		$	66,731		$	41,965

Note 12 — Income Taxes

We and our subsidiaries, including acquired companies from their respective dates of acquisition, file a consolidated U.S. federal income tax return. At December 13, 2006, CDI was separated from our tax consolidated group as a result of its initial public offering. As a result, we are required to accrue income tax expense on our share of CDI’s net income after the initial public offering in all periods where we consolidate their operations. The deconsolidation of CDI’s net income after its initial public offering did not have a material impact on our consolidated results of operations; however, because of our inability to recover our tax basis in CDI tax free, a long term deferred tax liability is provided for any incremental tax increases to the book over tax basis.

We conduct our international operations in a number of locations that have varying laws and regulations with regard to taxes. Management believes that adequate provisions have been made for all taxes that will ultimately be payable. Income taxes have been provided based on the US statutory rate of 35% adjusted for items which are allowed as deductions for federal income tax reporting purposes, but not for book purposes. The primary differences between the statutory rate and our effective rate were as follows:

	Year Ended December 31,
	2008		2007		2006
Statutory rate	35.0	%	35.0	%	35.0	%
Gain on subsidiary equity transaction	─		─		8.0
Foreign provision	2.6		(1.4	)	─
Percentage depletion in excess of basis	─		─		(0.1	)
IRC Section 199 deduction	0.7		(0.2	)	(0.2	)
CDI equity pick up in excess of tax basis	(4.2	)	─		─
Nondeductible goodwill impairment	(50.0	)	─		─
Other	(1.7	)	(0.1	)	─
Effective rate	(17.6	)%	33.3	%	42.7	%

Index to Financial Statements

Components of the provision (benefit) for income taxes reflected in the statements of operations consisted of the following (in thousands):

		Year Ended December 31,
		2008			2007		2006
Current	$	92,181		$	46,780	$	197,479
Deferred		(5,402	)		125,082		55,274
	$	86,779		$	171,862	$	252,753

		Year Ended December 31,
		2008		2007		2006
Domestic	$	42,780	$	147,219	$	245,166
Foreign		43,999		24,643		7,587
	$	86,779	$	171,862	$	252,753

Deferred income taxes result from the effect of transactions that are recognized in different periods for financial and tax reporting purposes. The nature of these differences and the income tax effect of each as of December 31, 2008 and 2007 are as follows (in thousands):

		2008			2007
Deferred tax liabilities:
Depreciation and Depletion	$	638,363		$	580,185
Subsidiary book basis in excess of tax		71,048			50,339
Equity investments in production facilities		41,839			35,288
Prepaid and other		57,230			74,007
Total deferred tax liabilities	$	808,480		$	739,819

Deferred tax assets:
Net operating loss carryforward	$	(3,533	)	$	(19,933	)
Decommissioning liabilities		(150,337	)		(65,685	)
Reserves, accrued liabilities and other		(46,401	)		(31,425	)
Total deferred tax assets	$	(200,271	)	$	(117,043	)
Valuation allowance		3,317			2,967

Net deferred tax liability	$	611,526		$	625,743

Deferred income tax is presented as:
Current deferred tax asset	$	(3,978	)	$	(13,542	)
Noncurrent deferred tax liabilities		615,504			639,285
Net deferred tax liability	$	611,526		$	625,743

As a result of the Remington acquisition on July 1, 2006, a deferred tax asset was recorded as a part of the purchase price allocation to reflect the availability of approximately $65.2 million of net operating loss carryforwards as of the acquisition date. As a result of Helix’s federal taxable income position during 2006 and 2008, we were able to utilize all of the $65.2 million of the net operating loss carryforwards at December 31, 2008. At December 31, 2007 Helix had a $28.0 million net operating loss, $1.3 million alternative minimum credit, $8.3 million foreign tax credit and $1 million general business credit, which were fully utilized in 2008. At December 31, 2008, CDI had $10.1 million in net operating loss carryforwards, which begin to expire in 2016.

Index to Financial Statements

We consider the undistributed earnings of our principal non-U.S. subsidiaries to be permanently reinvested. At December 31, 2008 and 2007, our principal non-U.S. subsidiaries had accumulated earnings and profits of approximately $127.8 million and $55.1 million, respectively. We have not provided deferred U.S. income tax on the accumulated earnings and profits. Alternatively, as a result of our inability to recover our tax basis in CDI tax free, we have provided a deferred tax liability on the incremental increases to the book over tax basis.

We adopted the provisions of FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes (“FIN 48”) on January 1, 2007. The impact of the adoption of FIN 48 was immaterial to our financial position, results of operations and cash flows. We account for tax related interest in interest expense and tax penalties in operating expenses as allowed under FIN 48. During 2008, we recorded a $5.4 million long term liability for uncertain tax benefits, interest and penalty. We recorded a $5.0 million increase to goodwill as part of the Horizon purchase price allocation and $0.4 million was recorded as income tax expense. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in thousands):

		Liability for Unrecognized Tax Benefits
Gross unrecognized tax benefits at January 1, 2008	$	640
Increases in tax positions for current years		2,643
Increases in tax positions for prior years		1,900
Gross unrecognized tax benefits at December 31, 2008	$	5,183

The total amount of tax benefits that, if recognized, would affect the effective tax rate was $5.2 million at December 31, 2008. At December 31, 2008, CDI accrued $3.5 million of interest and penalties related to unrecognized tax benefits.

We file tax returns in the U.S. and in various state, local and non-U.S. jurisdictions. We anticipate that any potential adjustments to our state, local and non-U.S. jurisdiction tax returns by tax authorities would not have a material impact on our financial position. The tax periods ending December 31, 2002, 2003, 2005, 2006, 2007 and 2008 remain subject to examination by the U.S. Internal Revenue Service (“IRS”). In addition, as we acquired Remington on July 1, 2006 we are exposed to any tax uncertainties related to Remington. For Remington, the tax period ending June 30, 2006 remains subject to examination by the IRS. The 2004 and 2005 tax returns for Remington were examined by the IRS and the examination was concluded with no adjustment.

During the fourth quarter of 2006, Horizon received a tax assessment from the 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 financial position and results of operations. Horizon’s 2002 through 2007 tax years remain subject to examination by the appropriate governmental agencies for Mexico tax purposes, with 2002 through 2004 currently under audit.

In December 2006, we entered into the Tax Matters Agreement with CDI in connection with the CDI initial public offering. The following is a summary of the material terms of the Tax Matters Agreement:

	•		Liability for Taxes. Each party has agreed to indemnify the other in respect of all taxes for which it is responsible under the Tax Matters Agreement. We are generally responsible for all federal, state, local and foreign income taxes that are imposed on or are attributable to CDI or any of its subsidiaries for all tax periods (or portions thereof) ending on or before CDI’s initial public offering. CDI is generally responsible for all federal, state, local and foreign income taxes that are imposed on or are attributable to CDI or any of its subsidiaries for all tax periods (or portions thereof) beginning after its initial public offering. CDI is also responsible for all taxes other than income taxes imposed on or attributable to CDI or any of its subsidiaries for all tax periods.
	•		Tax Benefit Payments. As a result of certain taxable income recognition by us in conjunction with the CDI initial public offering, CDI will become entitled to certain tax benefits that are expected to be realized by CDI in the ordinary course of its business and otherwise would not have been available to CDI. These benefits are generally attributable to increased tax deductions for amortization of tangible and intangible assets and to increased tax basis in nonamortizable assets. Under the Tax Matters Agreement, for a period of up to ten years, CDI will be required to make annual payments to us equal to 90% of the amount of taxes which CDI saves for each tax period as a result of these increased tax benefits. The timing of CDI’s payments to us under the Tax Matters Agreement will be determined with reference to when CDI actually realizes the projected tax savings. This timing will depend upon, among other things, the amount of their taxable income and the timing at which certain assets are sold or disposed.
	•		Preparation and Filing of Tax Returns. We will prepare and file all income tax returns that include CDI or any of its subsidiaries if we are responsible for any portion of the taxes reported on such tax returns. The Tax Matters Agreement also provides that we will have the sole authority to respond to and conduct all tax proceedings (including tax audits) relating to such income tax returns.

For the year ended December 31, 2008, this agreement did not have a material impact on our consolidated results of operations.

Index to Financial Statements

Note 13 — Convertible Preferred Stock

The Fletcher Agreement provides that if the volume weighted average price of our common stock on any date is 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. As a result of the redemption that occurred in January, the maximum number of shares available for redemption of Series A-1 Cumulative Convertible Stock is 9,035,038. 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 Fletcher’s redemption in January 2009, and the reset of the conversion price, Fletcher would receive an aggregate of 9,035,038 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. Under the existing terms of our Senior Credit Facilities (Note 11) we are not permitted to deliver cash to the holder upon a conversion or redemption of the Convertible Preferred Stock.

The preferred stock has a minimum annual dividend rate of 4%, subject to adjustment, payable quarterly in cash. The dividend rate for the years ended December 31, 2008, 2007 and 2006 was 4% (calculated rate was 3.7%, below the 4% minimum), 6.4% and 6.9%, respectively. At the time these dividends were paid we had the option to pay them in our common stock; we paid them in cash.

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 prices ($15.00 and $15.27).

Index to Financial Statements

Note 14 — Employee Benefit Plans

Defined Contribution Plan

We sponsor a defined contribution 401(k) retirement plan covering substantially all of our employees. Our contributions are in the form of cash and are determined annually as 50 percent of each employee’s contribution up to 5 percent of the employee’s salary. Our costs related to this plan totaled $3.0 million, $2.8 million and $2.3 million for the years ended December 31, 2008, 2007 and 2006, respectively. Costs related to the CDI 401(k) retirement plan totaled $2.1 million in 2008, $1.4 million in 2007 and $1.4 million in 2006.

Stock-Based Compensation Plans

We have three stock-based compensation plans: the 1995 Long-Term Incentive Plan, as amended (the “1995 Incentive Plan”), the 2005 Long-Term Incentive Plan (the “2005 Incentive Plan”) and the 1998 Employee Stock Purchase Plan (the “ESPP”). 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 December 31, 2008, there were approximately 2.3 million shares available for grant under our 2005 Incentive Plan.

Upon adoption of the 1995 Incentive Plan in May 1995, a maximum of 10% of the total shares of common stock issued and outstanding were eligible to be granted to key executives and selected employees and non-employee members of the Board of Directors. Following the approval by shareholders of the 2005 Incentive Plan in May 2005, no further grants have been or will be made under the 1995 Plan. The aggregate number of shares that may be granted under the 2005 Incentive Plan is 6,000,000 shares (after adjustment for the December 2005 two-for-one stock split) of which 4,000,000 shares may be granted in the form of restricted stock or restricted stock units and 2,000,000 shares may be granted in the form of stock options. The 1995 and 2005 Incentive Plans and the ESPP are administered by the Compensation Committee of the Board of Directors, which in the case of the 1995 and 2005 Incentive Plans, determines the type of award to be made to each participant, and as set forth in the related award agreement, the terms, conditions and limitations applicable to each award. The committee may grant stock options, restricted stock, restricted stock units, and cash awards. Awards granted to employees under the 1995 and 2005 Incentive Plan typically vest 20% per year over a five-year period (or in the case of certain stock option awards under the 1995 Incentive Plan, 33% per year for a three-year period); if in the form of stock options, have a maximum exercise life of ten years; and, subject to certain exceptions, are not transferable.

We account for our stock-based compensation plans under Statement of Financial Accounting Standards No. 123 (Revised 2004) Share-Based Payments (“SFAS 123R”). We continue to use the Black-Scholes option pricing model for valuing share-based payments relating to stock options 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 utilized the modified-prospective method of adoption. Under that transition method, compensation cost recognized in 2006 included: (a) compensation cost for all share-based payments granted prior to, but not yet vested as of January 1, 2006, based on the grant-date fair value, and (b) compensation cost for all share-based payments granted subsequent to January 1, 2006, based on the grant-date fair value. 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. We did not grant any stock options in 2008, 2007 or 2006.

Stock Options

The options outstanding at December 31, 2008, have exercise prices as follows: 139,000 shares at $8.57; 82,774 shares at $10.92; 30,400 shares at $10.94; 30,000 shares at $11.00; 127,680 shares at $12.18; 52,800 shares at $13.91; and 59,000 shares ranging from $8.14 to $10.59, and a weighted average remaining contractual life of 3.9 years.

Index to Financial Statements

Options outstanding are as follows:

	2008					2007					2006
	Shares			Weighted Average Exercise Price		Shares			Weighted Average Exercise Price		Shares			Weighted Average Exercise Price
Options outstanding at beginning of year		736,550		$	10.55		883,070		$	10.86		1,717,904		$	10.91
Exercised		(214,896	)	$	10.28		(141,186	)	$	11.10		(792,394	)	$	11.21
Terminated		—			—		(5,334	)	$	10.92		(42,440	)	$	10.96
Options outstanding at end of year		521,654		$	10.66		736,550		$	10.55		883,070		$	10.86
Options exercisable end of year		473,054		$	10.44		537,514		$	10.28		515,318		$	10.34

For the years ended December 31, 2008, 2007 and 2006, $1.1 million (of which $0.6 million of compensation expense was recognized in the first half of 2008 related to the acceleration of unvested options per the separation agreements between the Company and two of our former executive officers), $1.0 million and $1.4 million, respectively, was recognized as compensation expense related to stock options. The aggregate intrinsic value of the stock options exercised in 2008, 2007 and 2006 was approximately $5.9 million, $4.1 million and $21.3 million, respectively. Future compensation cost associated with unvested options at December 31, 2008 and 2007 totaled approximately $0.1 million and $0.8 million, respectively. There was no aggregate intrinsic value of options exercisable at December 31, 2008 as the fair market value at year end was lower than the exercise price of the vested stock options. The aggregate intrinsic value of options exercisable at December 31, 2007 was approximately $16.8 million. The weighted average vesting period related to nonvested stock options at December 31, 2008 was approximately 0.2 years.

Restricted Shares

We grant restricted shares to members of our board of directors, all executive officers and selected management employees. Compensation cost for each award is the product of grant date market value of each share and the number of shares granted. The following table summarizes information about our restricted shares during the years ended December 31, 2008, 2007 and 2006:

	2008			2007			2006
	Shares		Grant Date Fair Value(1)	Shares		Grant Date Fair Value(1)	Shares		Grant Date Fair Value(1)
Restricted shares outstanding at beginning of year	1,166,077		$32.19	729,212		$ 32.29	384,902		$ 25.59
Granted	702,190		$34.01	702,297		$ 31.77	497,450		$ 37.07
Vested	(386,963	)	$31.19	(236,667	)	$ 31.32	(66,865	)	$ 24.51
Forfeited	(274,778	)	$35.40	(28,765	)	$ 31.59	(86,275	)	$ 36.04
Restricted shares outstanding at end of year	1,206,526		$32.84	1,166,077		$ 32.19	729,212		$ 32.29

(1)	Represents the average grant date market value, which is based on the quoted market price of the common stock on the business day prior to the date of grant.

For the years ended December 31, 2008, 2007 and 2006, $18.5 million (of which $3.6 million was related to the accelerated vesting of restricted shares per the separation agreements between the Company and two of our former executive officers during the first half of 2008), $11.7 million and $6.3 million, respectively, was recognized as compensation expense related to restricted shares. In 2008 and 2007, compensation expense of $4.8 and $2.1 million, respectively, was related to the CDI Incentive Plan. Future compensation cost associated with unvested restricted stock awards at December 31, 2008 and 2007 totaled approximately $53.3 million and $41.8 million, respectively, of which $23.4 million and $13.4 million is related to the CDI Incentive Plan. The weighted average vesting period related to nonvested restricted stock awards at December 31, 2008 was approximately 3.4 years.

Index to Financial Statements

In January 2009, we granted executive officers and select management employees 343,368 and 26,506 restricted shares and restricted stock units, respectively, under the 2005 Long-Term Incentive Plan. The shares and units vest 20% per year for a five-year period. The market value of the restricted stock is based on the quoted market price of the common stock on the business day prior to the grant date. The market value of the restricted shares was $7.24 per share or $2.5 million. We also granted certain of our outside directors 10,617 restricted shares. The shares vest on January 1, 2011. The market value of the restricted shares was $7.24 per share or $76,867.

Employee Stock Purchase Plan

In May 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% of the fair market value of the common stock on either the first or last day of the subscription period, whichever is lower. Purchases under the plan are limited to the lesser of 10% of an employee’s base salary or $25,000 of our stock value. Shares of our common stock issued to our employees under the ESPP totaled 98,933 shares in 2008 and 222,984 in 2007. In 2007, we subsequently repurchased approximately the same number of shares of our common stock in the open market at a weighted average price of $35.04 per share and reduced the number of shares of our outstanding common stock. Under this plan 97,598 shares of common stock were purchased in the open market for our employees at a weighted-average share price of $33.12 during 2006. For the years ended December 31, 2008, 2007 and 2006, we recognized $1.8 million, $2.1 and $1.6 million, respectively, of compensation expense related to stock purchased under the ESPP and the CDI ESPP (of which $1.2 million and $0.6 million of expense for the years ended December 31, 2008 and 2007, respectively, was related to the CDI ESPP that became effective in the third quarter of 2007).

In January 2009, we issued 25,393 shares of our common stock to our employees under this plan to satisfy the employee purchase period from July 1, 2008 to December 31, 2008, which increased our common stock outstanding. There are no longer any shares available under this plan.

Stock Compensation Modifications

Under our 1995 Incentive Plan and our 2005 Long-Term Incentive Plan, upon a stock recipient’s termination of employment, which is defined as employment with us and any of our majority-owned subsidiaries, any unvested restricted stock and stock options are forfeited immediately, and all unexercised vested options are forfeited as specified under the applicable plan or agreement. Ordinarily, once our beneficial ownership of CDI falls to 50% or below (the “Trigger Date”), the options and unvested shares granted to CDI employees would be forfeited at such date under our current plans. As part of the Employee Matters Agreement between us and CDI, which was executed in December 2006, with respect to any employee who is a Cal Dive employee as of the date of the IPO, we have agreed to extend the life of any vested and unexercised stock options to the earlier of (1) the expiration of the general term of the option or (2) the later of (i) December 31 of the calendar year in which the Trigger Date occurs, or (ii) the 15th day of the third month after the expiration of the 60-day period commencing on the Trigger Date (135 days). To the extent that any such employee would forfeit options because they have not vested as of such date, such options will be accelerated and will vest at the Trigger Date. In addition, under the Employee Matters Agreement, restricted stock awards granted to employees of CDI as of the IPO closing date will continue under their present terms and the terms of the plans under which they were granted. The modification date for these restricted stock and options occurred at the date the Employee Matters Agreement was adopted. However, no accounting charge will occur until the Trigger Date occurs and the impact of the modification, if any, can be measured.

Index to Financial Statements

Note 15 — Shareholders’ Equity

Our amended and restated Articles of Incorporation provide for authorized Common Stock of 240,000,000 shares with no stated par value per share and 5,000,000 shares of preferred stock, $0.01 par value per share issuable in one or more series.

The components of accumulated other comprehensive income (loss) as of December 31, 2008 and 2007 were as follows (in thousands):

		2008			2007
Cumulative foreign currency translation adjustment	$	(42,874	)	$	28,260
Unrealized gain (loss) on hedges, net		9,178			(6,998	)
Accumulated other comprehensive income (loss)	$	(33,696	)	$	21,262

Note 16 — Stock Buyback Program

In June 2006, our Board of Directors authorized us to discretionarily purchase up to $50 million of our common stock in the open market. In October and November 2006, we purchased approximately 1.7 million shares under this program for a weighted average price of $29.86 per share, or $50.0 million thus ending the program.

Note 17 — Related Party Transactions

Cal Dive International, Inc.

We have provided Cal Dive certain management and administrative services including: (i) accounting, treasury, payroll and other financial services; (ii) legal, insurance and claims services; (iii) information systems, network and communication services; (iv) employee benefit services (including direct third-party group insurance costs and 401(k) contribution matching costs discussed below); and (v) corporate facilities management services. Total allocated costs to Cal Dive for such services were approximately $4 million, $3.6 million and $16.5 million for the years ended December 31, 2008, 2007 and 2006, respectively.

Included in these costs are costs related to the participation by CDI’s employees in our employee benefit plans through December 31, 2007, including employee medical insurance and a defined contribution 401(k) retirement plan. These costs were recorded as a component of operating expenses and were approximately $9.2 million and $5.8 million for the years ended December 31, 2007 and 2006, respectively. Our defined contribution 401(k) retirement plan is further disclosed in Note 14.

In addition, through December 31, 2007, Cal Dive provided to us operational and field support services including: (i) training and quality control services; (ii) marine administration services; (iii) supply chain and base operation services; (iv) environmental, health and safety services; (v) operational facilities management services; and (vi) human resources. Total allocated costs to us for such services were approximately $3.4 million and $5.6 million for the years ended December 31, 2007 and 2006, respectively. These amounts are eliminated in the accompanying consolidated financial statements.

In contemplation of the IPO of CDI, we entered into intercompany agreements with CDI that address the rights and obligations of each respective company, including a Master Agreement, a Corporate Services Agreement, an Employee Matters Agreement and a Tax Matters Agreement. The Master Agreement describes and provides a framework for the separation of our business from CDI’s business, allocates liabilities (including potential liabilities related to litigation) between the parties, allocates responsibilities and provides standards for each of the parties’ conduct going forward (e.g., coordination regarding financial reporting), and sets forth the indemnification obligations of each party to the other. In addition, the Master Agreement provides us with a preferential right to use a specified number of CDI’s vessels in accordance with the terms of such agreement.

Index to Financial Statements

Pursuant to the Corporate Services Agreement, each party agrees to provide specified services to the other party, including administrative and support services for the time period specified therein. Generally after we cease to own more than 50% of the total voting power of CDI common stock, all services may be terminated by either party upon 60 days notice, but a longer notice period is applicable for selected services. Each of the services shall be provided in exchange for a monthly charge as calculated for each service (based on relative revenues, number of users for a particular service, or other specified measure). In general, under the Corporate Services Agreement as originally entered into by the parties we provide CDI with services related to the tax, treasury, audit, insurance (including claims) and information technology functions; CDI provides us with services related to the human resources, training and orientation functions, and certain supply chain and environmental, health and safety services. However, the Corporate Services Agreement was amended effective January 1, 2008 and effective January 1, 2009 to reflect that CDI no longer provides us with these functions, and to reflect that we only provide CDI with certain information technology and insurance services.

Pursuant to the Employee Matters Agreement, except as otherwise provided, CDI generally accepts and assumes all employment related obligations with respect to all individuals who are employees of CDI as of the IPO closing date, including expenses related to existing options and restricted stock. Those employees are entitled to retain their Helix stock options and restricted stock grants under their original terms except as mandated by applicable law. The Employee Matters Agreement also permitted CDI employees to participate in our Employee Stock Purchase Plan for the offering period that ended June 30, 2007, and CDI paid us $1.6 million in July 2007, which was the fair market value of the shares of our stock purchased by such employees.

Pursuant to the Tax Matters Agreement, we are generally responsible for all federal, state, local and foreign income taxes that are attributable to CDI for all tax periods ending on the IPO; CDI is generally responsible for all such taxes beginning after the IPO. In addition, the agreement provides that for a period of up to ten years, CDI is required to make annual payments to us equal to 90% of tax benefits derived by CDI from tax basis adjustments resulting from the “Boot” gain recognized by us as a result of the distributions made to us as part of the IPO transaction. See Note 12 for more detailed disclosure of the Tax Matters Agreement.

Other

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. Production from the Gunnison field commenced in December 2003. We have made payments to OKCD totaling $21.6 million, $22.1 million and $34.6 million in the years ended December 31, 2008, 2007 and 2006 respectively. Our Chief Executive Officer, Owen Kratz, through Class A limited partnership interests in OKCD, personally owns approximately 74% of the partnership. Martin Ferron, our former President and Chief Executive Officer, owns approximately 1.1% of the partnership and A. Wade Pursell, our former Executive Vice President and Chief Financial Officer, owns approximately .43% of the partnership. In 2000, OKCD also awarded Class B limited partnership interests to key Helix employees.

During 2008, 2007 and 2006, we paid $3.4 million, $12.3 million and $6.1 million, respectively, to Weatherford International, Ltd. (“Weatherford”), an oil and gas industry company, for services provided to us. A member of our board of directors is part of the senior management team of Weatherford. During 2008, we paid $0.2 million to Tesco Corporation (“Tesco”) for services provided to us. A current member of our executive management team is a former member of Tesco’s executive management team.

Index to Financial Statements

Note 18 — Commitments and Contingencies

Lease Commitments

We lease several facilities, ROVs and vessels under noncancelable operating leases. Future minimum rentals under these leases are approximately $191.6 million at December 31, 2008 with $84.9 million due in 2009, $40.4 million in 2010, $35.3 million in 2011, $17.6 million in 2012, $4.0 million in 2013 and $9.4 million thereafter. Total rental expense under these operating leases was approximately $59.6 million, $76.0 million and $25.3 million for the years ended December 31, 2008, 2007 and 2006, respectively.

Insurance

We carry Hull and Increased Value insurance which provides coverage for physical damage up to an agreed amount for each vessel. The deductibles are based on the value of the vessel with a maximum deductible of $1.0 million on the Q4000 and Well Enhancer and $500,000 on the Intrepid, Seawell, Express and Kestrel. Other vessels carry deductibles between $25,000 and $350,000. We also carry Protection and Indemnity (“P&I”) insurance which covers liabilities arising from the operation of the vessels and General Liability insurance which covers liabilities arising from construction operations. The deductible on both the P&I and General Liability is $100,000 per occurrence. Onshore employees are covered by Workers’ Compensation. Offshore employees, including divers and tenders and marine crews, are covered by Maritime Employers Liability insurance policy which covers Jones Act exposures and includes a deductible of $100,000 per occurrence plus a $2.0 million annual aggregate deductible. In addition to the liability policies named above, we currently carry various layers of Umbrella Liability for total limits of $500 million excess of primary limits. Our self-insured retention on our medical and health benefits program for employees is $250,000 per participant.

We incur workers’ compensation and other insurance claims in the normal course of business, which management believes are covered by insurance. The Company analyzes each claim for potential exposure and estimates the ultimate liability of each claim. Our liability at December 31, 2008 and 2007, above the applicable deductible limits, were $7.9 million and $14.2 million, respectively. The related receivable from insurance companies at December 31, 2008 and 2007 were $7.9 million and $10.2 million, respectively. These amounts are reflected in Accrued Liabilities and Other Current Assets in the consolidated balance sheet (Note 8). We have not incurred any significant losses as a result of claims denied by our insurance carriers. Our services are provided in hazardous environments where accidents involving catastrophic damage or loss of life could occur, and litigation arising from such an event may result in our being named a defendant in lawsuits asserting large claims. Although there can be no assurance the amount of insurance we carry is sufficient to protect us fully in all events, or that such insurance will continue to be available at current levels of cost or coverage, we believe that our insurance protection is adequate for our business operations. A successful liability claim for which we are underinsured or uninsured could have a material adverse effect on our business.

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 only 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 May 2006 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

Index to Financial Statements

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. As a result of this dispute, we have recorded reserves for the disputed royalties (and any other royalties that may be claimed for production during 2005, 2006 and 2007) plus interest at 5% for our portion of the Gunnison related MMS claim. The total reserved amount at December 31, 2008 was approximately $69.7 million and is included in Other Long-Term Liabilities in the accompanying consolidated balance sheet. 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.

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

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 $158.9 million had been incurred, with an additional $11.8 million committed, at December 31, 2008. We expect the Caesar 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 costs for the Well Enhancer is expected to range between $200 million and $220 million. We expect the Well Enhancer to join our fleet in the second quarter 2009. At December 31, 2008, we had incurred approximately $149.7 million, with an additional $31.2 million committed to this project.

Index to Financial Statements

Further, we, along with Kommandor Rømø, a Danish corporation, formed a joint venture company called Kommandor LLC 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 $150 million and $160 million. We have provided $84.7 million in construction financing through December 31, 2008 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, scheduled for second quarter 2009, we will charter 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 field. The cost of these additional facilities is estimated to range between $195 million and $205 million and the work is expected to be completed in early 2010. As of December 31, 2008, approximately $210.1 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 $4.9 million committed. The total estimated cost of the vessel, initial conversion and the additional facilities will range approximately between $345 million and $365 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 thus have consolidated the financial results of Kommandor LLC as of December 31, 2008 in our Production Facilities segment. Kommandor LLC has been a development stage enterprise since its formation in October 2006.

As of December 31, 2008, we have also committed approximately $106.3 million in additional capital expenditures for exploration, development and drilling costs related to our oil and gas properties.

Note 19 — Business Segment Information

Our operations are conducted through the following lines of business: contracting services operations and oil and gas operations. We have disaggregated our contracting services operations into three reportable segments in accordance with SFAS No. 131: Contracting Services, Shelf Contracting and Production Facilities. As a result, our reportable segments consist of the following: Contracting Services, Shelf Contracting, Oil and Gas and Production Facilities. Contracting Services operations include deepwater pipelay, well operations, robotics and reservoir and well tech services. Shelf Contracting operations consist of CDI, which include all 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 (Deepwater Gateway and Independence Hub) are accounted for under the equity method of accounting. Our investment in Kommandor LLC was consolidated in accordance with FIN 46 and is included in our Production Facilities segment.

Index to Financial Statements

The following summarizes certain financial data by business segment:

		Year Ended December 31,
		2008			2007			2006
		(in thousands)
Revenues ─
Contracting Services	$	961,926		$	673,808		$	446,458
Shelf Contracting		856,906			623,615			509,917
Oil and Gas		545,853			584,563			429,607
Intercompany elimination		(250,611	)		(149,566	)		(57,846	)
Total	$	2,114,074		$	1,732,420		$	1,328,136

Income (loss) from operations ─
Contracting Services	$	142,763		$	128,651		$	83,666
Shelf Contracting(1)		179,711			183,130			185,366
Oil and Gas		(731,565	)		123,353			132,104
Production Facilities(2)		(719	)		(847	)		(1,051	)
Intercompany elimination		(26,011	)		(23,008	)		(8,024	)
Total(5)	$	(435,821		$	411,279		$	392,061

Net interest expense and other ─
Contracting Services(4)	$	37,909		$	6,440		$	27,363
Shelf Contracting		22,285			9,259			(163	)
Oil and Gas		26,000			49,580			14,293
Production Facilities		3,305			1,768			60
Total	$	89,499		$	67,047		$	41,553

Equity in losses of OTSL, inclusive of impairment	$	—		$	(10,841	)	$	(487	)
Equity in earnings of equity investments excluding OTSL	$	31,854		$	30,414		$	18,414

Income (loss) before income taxes ─
Contracting Services(3)	$	104,957		$	273,906		$	279,438
Shelf Contracting(1)		157,426			163,031			185,042
Oil and Gas		(757,565	)		73,773			117,811
Production Facilities(2)		27,727			27,799			17,302
Intercompany elimination		(26,011	)		(23,008	)		(8,024	)
Total	$	(493,466	)	$	515,501		$	591,569


Provision (benefit) for income taxes ─
Contracting Services	$	42,469		$	79,332		$	135,903
Shelf Contracting		47,927			57,430			65,710
Oil and Gas		(15,092	)		24,896			45,084
Production Facilities		11,475			10,204			6,056
Total	$	86,779		$	171,862		$	252,753

Index to Financial Statements

		Year Ended December 31,
		2008		2007		2006
		(in thousands)
Identifiable assets ─
Contracting Services	$	1,572,618	$	1,135,981	$	1,271,890
Shelf Contracting		1,309,608		1,274,050		452,153
Oil and Gas		1,708,428		2,634,238		2,282,715
Production Facilities		457,197		366,634		242,113
Discontinued operations		19,215		38,612		38,912
Total	$	5,067,066	$	5,449,515	$	4,287,783

Capital expenditures ─
Contracting Services	$	258,184	$	286,362	$	129,847
Shelf Contracting		83,108		30,301		38,086
Oil and Gas		404,308		519,632		282,318
Production Facilities (6)		110,300		123,545		45,327
Discontinued operations		476		1,215		1,091
Total	$	856,376	$	961,055	$	496,669

Depreciation and amortization ─
Contracting Services	$	46,926	$	38,729	$	32,223
Shelf Contracting(1)		71,195		40,698		24,515
Oil and Gas		215,605		250,371		134,967
Total	$	333,726	$	329,798	$	191,705

(1)	Includes $(10.8) million and $(0.5) million equity in (losses) earnings from investment in OTSL in 2007 and 2006, respectively.

(2)	Represents selling and administrative expense of Production Facilities incurred by us. See Equity in Earnings of Production Facilities investments for earnings contribution.

(3)	Includes pre-tax gain of $151.7 million related to the Horizon acquisition in 2007 and pre-tax gain of $223.1 million related to the initial public offering of CDI common stock and transfer of debt through dividend distributions from CDI in 2006.

(4)	Includes interest expense related to the Term Loan. The proceeds from the Term Loan were used to fund the cash portion of the Remington acquisition.

(5)	Includes $704.3 million of goodwill impairment charges for year ending December 31, 2008. Also includes approximately $215.7 million and $64.1 million of asset impairment charges for certain oil and gas properties for the years ended December 31, 2008 and 2007 respectively. There were no asset impairment charges in 2006.

(6)	Includes investments in production facilities.

Intercompany segment revenues during the years ended December 31, 2008, 2007 and 2006 were as follows (in thousands):

		Year Ended December 31,
		2008		2007		2006
Contracting Services	$	195,207	$	115,864	$	42,585
Shelf Contracting		55,404		33,702		15,261
Total	$	250,611	$	149,566	$	57,846

Index to Financial Statements

Intercompany segment profit (which only relates to intercompany capital projects) during the years ended December 31, 2008, 2007 and 2006 were as follows (in thousands):

		Year Ended December 31,
		2008		2007		2006
Contracting Services	$	20,945	$	10,026	$	2,460
Shelf Contracting		5,066		12,982		5,564
Total	$	26,011	$	23,008	$	8,024

Revenue by geographic region during the years ended December 31, 2008, 2007 and 2006 were as follows (in thousands):

		Year Ended December 31,
		2008		2007		2006
United States	$	1,394,108	$	1,261,844	$	1,063,821
United Kingdom		160,186		205,529		162,953
India		214,288		36,433		—
OtherOther		345,492		228,614		101,362
Total	$	2,114,074	$	1,732,420	$	1,328,136

We include the property and equipment, net in the geographic region in which it is legally owned. The following table provides our property and equipment, net of depreciation by geographic region (in thousands):

		Year Ended December 31,
		2008		2007		2006

United States	$	3,170,866	$	3,014,283	$	2,068,342
United Kingdom		206,009		187,551		109,461
Other		41,568		41,073		33,427
Total	$	3,418,443	$	3,242,907	$	2,211,230

Note 20 — Allowance Accounts

The following table sets forth the activity in our valuation accounts for each of the three years in the period ended December 31, 2008 (in thousands):

	Allowance for Uncollectible Accounts			Deferred Tax Asset Valuation Allowance
Balance, December 31, 2005	$	585		$	—
Additions		3,581			—
Deductions		(3,201	)		—
Balance, December 31, 2006		965			—
Additions		5,122			2,967
Deductions		(3,213	)		—
Balance, December 31, 2007		2,874			2,967
Additions		8,989			350
Deductions		(5,958	)		—
Balance, December 31, 2008	$	5,905		$	3,317

See Note 2 for a detailed discussion regarding our accounting policy on Accounts Receivable and Allowance for Uncollectible Accounts and Note 12 for a detailed discussion of the valuation allowance related to our deferred tax assets.

Index to Financial Statements

Note 21 — Supplemental Oil and Gas Disclosures (Unaudited)

The following information regarding our oil and gas producing activities is presented pursuant to SFAS No. 69, Disclosures About Oil and Gas Producing Activities.

Capitalized Costs

Aggregate amounts of capitalized costs relating to our oil and gas activities and the aggregate amount of related accumulated depletion, depreciation and amortization as of the dates indicated are presented below (in thousands):

		2008			2007
Unproved oil and gas properties	$	99,787		$	101,453
Proved oil and gas properties		2,472,036			2,228,924
Total oil and gas properties		2,571,823			2,330,377
Accumulated depletion, depreciation and amortization		(1,023,493	)		(617,922	)
Net capitalized costs	$	1,548,330		$	1,712,455

Included in capitalized costs of proved oil and gas properties being amortized is an estimate of our proportionate share of decommissioning liabilities assumed relating to these properties which are also reflected as decommissioning liabilities in the accompanying consolidated balance sheets at fair value on a discounted basis. At December 31, 2008 and 2007, our oil and gas operations’ decommissioning liabilities were $225.8 million and $217.5 million, respectively.

Costs Incurred in Oil and Gas Producing Activities

The following table reflects the costs incurred in oil and gas property acquisition and development activities, including estimated decommissioning liabilities assumed, during the years indicated (in thousands):

	United States		United Kingdom		Total
Year Ended December 31, 2008—
Property acquisition costs:
Proved properties	$	17,684	$	—	$	17,684
Unproved properties		13,392		—		13,392
Total property acquisition costs		31,076		—		31,076

Exploration costs		7,528		—		7,528
Development costs(1)		403,653		—		403,653
Asset retirement cost		26,891		—		26,891
Total costs incurred	$	469,148	$	—	$	469,148

Year Ended December 31, 2007—
Property acquisition costs:
Proved properties	$	12,703	$	—	$	12,703
Unproved properties		16,347		—		16,347
Total property acquisition costs		29,050		—		29,050

Exploration costs		220,237		—		220,237
Development costs(1)		351,964		—		351,964
Asset retirement cost		58,082		—		58,082
Total costs incurred	$	659,333	$	—	$	659,333

Index to Financial Statements

		United States		United Kingdom		Total
Year Ended December 31, 2006—
Property acquisition costs:
Proved properties	$	770,307	$	365	$	770,672
Unproved properties		105,519		—		105,519
Total property acquisition costs		875,826		365		876,191

Exploration costs		143,459		—		143,459
Development costs(1)		159,688		—		159,688
Asset retirement cost		32,863		7,579		40,442
Total costs incurred	$	1,211,836	$	7,944	$	1,219,780

(1)	Development costs include costs incurred to obtain access to proved reserves to drill and equip development wells. Development costs also include costs of developmental dry holes.

Results of Operations for Oil and Gas Producing Activities

Amounts in thousands:

	United States			United Kingdom			Total
Year Ended December 31, 2008—
Revenues	$	541,983		$	3,870		$	545,853
Production (lifting) costs		140,316			2,448			142,764
Exploration expenses(2)		32,926			—			32,926
Depreciation, depletion, amortization and accretion		198,144			959			199,103
Abandonment and impairment		935,971			—			935,971
Gain on sale of oil and gas properties		73,136			125			73,261
Selling and administrative		39,219			696			39,915
Pretax loss from producing activities		(731,457	)		(108	)		(731,565	)
Income tax expense (benefit)		(16,242	)		1,150			(15,092	)
Results of oil and gas producing activities(1)	$	(715,215	)	$	(1,258	)	$	(716,473	)

Year Ended December 31, 2007—
Revenues	$	581,904		$	2,659		$	584,563
Production (lifting) costs		118,032			5,102			123,134
Exploration expenses(2)		26,725			—			26,725
Depreciation, depletion, amortization and accretion		228,083			615			228,698
Abandonment and impairment		85,145			—			85,145
Gain on sale of oil and gas properties		42,566			1,717			44,283
Selling and administrative		40,176			1,615			41,791
Pretax income (loss) from producing activities		126,309			(2,956	)		123,353
Income tax expense (benefit)		26,240			(1,344	)		24,896
Results of oil and gas producing activities(1)	$	100,069		$	(1,612	)	$	98,457

Year Ended December 31, 2006—
Revenues	$	429,607		$	—		$	429,607
Production (lifting) costs		89,139			—			89,139
Exploration expenses(2)		43,115			—			43,115
Depreciation, depletion, amortization and accretion		134,967			—			134,967
Gain on sale of oil and gas properties		2,248			—			2,248
Selling and administrative		27,645			4,885			32,530
Pretax income (loss) from producing activities		136,989			(4,885	)		132,104
Income tax expense (benefit)		47,527			(2,443	)		45,084
Results of oil and gas producing activities(1)	$	89,462		$	(2,442	)	$	87,020

Index to Financial Statements

(1)	Excludes net interest expense and other.

(2)	See Note 7 for additional information related to the components of our exploration costs.

Estimated Quantities of Proved Oil and Gas Reserves

We employ full-time experienced reserve engineers and geologists who are responsible for determining proved reserves in compliance with SEC guidelines. Our engineering reserve estimates were prepared based upon interpretation of production performance data and sub-surface information obtained from the drilling of existing wells. Our internal reservoir engineers and independent petroleum engineers analyzed 100% of our significant United States oil and gas fields on an annual basis (107 fields as of December 31, 2008). We consider any field with discounted future net revenues of 1% or greater of the total discounted future net revenues of all our fields to be significant. An “engineering audit,” as we use the term, is a process involving an independent petroleum engineering firm’s (Huddleston) extensive visits, collection and examination of all geologic, geophysical, engineering and economic data requested by the independent petroleum engineering firm. Our use of the term “engineering audit” is intended only to refer to the collective application of the procedures which Huddleston was engaged to perform and may be defined and used differently by other companies.

The engineering audit of our reserves by the independent petroleum engineers involves their rigorous examination of our technical evaluation, interpretation and extrapolations of well information such as flow rates and reservoir pressure declines as well as other technical information and measurements. Our internal reservoir engineers interpret this data to determine the nature of the reservoir and ultimately the quantity of estimated proved oil and gas reserves attributable to a specific property. Our proved reserves in this Annual Report include only quantities that we expect to recover commercially using current prices, costs, existing regulatory practices and technology. While we are reasonably certain that the estimated proved reserves will be produced, the timing and ultimate recovery can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and changes in projections of long-term oil and gas prices. Revisions can include upward or downward changes in the previously estimated volumes of proved reserves for existing fields due to evaluation of (1) already available geologic, reservoir or production data or (2) new geologic or reservoir data obtained from wells. Revisions can also include changes associated with significant changes in development strategy, oil and gas prices, or the related production equipment/facility capacity. Huddleston also examined our estimates with respect to reserve categorization, using the definitions for proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent SEC staff interpretations and guidance.

In the conduct of the engineering audit, Huddleston did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties or sales of production. However, if in the course of the examination something came to the attention of Huddleston which brought into question the validity or sufficiency of any such information or data, Huddleston did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data. Furthermore, in instances where decline curve analysis was not adequate in determining proved producing reserves, Huddleston evaluated our volumetric analysis, which included the analysis of production and pressure data. Each of the PUDs analyzed by Huddleston included volumetric analysis, which took into consideration recovery factors relative to the geology of the location and similar reservoirs. Where applicable, Huddleston examined data related to well spacing, including potential drainage from offsetting producing wells in evaluating proved reserves for un-drilled well locations.

Index to Financial Statements

The engineering audit by Huddleston included 100% of the producing properties and essentially all the non-producing and undeveloped properties. Properties for analysis were selected by us and Huddleston based on estimated discounted future net revenues. All of our significant properties were included in the engineering audit and such audited properties constituted approximately 97% of the total estimated discounted future net revenues. Huddleston also analyzed the methods utilized by us in the preparation of all of the estimated reserves and revenues. Huddleston’s audit report represents that Huddleston believes our methodologies are consistent with the methodologies required by the SEC, SPE and FASB. There were no limitations imposed, nor limitations encountered by us or Huddleston.

The following table presents our net ownership interest in proved oil reserves (MBbls):

	United States			United(2) Kingdom			Total
Total proved reserves at December 31, 2005		14,873			—			14,873
Revision of previous estimates		(607	)		—			(607	)
Production		(3,400	)		—			(3,400	)
Purchases of reserves in place		24,820			—			24,820
Sales of reserves in place		—			—			—
Extensions and discoveries		651			—			651
Total proved reserves at December 31, 2006(1)		36,337			—			36,337
Revision of previous estimates		(473	)		97			(376	)
Production		(3,723	)		—			(3,723	)
Purchases of reserves in place		—			—			—
Sales of reserves in place		(1,858	)		(49	)		(1,907	)
Extensions and discoveries		9,346			—			9,346
Total proved reserves at December 31, 2007		39,629			48			39,677
Revision of previous estimates		(250	)		(48	)		(298	)
Production		(2,751	)		—			(2,751	)
Purchases of reserves in place		—			—			—
Sales of reserves in place		(5,277	)		—			(5,277	)
Extensions and discoveries		661			—			661
Total proved reserves at December 31, 2008		32,012			—			32,012

Total proved developed reserves as of :
December 31, 2005		7,759			—			7,759
December 31, 2006		13,328			—			13,328
December 31, 2007		14,703			10			14,713
December 31, 2008		12,809			—			12,809

(1)	Proved reserves at December 31, 2006 included approximately 17,573 MBbls acquired from the Remington acquisition.

(2)	Reflects current 50% ownership in United Kingdom reserves in 2008 and 2007; 100% ownership in 2006.

Index to Financial Statements

The following table presents our net ownership interest in proved gas reserves, including natural gas liquids (MMcf):

	United States			United(2) Kingdom			Total
Total proved reserves at December 31, 2005		136,073			—			136,073
Revision of previous estimates		4,678			—			4,678
Production		(27,949	)		—			(27,949	)
Purchases of reserves in place		169,375			23,634			193,009
Sales of reserves in place		—			—			—
Extensions and discoveries		12,212			—			12,212
Total proved reserves at December 31, 2006(1)		294,389			23,634			318,023
Revision of previous estimates		(12,209	)		5,666			(6,543	)
Production		(42,163	)		(300	)		(42,463	)
Purchases of reserves in place		160			—			160
Sales of reserves in place		(2,932	)		(14,700	)		(17,632	)
Extensions and discoveries		187,439			—			187,439
Total proved reserves at December 31, 2007		424,684			14,300			438,984
Revision of previous estimates		(32,098	)		(1,028	)		(33,126	)
Production		(30,490	)		(322	)		(30,812	)
Purchases of reserves in place		—			—			—
Sales of reserves in place		(73,627	)		—			(73,627	)
Extensions and discoveries		171,987			—			171,987
Total proved reserves at December 31, 2008		460,456			(12,950	)		473,406

Total proved developed reserves as of :
December 31, 2005		55,321			—			55,321
December 31, 2006		156,251			—			156,251
December 31, 2007		134,047			1,500			135,547
December 31, 2008		256,794			950			257,744

(1)	Proved reserves at December 31, 2006 included approximately 159,338 MMcf acquired from the Remington acquisition.

(2)	Reflects current 50% ownership in United Kingdom reserves in 2008 and 2007; 100% ownership in 2006.

Index to Financial Statements

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following table reflects the standardized measure of discounted future net cash flows relating to our interest in proved oil and gas reserves (in thousands):

	United States			United(1) Kingdom			Total
As of December 31, 2008—
Future cash inflows	$	4,011,788		$	113,054		$	4,124,842
Future costs:
Production		(584,165	)		(12,584	)		(596,749	)
Development and abandonment		(784,080	)		(33,150	)		(817,230	)
Future net cash flows before income taxes		2,643,543			67,320			2,710,863
Future income tax expense		(777,736	)		(53,626	)		(831,362	)
Future net cash flows		1,865,807			13,694			1,879,501
Discount at 10% annual rate		(562,354	)		(4,992	)		(567,346	)
Standardized measure of discounted future net cash flows	$	1,303,453		$	8,702		$	1,312,155

As of December 31, 2007—
Future cash inflows	$	6,769,106		$	126,700		$	6,895,806
Future costs:
Production		(622,842	)		(42,350	)		(665,192	)
Development and abandonment		(883,923	)		(46,600	)		(930,523	)
Future net cash flows before income taxes		5,262,341			37,750			5,300,091
Future income tax expense		(1,617,709	)		(18,850	)		(1,636,559	)
Future net cash flows		3,644,632			18,900			3,663,532
Discount at 10% annual rate		(831,705	)		(4,313	)		(836,018	)
Standardized measure of discounted future net cash flows	$	2,812,927		$	14,587		$	2,827,514

As of December 31, 2006—
Future cash inflows	$	3,814,201		$	173,520		$	3,987,721
Future costs:
Production		(588,000	)		(8,521	)		(596,521	)
Development and abandonment		(707,398	)		(66,300	)		(773,698	)
Future net cash flows before income taxes		2,518,803			98,699			2,617,502
Future income tax expense		(776,120	)		(53,791	)		(829,911	)
Future net cash flows		1,742,683			44,908			1,787,591
Discount at 10% annual rate		(416,738	)		(9,910	)		(426,648	)
Standardized measure of discounted future net cash flows	$	1,325,945		$	34,998		$	1,360,943

(1)	Reflects current 50% ownership in United Kingdom reserves in 2008 and 2007; 100% ownership in 2006.

Index to Financial Statements

Future cash inflows are computed by applying year-end prices, adjusted for location and quality differentials on a property-by-property basis, to year-end quantities of proved reserves, except in those instances where fixed and determinable price changes are provided by contractual arrangements at year-end. The discounted future cash flow estimates do not include the effects of our derivative instruments or forward sales agreements. See the following table for base prices used in determining the standardized measure:

	United States		United Kingdom		Total
Year Ended December 31, 2008—
Average oil price per Bbl	$	42.76	$	—	$	42.76
Average gas prices per Mcf	$	5.74	$	8.73	$	5.83

Year Ended December 31, 2007—
Average oil price per Bbl	$	93.98	$	49.69	$	93.92
Average gas prices per Mcf	$	7.17	$	8.69	$	7.22

Year Ended December 31, 2006—
Average oil price per Bbl	$	59.75	$	—	$	59.75
Average gas prices per Mcf	$	5.58	$	7.23	$	5.70

The future income tax expense was computed by applying the appropriate year-end statutory rates, with consideration of future tax rates already legislated, to the future pretax net cash flows less the tax basis of the associated properties. Future net cash flows are discounted at the prescribed rate of 10%. We caution that actual future net cash flows may vary considerably from these estimates. Although our estimates of total proved reserves, development costs and production rates were based on the best information available, the development and production of oil and gas reserves may not occur in the periods assumed. Actual prices realized, costs incurred and production quantities may vary significantly from those used. Therefore, such estimated future net cash flow computations should not be considered to represent our estimate of the expected revenues or the current value of existing proved reserves.

Changes in Standardized Measure of Discounted Future Net Cash Flows

Principal changes in the standardized measure of discounted future net cash flows attributable to our proved oil and gas reserves are as follows (in thousands):

		Year ended December 31,
		2008			2007			2006
Standardized measure, beginning of year	$	2,827,514		$	1,360,943		$	727,062
Changes during the year:
Sales, net of production costs		(403,089	)		(461,430	)		(340,468	)
Net change in prices and production costs		(1,713,458	)		1,208,823			(328,149	)
Changes in future development costs		(109,775	)		(17,689	)		(49,357	)
Development costs incurred		403,653			351,964			159,616
Accretion of discount		338,582			261,931			106,333
Net change in income taxes		700,071			(665,750	)		(254,770	)
Purchases of reserves in place		—			(951	)		1,245,847
Extensions and discoveries		335,643			1,285,499			82,730
Sales of reserves in place		(566,332	)		(247,344	)		—
Net change due to revision in quantity estimates		(96,096	)		(80,865	)		(6,067	)
Changes in production rates (timing) and other		(404,558	)		(167,617	)		18,166
Total		(1,515,359	)		1,466,571			633,881
Standardized measure, end of year	$	1,312,155		$	2,827,514		$	1,360,943

Index to Financial Statements

Note 22 — Resignation of Executive Officers

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

Wade Pursell resigned as our Chief Financial Officer effective June 25, 2008. Mr. Pursell remained employed by us through July 4, 2008, after which his employment terminated. Anthony Tripodo, who served as the chairman of our audit committee on our Board of Directors, was elected by our Board of Directors as the new Chief Financial Officer effective June 25, 2008, at which time he resigned from our Board of Directors. We recognized approximately $2.0 million of compensation expense (inclusive of the expenses recorded for the acceleration of unvested stock options and restricted stock) related to the separation between us and Mr. Pursell.

Note 23 — Quarterly Financial Information (Unaudited)

The offshore marine construction industry in the Gulf of Mexico is highly seasonal as a result of weather conditions and the timing of capital expenditures by oil and gas companies. Historically, a substantial portion of our services has been performed during the summer and fall months. As a result, historically a disproportionate portion of our revenues and net income is earned during such period. The following is a summary of consolidated quarterly financial information for 2008 and 2007 (in thousands, except per share data):

		Quarter Ended
		March 31,		June 30,		September 30,		December 31,(1)
2008
Net revenues	$	441,769	$	530,130	$	607,736	$	534,439
Gross profit (loss)		118,583		189,078		199,080		(134,550	)
Net income (loss) applicable to Helix		73,965		90,531		60,178		(860,604	)
Net income (loss) applicable to Helix common shareholders		73,084		89,651		59,297		(861,154	)
Basic earnings (loss) per common share		0.80		0.98		0.65		(9.48	)
Diluted earnings (loss) per common share		0.77		0.93		0.63		(9.48	)

		Quarter Ended
		March 31,		June 30,		September 30,		December 31,

2007
Net revenues	$	386,254	$	401,415	$	452,880	$	491,871
Gross profit		132,614		139,094		165,307		68,892
Net income applicable to Helix		55,588		57,470		82,560		120,080
Net income applicable to Helix common shareholders		54,643		56,525		81,615		119,199
Basic earnings per common share		0.60		0.62		0.89		1.31
Diluted earnings per common share		0.58		0.59		0.86		1.23

(1)	Includes $907.6 million of impairment charges to reduce goodwill and other indefinite-lived intangible assets ($715 million) and certain oil and gas properties ($192.6 million) to their estimated fair value in fourth quarter of 2008.

Index to Financial Statements

Note 24 — Condensed Consolidated Guarantor and Non-Guarantor Financial Information

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

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(As Adjusted (Note 2))

	As of December 31, 2008
	Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated

	(in thousands)
ASSETS

Current assets:
Cash and cash equivalents	$	148,704		$	4,983		$	69,926		$	—		$	223,613
Accounts receivable, net		125,882			97,300			204,674			—			427,856
Unbilled revenue		43,888			1,080			72,282			—			117,250
Other current assets		120,320			79,202			41,031			(68,464	)		172,089
Current assets of discontinued operations		—			—			19,215			—			19,215
Total current assets		438,794			182,565			407,128			(68,464	)		960,023
Intercompany		78,395			100,662			(101,813	)		(77,244	)		—
Property and equipment, net		168,054			2,007,807			1,247,060			(4,478	)		3,418,443
Other assets:
Equity investments in unconsolidated affiliates		—			—			196,660			—			196,660
Equity investments in affiliates		2,331,924			31,374			—			(2,363,298	)		—
Goodwill, net		—			45,107			321,111			—			366,218
Other assets, net		48,734			37,967			68,035			(29,014	)		125,722
	$	3,065,901		$	2,405,482		$	2,138,181		$	(2,542,498	)	$	5,067,066

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	99,197		$	139,074		$	107,856		$	(1,320	)	$	344,807
Accrued liabilities		87,712			65,090			83,233			(4,356	)		231,679
Income taxes payable		(104,487	)		82,859			9,149			12,479			—
Current maturities of long-term debt		4,326			—			173,947			(84,733	)		93,540
Current liabilities of discontinued operations		—			—			2,772			—			2,772
Total current liabilities		86,748			287,023			376,957			(77,930	)		672,798
Long-term debt		1,579,451			—			354,235			—			1,933,686
Deferred income taxes		184,543			242,967			191,773			(3,779	)		615,504
Decommissioning liabilities		—			191,260			3,405			—			194,665
Other long-term liabilities		—			73,549			10,706			(2,618	)		81,637
Due to parent		(100,528	)		(3,741	)		126,013			(21,744	)		—
Total liabilities		1,750,214			791,058			1,063,089			(106,071	)		3,498,290
Convertible preferred stock		55,000			—			—			—			55,000
Total equity		1,260,687			1,614,424			1,075,092			(2,436,427	)		1,513,776
	$	3,065,901		$	2,405,482		$	2,138,181		$	(2,542,498	)	$	5,067,066

Index to Financial Statements

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(As Adjusted (Note 2))

	As of December 31, 2007
	Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated

	(in thousands)
ASSETS

Current assets:
Cash and cash equivalents	$	3,507		$	2,609		$	83,439		$	—		$	89,555
Accounts receivable, net		85,122			104,619			249,997			—			439,738
Unbilled revenue		14,232			(280	)		50,351			—			64,303
Other current assets		74,665			45,752			54,391			(50,837	)		123,971
Current assets of discontinued operations		—			—			9,702			—			9,702
Total current assets		177,526			152,700			447,880			(50,837	)		727,269
Intercompany		38,989			50,860			(84,065	)		(5,784	)		—
Property and equipment, net		92,864			2,092,730			1,058,517			(1,204	)		3,242,907
Other assets:
Equity investments in unconsolidated affiliates		—			—			212,845			—			212,845
Equity investments in affiliates		3,020,092			30,046			—			(3,050,138	)		—
Goodwill, net		—			757,752			320,960						1,078,712
Other assets, net		56,716			40,686			95,760			(34,290	)		158,872
Assets of discontinued operations		—			—			28,910			—			28,910
	$	3,386,187		$	3,124,774		$	2,080,807		$	(3,142,253	)	$	5,449,515

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	43,774		$	207,222		$	130,145		$	41		$	381,182
Accrued liabilities		40,415			71,945			108,244			(1,437	)		219,167
Income taxes payable		7,271			(5,574	)		4,853			(6,550	)		—
Current maturities of long-term debt		4,327			2			113,975			(43,458	)		74,846
Current liabilities of discontinued operations		—			—			3,784			—			3,784
Total current liabilities		95,787			273,595			361,001			(51,404	)		678,979
Long-term debt		1,244,891			—			438,449			—			1,683,340
Deferred income taxes		151,744			318,492			178,130			(9,081	)		639,285
Decommissioning liabilities		—			189,639			4,011			—			193,650
Other long-term liabilities		3,294			56,325			9,244			(5,680	)		63,183
Due to parent		(35,681	)		98,504			62,513			(125,336	)		—
Total liabilities		1,460,035			936,555			1,053,348			(191,501	)		3,258,437
Convertible preferred stock		55,000			—			—			—			55,000
Unamortized debt discount on convertible notes		42,201			—			—			—			42,201
Total equity		1,828,951			2,188,219			1,027,459			(2,950,752	)		2,093,877
	$	3,386,187		$	3,124,774		$	2,080,807		$	(3,142,253	)	$	5,449,515

Index to Financial Statements

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(As Adjusted (Note 2))

	For the Year Ended December 31, 2008
	Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated

	(in thousands)
Net revenues	$	404,591		$	813,240		$	1,170,707		$	(274,464	)	$	2,114,074
Cost of sales		347,433			554,628			837,685			(246,464	)		1,493,282
Oil and gas impairments		—			215,675			—			—			215,675
Exploration expense		—			32,926			—			—			32,926
Gross profit (loss)		57,158			10,011			333,022			(28,000	)		372,191
Goodwill and other intangible impairments		—			704,311			—			—			704,311
Gain on sale of assets, net		—			73,136			335			—			73,471
Selling and administrative expenses		42,194			47,372			91,974			(4,368	)		177,172
Income (loss) from operations		14,964			(668,536	)		241,383			(23,632	)		(435,821	)
Equity in earnings of unconsolidated affiliates		—			—			31,854			—			31,854
Equity in earnings (losses) of affiliates		(584,299	)		1,328			—			582,971			—
Net interest expense and other		21,939			25,367			42,285			(92	)		89,499
Income (loss) before income taxes		(591,274	)		(692,575	)		230,952			559,431			(493,466	)
Provision for income taxes		30,412			2,909			62,754			(9,296	)		86,779
Income (loss) from continuing operations		(621,686	)		(695,484	)		168,198			568,727			(580,245	)
Discontinued operations, net of tax		—			—			(9,812	)		—			(9,812	)
Net income (loss) , including noncontrolling interests		(621,686	)		(695,484	)		158,386			568,727			(590,057	)
Net income applicable to noncontrolling interests		—			—			—			45,873			45,873
Net income (loss) applicable to Helix		(621,686	)		(695,484	)		158,386			522,854			(635,930	)
Preferred stock dividends		3,192			—			—			—			3,192
Net income (loss) applicable to Helix common shareholders	$	(624,878	)	$	(695,484	)	$	158,386		$	522,854		$	(639,122	)

	For the Year Ended December 31, 2007
	Helix			Guarantors		Non-Guarantors		Consolidating Entries			Consolidated

	(in thousands)
Net revenues	$	262,007		$	769,648	$	874,324	$	(173,559	)	$	1,732,420
Cost of sales		201,001			514,653		568,480		(148,418	)		1,135,716
Oil and gas impairments		—			64,072		—		—			64,072
Exploration expense		—			26,725		—		—			26,725
Gross profit (loss)		61,006			164,198		305,844		(25,141	)		505,907
Gain on sale of assets, net		1,960			42,566		5,842		—			50,368
Selling and administrative expenses		38,063			44,940		65,126		(3,133	)		144,996
Income from operations		24,903			161,824		246,560		(22,008	)		411,279
Equity in earnings of unconsolidated affiliates		—			—		19,573		—			19,573
Equity in earnings of affiliates		219,280			15,140		—		(234,420	)		—
Gain on subsidiary equity transaction		151,696			—		—		—			151,696
Net interest expense and other		(7,539	)		49,064		21,178		4,344			67,047
Income before income taxes		403,418			127,900		244,955		(260,772	)		515,501
Provision for income taxes		70,592			39,871		70,623		(9,224	)		171,862
Income (loss) from continuing operations		332,826			88,029		174,332		(251,548	)		343,639
Discontinued operations, net of tax		—			—		1,347		—			1,347
Net income (loss), including noncontrolling interests		332,826			88,029		175,679		(251,548	)		344,986
Net income applicable to noncontrolling interests		—			—		113		29,175			29,288
Net income (loss) applicable to Helix		332,826			88,029		175,566		(280,723	)		315,698
Preferred stock dividends		3,716			—		—		—			3,716
Net income applicable to Helix common shareholders	$	329,110		$	88,029	$	175,566	$	(280,723	)	$	311,982

Index to Financial Statements

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(As Adjusted (Note 2))

	For the Year Ended December 31, 2006
	Helix		Guarantors		Non-Guarantors		Consolidating Entries			Consolidated

	(in thousands)
Net revenues	$	173,976	$	569,074	$	669,711	$	(84,625	)	$	1,328,136
Cost of sales		120,566		334,979		401,666		(75,668	)		781,543
Exploration expense		—		43,115		—		—			43,115
Gross profit (loss)		53,410		190,980		268,045		(8,957	)		503,478
Gain on sale of assets, net		220		2,248		349		—			2,817
Selling and administrative expenses		33,838		33,135		48,477		(1,216	)		114,234
Income (loss) from operations		19,792		160,093		219,917		(7,741	)		392,061
Equity in earnings of unconsolidated affiliates		—		—		17,927		—			17,927
Equity in earnings of affiliates		255,110		9,996		—		(265,106	)		—
Gain on subsidiary equity transaction		223,134		—		—		—			223,134
Net interest expense and other		20,497		14,301		6,755		—			41,553
Income (loss) before income taxes		477,539		155,788		231,089		(272,847	)		591,569
Provision for income taxes		129,062		54,703		71,695		(2,707	)		252,753
Income (loss) from continuing operations		348,477		101,085		159,394		(270,140	)		338,816
Discontinued operations, net of tax		—		—		4,806		—			4,806
Net income (loss), including noncontrolling interests		348,477		101,085		164,200		(270,140	)		343,622
Net income applicable to noncontrolling interests		—		—		179		546			725
Net income (loss) applicable to Helix		348,477		101,085		164,021		(270,686	)		342,897
Preferred stock dividends		3,358		—		—		—			3,358
Net income (loss) applicable to common shareholders	$	345,119	$	101,085	$	164,021	$	(270,686	)	$	339,539

Index to Financial Statements

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(As Adjusted (Note 2))

	For the Year Ended December 31, 2008
	Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated

	(in thousands)
Cash flow from operating activities:
Net income (loss), including noncontrolling interests	$	(621,686	)	$	(695,484	)	$	158,386		$	568,727		$	(590,057	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Equity in earnings of unconsolidated affiliates		—			—			2,846			—			2,846
Equity in earnings of affiliates		584,299			(1,328	)		—			(582,971	)		—
Other adjustments		(48,995	)		967,933			107,708			(5,021	)		1,021,625
Net cash provided by (used in) operating activities		(86,382	)		271,121			268,940			(19,265	)		434,414
Net cash provided by discontinued operations		—			—			3,305			—			3,305
Net cash provided by (used in) operating activities		(86,382	)		271,121			272,245			(19,265	)		437,719

Cash flows from investing activities:
Capital expenditures		(75,003	)		(513,024	)		(267,027	)		—			(855,054	)
Acquisition of businesses, net of cash acquired		—			—			—			—			—
Investments in equity investments		—			—			(846	)		—			(846	)
Distributions from equity investments, net		—			—			11,586			—			11,586
Increases in restricted cash		—			(614	)		—			—			(614	)
Proceeds from insurance		—			13,200			—			—			13,200
Proceeds from sales of property		—			271,758			2,472			—			274,230
Net cash used in investing activities		(75,003	)		(228,680	)		(253,815	)		—			(557,498	)
Net cash used in discontinued operations		—			—			(476	)		—			(476	)
Net cash used in investing activities		(75,003	)		(228,680	)		(254,291	)		—			(557,974	)

Cash flows from financing activities:
Borrowings on revolvers		1,021,500			—			61,100			—			1,082,600
Repayments on revolvers		(690,000	)		—			(61,100	)		—			(751,100	)
Repayments of debt		(4,326	)		—			(64,014	)		—			(68,340	)
Deferred financing costs		(1,796	)		—			—			—			(1,796	)
Capital lease payments		—			—			(1,505	)		—			(1,505	)
Preferred stock dividends paid		(3,192	)		—			—			—			(3,192	)
Repurchase of common stock		(3,925	)		—			—			—			(3,925	)
Excess tax benefit from stock-based compensation		1,335			—			—			—			1,335
Exercise of stock options, net		2,139			—			—			—			2,139
Intercompany financing		(15,153	)		(40,067	)		35,955			19,265			—
Net cash provided by (used in) financing activities		306,582			(40,067	)		(29,564	)		19,265			256,216
Effect of exchange rate changes on cash and cash equivalents		—			—			(1,903	)		—			(1,903	)
Net increase (decrease) in cash and cash equivalents		145,197			2,374			(13,513	)		—			134,058
Cash and cash equivalents:
Balance, beginning of year		3,507			2,609			83,439			—			89,555
Balance, end of year	$	148,704		$	4,983		$	69,926		$	—		$	223,613

Index to Financial Statements

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(As Adjusted (Note 2))

	For the Year Ended December 31, 2007
	Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated

	(in thousands)
Cash flow from operating activities:
Net income (loss), including noncontrolling interests	$	332,826		$	88,029		$	175,679		$	(251,548	)	$	344,986
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Equity in earnings of unconsolidated affiliates		—			—			11,538			—			11,538
Equity in earnings of affiliates		(219,280	)		(15,139	)		—			234,419			—
Other adjustments		(268,156	)		297,948			(135,511	)		169,970			64,251
Net cash provided by (used in) operating activities		(154,610	)		370,838			51,706			152,841			420,775
Net cash provided by discontinued operations		—			—			(4,449	)		—			(4,449	)
Net cash provided by (used in) operating activities		(154,610	)		370,838			47,257			152,841			416,326

Cash flows from investing activities:
Capital expenditures		(81,577	)		(642,364	)		(218,440	)		—			(942,381	)
Acquisition of businesses, net of cash acquired		—			—			(147,498	)		—			(147,498	)
Sale of short-term investments		285,395			—			—			—			285,395
Investments in equity investments		—			—			(17,459	)		—			(17,459	)
Distributions from equity investments, net		—			—			6,679			—			6,679
Increases in restricted cash		—			(1,112	)		—			—			(1,112	)
Proceeds from sales of property		—			53,547			24,526			—			78,073
Other, net		—			(136	)		—			—			(136	)
Net cash used in investing activities		203,818			(590,065	)		(352,192	)		—			(738,439	)
Net cash used in discontinued operations		—			—			(1,215	)		—			(1,215	)
Net cash provided by (used in) investing activities		203,818			(590,065	)		(353,407	)		—			(739,654	)

Cash flows from financing activities:
Borrowings on revolvers		472,800			—			31,500			—			504,300
Repayments on revolvers		(454,800	)		—			(332,668	)		—			(787,468	)
Borrowings under debt		550,000			—			380,000			—			930,000
Repayments of debt		(405,408	)		—			(3,823	)		—			(409,231	)
Deferred financing costs		(11,377	)		—			(5,788	)		—			(17,165	)
Capital lease payments		—			—			(2,519	)		—			(2,519	)
Preferred stock dividends paid		(3,716	)		—			—			—			(3,716	)
Repurchase of common stock		(9,904	)		—			—			—			(9,904	)
Excess tax benefit from stock-based compensation		580			—			—			—			580
Exercise of stock options, net		1,568			—			—			—			1,568
Intercompany financing		(327,933	)		214,146			266,628			(152,841	)		—
Net cash provided by (used in) financing activities		(188,190	)		214,146			333,330			(152,841	)		206,445
Effect of exchange rate changes on cash and cash equivalents		—			—			174			—			174
Net increase (decrease) in cash and cash equivalents		(138,982	)		(5,081	)		27,354			—			(116,709	)
Cash and cash equivalents:
Balance, beginning of year		142,489			7,690			56,085			—			206,264
Balance, end of year	$	3,507		$	2,609		$	83,439		$	—		$	89,555

Index to Financial Statements

HELIX ENERGY SOLUTIONS GROUP, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(As Adjusted (Note 2))

	For the Year Ended December 31, 2006
	Helix			Guarantors			Non-Guarantors			Consolidating Entries			Consolidated
	(in thousands)

Cash flow from operating activities:
Net income (loss), including noncontrolling interests	$	348,477		$	101,085		$	164,200		$	(270,140	)	$	343,622
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Equity in earnings of unconsolidated affiliates		—			—			(1,410	)		—			(1,410	)
Equity in earnings of affiliates		(255,110	)		(9,996	)		—			265,106			—
Other adjustments		26,274			131,644			(25,432	)		34,880			167,366
Net cash provided by (used in) operating activities		119,641			222,733			137,358			29,846			509,578
Net cash provided by discontinued operations		—			—			4,458			—			4,458
Net cash provided by operating activities		119,641			222,733			141,816			29,846			514,036

Cash flows from investing activities:
Capital expenditures		(9,170	)		(362,343	)		(96,487	)		—			(468,000	)
Acquisition of businesses, net of cash acquired		—			(772,244	)		(115,699	)		—			(887,943	)
Purchases of short-term investments		(285,395	)		—			—			—			(285,395	)
Investments in equity investments		—			—			(27,578	)		—			(27,578	)
Increases in restricted cash		—			(6,666	)		—			—			(6,666	)
Proceeds from sale of subsidiary stock		264,401			—			—			—			264,401
Proceeds from sales of property		514			15,000			16,828			—			32,342
Net cash used in investing activities		(29,650	)		(1,126,253	)		(222,936	)		—			(1,378,839	)
Net cash used in discontinued operations		—			—			(1,091	)		—			(1,091	)
Net cash used in investing activities		(29,650	)		(1,126,253	)		(224,027	)		—			(1,379,930	)

Cash flows from financing activities:
Borrowings on revolvers		209,800			—			201,000			—			410,800
Repayments on revolvers		(209,800	)		—			—			—			(209,800	)
Borrowings under debt		835,000			—			5,000			—			840,000
Repayments of debt		(2,100	)		—			(3,641	)		—			(5,741	)
Deferred financing costs		(11,462	)		—			(377	)		—			(11,839	)
Capital lease payments		—			—			(2,827	)		—			(2,827	)
Preferred stock dividends paid		(3,613	)		—			—			—			(3,613	)
Repurchase of common stock		(50,266	)		—			—			—			(50,266	)
Subsidiary stock issuance		—			—			264,401			(264,401	)		—
Excess tax benefit from stock-based compensation		2,660			—			—			—			2,660
Exercise of stock options, net		8,886			—			—			—			8,886
Intercompany financing		(802,878	)		907,869			(339,546	)		234,555			—
Net cash provided by (used in) financing activities		(23,773	)		907,869			124,010			(29,846	)		978,260
Effect of exchange rate changes on cash and cash equivalents		—			—			2,818			—			2,818
Net increase in cash and cash equivalents		66,218			4,349			44,617			—			115,184
Cash and cash equivalents:
Balance, beginning of year		76,271			3,341			11,468			—			91,080
Balance, end of year	$	142,489		$	7,690		$	56,085		$	—		$	206,264

Index to Financial Statements

Note 25 — Subsequent Events

Discontinued Operations

On April 27, 2009, we sold Helix Energy Limited to a subsidiary of Baker Hughes Incorporated for $25 million. Helix Energy Limited and its wholly owned subsidiary, Helix RDS Limited, represented our reservoir and well technology services business, which serviced the upstream oil and gas induction by providing reservoir engineering, geophysical, production technology and associated specialized consulting services. As a result of the sale of Helix Energy Limited and Helix RDS Limited we have presented its results and financial position as discontinued operations in the accompanying consolidated financial statements. Helix Energy Limited was previously a component of our Contracting Services segment.

Sale of Cal Dive Common Stock

On June 10, 2009, we completed an underwritten secondary public offering by selling 20 million shares of Cal Dive common stock held by us. Proceeds from the Offering totaled approximately $161.9 million, net of underwriting fees. The Offering remains subject to a thirty day option period under which the underwriters may sell up to an additional 3 million shares of our Cal Dive shares of common stock at $8.50 per share, the price per share under the Offering. Separately, pursuant to a Stock Repurchase Agreement with Cal Dive, upon closing of the Offering, Cal Dive simultaneously repurchased from us approximately 1.6 million shares of its shares for net proceeds of $14 million at $8.50 per share. Following the closing of these two transactions, our ownership of Cal Dive common stock has been reduced to approximately 28%.

Index to Financial Statements