HELIX ENERGY SOLUTIONS GROUP INC - Quarter Report: 2008 September (Form 10-Q)

 

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

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

For the quarterly period ended September 30, 2008

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

For the transition period from                      to                     

HELIX ENERGY SOLUTIONS GROUP, INC.

Minnesota (State or other jurisdiction of incorporation or organization)		95-3409686 (I.R.S. Employer Identification No.)
400 North Sam Houston Parkway East
Suite 400		77060
Houston, Texas		(Zip Code)
(Address of principal executive offices)

(281) 618-0400
(Registrant’s telephone number, including area code)

NOT APPLICABLE
(Former name, former address and former fiscal year, if changed since last report)

          Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

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

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

          Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o No þ

As of October 29, 2008, 91,849,691 shares of common stock were outstanding.

 

 

TABLE OF CONTENTS

				PAGE
PART I.		FINANCIAL INFORMATION
Item 1.		Financial Statements:
		Condensed Consolidated Balance Sheets — September 30, 2008 (Unaudited) and December 31, 2007			1
		Condensed Consolidated Statements of Operations (Unaudited) — Three months ended September 30, 2008 and 2007			2
		Nine months ended September 30, 2008 and 2007			3
		Condensed Consolidated Statements of Cash Flows (Unaudited) — Nine months ended September 30, 2008 and 2007			4
		Notes to Condensed Consolidated Financial Statements (Unaudited)			5
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			32
Item 3.		Quantitative and Qualitative Disclosures About Market Risk			49
Item 4.		Controls and Procedures			50
PART II.		OTHER INFORMATION
Item 1.		Legal Proceedings			51
Item 1A.		Risk Factors			51
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds			51
Item 6.		Exhibits			52
		Signatures			53
		Index to Exhibits			54
EX-15.1
EX-31.1
EX-31.2
EX-32.1
EX-99.1

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

		September 30,				December 31,
		2008				2007
		(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	35,761			$	89,555
Accounts receivable —
Trade, net of allowance for uncollectible accounts of $4,704 and $2,874, respectively			429,853				447,502
Unbilled revenue			51,881				10,715
Costs in excess of billing			95,142				53,915
Other current assets			148,378				125,582
Total current assets			761,015				727,269
Property and equipment			4,663,853				4,088,561
Less — accumulated depreciation			(1,056,183	)			(843,873	)
			3,607,670				3,244,688
Other assets:
Equity investments			206,805				213,429
Goodwill			1,077,411				1,089,758
Other assets, net			166,593				177,209
		$	5,819,494			$	5,452,353
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	344,088			$	382,767
Accrued liabilities			213,555				221,366
Current maturities of long-term debt			93,540				74,846
Total current liabilities			651,183				678,979
Long-term debt			1,815,083				1,725,541
Deferred income taxes			669,620				625,508
Decommissioning liabilities			185,306				193,650
Other long-term liabilities			74,532				63,183
Total liabilities			3,395,724				3,286,861
Minority interest			296,248				263,926
Convertible preferred stock			55,000				55,000
Commitments and contingencies			—				—
Shareholders’ equity:
Common stock, no par, 240,000 shares authorized, 91,841 and 91,385 shares issued, respectively			772,306				755,758
Retained earnings			1,295,370				1,069,546
Accumulated other comprehensive income			4,846				21,262
Total shareholders’ equity			2,072,522				1,846,566
		$	5,819,494			$	5,452,353

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

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

		Three Months Ended
		September 30,
		2008				2007
Net revenues:
Contracting services		$	481,597			$	318,752
Oil and gas			134,619				141,821
			616,216				460,573
Cost of sales:
Contracting services			325,186				196,027
Oil and gas			90,205				98,228
			415,391				294,255
Gross profit			200,825				166,318
Gain (loss) on sale of assets, net			(23	)			20,701
Selling and administrative expenses			50,700				42,146
Income from operations			150,102				144,873
Equity in earnings of investments			8,886				7,889
Net interest expense and other			23,464				13,467
Income before income taxes			135,524				139,295
Provision for income taxes			54,816				45,327
Minority interest			19,240				10,195
Net income			61,468				83,773
Preferred stock dividends			881				945
Net income applicable to common shareholders		$	60,587			$	82,828
Earnings per common share:
Basic		$	0.67			$	0.92
Diluted		$	0.65			$	0.88
Weighted average common shares outstanding:
Basic			90,725				90,111
Diluted			94,779				95,649

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

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

		Nine Months Ended
		September 30,
		2008				2007
Net revenues:
Contracting services		$	1,107,616			$	852,332
Oil and gas			499,831				414,870
			1,607,447				1,267,202
Cost of sales:
Contracting services			797,641				556,546
Oil and gas			295,688				266,958
			1,093,329				823,504
Gross profit			514,118				443,698
Gain on sale of assets, net			79,893				26,385
Selling and administrative expenses			142,405				106,134
Income from operations			451,606				363,949
Equity in earnings of investments			25,964				9,245
Net interest expense and other			68,178				40,765
Income before income taxes			409,392				332,429
Provision for income taxes			154,373				111,711
Minority interest			26,553				21,533
Net income			228,466				199,185
Preferred stock dividends			2,642				2,835
Net income applicable to common shareholders		$	225,824			$	196,350
Earnings per common share:
Basic		$	2.49			$	2.18
Diluted		$	2.40			$	2.07
Weighted average common shares outstanding:
Basic			90,598				90,051
Diluted			95,266				96,087

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

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

		Nine Months Ended
		September 30,
		2008				2007
Cash flows from operating activities:
Net income		$	228,466			$	199,185
Adjustments to reconcile net income to net cash provided by (used in) operating activities —
Depreciation, depletion and amortization			248,578				229,870
Asset impairment charges			23,902				904
Dry hole expense			254				166
Equity in losses of investments, inclusive of impairment charge			2,300				10,841
Amortization of deferred financing costs			3,837				2,315
Stock compensation expense			17,933				11,014
Deferred income taxes			56,575				48,159
Hedge Ineffectiveness			4,045				—
Excess tax benefit from stock-based compensation			(1,142	)			(28	)
Gain on sale of assets			(79,893	)			(26,386	)
Minority interest			26,553				21,533
Changes in operating assets and liabilities:
Accounts receivable, net			(48,485	)			(36,029	)
Other current assets			(5,079	)			(38,074	)
Income tax payable			739				(115,556	)
Accounts payable and accrued liabilities			(79,181	)			17,741
Other noncurrent, net			(60,316	)			(45,127	)
Net cash provided by operating activities			339,086				280,528
Cash flows from investing activities:
Capital expenditures			(728,803	)			(684,653	)
Acquisition of businesses, net of cash acquired			—				(10,202	)
Sale of short-term investments			—				285,395
Investments in equity investments			(708	)			(16,132	)
Distributions from equity investments, net			4,636				6,363
Proceeds from sales of property			230,261				4,343
Other			(553	)			(834	)
Net cash used in investing activities			(495,167	)			(415,720	)
Cash flows from financing activities:
Repayment of Helix Term Notes			(3,245	)			(6,300	)
Borrowings on Helix Revolver			847,000				236,300
Repayments on Helix Revolver			(690,000	)			(150,300	)
Repayment of MARAD borrowings			(4,014	)			(3,823	)
Borrowings on CDI Revolver			61,100				19,000
Repayments on CDI Revolver			(61,100	)			(103,000	)
Repayments on CDI Term Notes			(40,000	)			—
Deferred financing costs			(1,711	)			(231	)
Capital lease payments			(1,505	)			(1,882	)
Preferred stock dividends paid			(2,642	)			(2,835	)
Repurchase of common stock			(3,912	)			(9,821	)
Excess tax benefit from stock-based compensation			1,142				28
Exercise of stock options, net			2,139				957
Net cash provided by (used in) financing activities			103,252				(21,907	)
Effect of exchange rate changes on cash and cash equivalents			(965	)			1,271
Net decrease in cash and cash equivalents			(53,794	)			(155,828	)
Cash and cash equivalents:
Balance, beginning of year			89,555				206,264
Balance, end of period		$	35,761			$	50,436

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

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

Note 1 — Basis of Presentation

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

          The accompanying condensed consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles and are consistent in all material respects with those applied in our Annual Report on Form 10-K for the year ended December 31, 2007 (“2007 Form 10-K”). The preparation of these financial statements requires us to make estimates and judgments that affect the amounts reported in the financial statements and the related disclosures. Actual results may differ from our estimates. Management has reflected all adjustments (which were normal recurring adjustments unless otherwise disclosed herein) that it believes are necessary for a fair presentation of the condensed consolidated balance sheets, results of operations, and cash flows, as applicable. Operating results for the period ended September 30, 2008 are not necessarily indicative of the results that may be expected for the year ending December 31, 2008. Our balance sheet as of December 31, 2007 included herein has been derived from the audited balance sheet as of December 31, 2007 included in our 2007 Form 10-K. These condensed consolidated financial statements should be read in conjunction with the annual consolidated financial statements and notes thereto included in our 2007 Form 10-K.

          Certain reclassifications were made to previously reported amounts in the condensed consolidated financial statements and notes thereto to make them consistent with the current presentation format.

Note 2 — Company Overview

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

Contracting Services Operations

          We seek to provide services and methodologies which we believe are critical to finding and developing offshore reservoirs and maximizing production economics, particularly from marginal fields. By “marginal” we mean reservoirs that are no longer wanted by major operators or are too small to be material to them. Our “life of field” services are organized into five disciplines: construction, well operations, production facilities, reservoir and well technology services, and drilling. We have disaggregated our contracting services operations into three reportable segments in accordance with Financial Accounting Standards Board (“FASB”) Statement No. 131, Disclosures about Segments of an Enterprise and Related Information (“SFAS No. 131”): Contracting Services (which currently includes subsea construction, well operations and reservoir and well technology services and in the future, drilling); Shelf Contracting; and Production Facilities. Within our contracting services operations, we operate primarily in the Gulf of Mexico, North Sea, Asia/Pacific and Middle East regions, with services that cover the lifecycle of an offshore oil or gas field. The assets of our Shelf Contracting segment are the assets of Cal Dive International, Inc. and its subsidiaries (“Cal Dive” or “CDI”). Our ownership in CDI was approximately 58.1% as of September 30, 2008.

Oil and Gas Operations

          In 1992 we began our oil and gas operations to provide a more efficient solution to offshore abandonment, to expand our off-season asset utilization of our contracting services assets and to achieve incremental returns to our contracting services. Over the last 16 years we have evolved this business model to include not only mature oil and gas properties but also proved and unproved reserves yet to be developed and explored. This has led to the assembly of services that allows us to create value at key points in the life of a reservoir from exploration through development, life of field management and operating through abandonment.

Note 3 — Statement of Cash Flow Information

          We define cash and cash equivalents as cash and all highly liquid financial instruments with original maturities of less than three months. As of September 30, 2008 and December 31, 2007, we had $35.4 million and $34.8 million, respectively, of restricted cash. All of our restricted cash was related to funds required to be escrowed to cover decommissioning liabilities associated with the South Marsh Island 130 (“SMI 130”) acquisition in 2002 by our Oil and Gas segment. These amounts were reported in Other Assets, Net. We had fully satisfied the escrow requirement as of September 30, 2008. We may use the restricted cash for decommissioning the related field.

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

		Nine Months Ended
		September 30,
		2008				2007
Interest paid		$	77,268			$	71,906
Income taxes paid		$	97,059			$	179,107

          Non-cash investing activities for the nine months ended September 30, 2008 included $28.6 million of accruals for capital expenditures. Non-cash investing activities for the nine months ended September 30, 2007 were immaterial. The accruals have been reflected in the condensed consolidated balance sheet as an increase in property and equipment and accounts payable.

Note 4 — Acquisition of Horizon Offshore, Inc.

          On December 11, 2007, CDI acquired 100% of Horizon Offshore, Inc. (“Horizon”), a marine construction services company headquartered in Houston, Texas. Upon consummating the merger of Horizon into a subsidiary of CDI, each share of Horizon common stock, par value $0.00001 per share, was converted into the right to receive $9.25 in cash and 0.625 shares of CDI’s common stock. All shares of Horizon restricted stock that had been issued but had not vested prior to the effective time of the merger became fully vested at such time and converted into the right to receive the merger consideration. CDI issued approximately 20.3 million shares of common stock and paid approximately $300 million in cash to the former Horizon stockholders upon completion of the acquisition. The cash portion of the merger consideration was paid from cash on hand and from borrowings of $375 million under CDI’s $675 million credit facility, which consists of a $375 million senior secured term loan and a $300 million senior secured revolving credit facility (see "—Note 8—Long-Term Debt” below).

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

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

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

Cash		$	170,607
Other current assets			165,623
Property and equipment			336,147
Goodwill			257,343
Intangible assets(1)			9,510
Other long-term assets			15,270
Total assets acquired		$	954,500
Current liabilities		$	180,846
Long-term debt			87,641
Deferred income taxes			55,789
Other non-current liabilities			100
Total liabilities assumed		$	324,376
Net assets acquired		$	630,124

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

At September 30, 2008, the net carrying amount for these intangible assets was $5.7 million.

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

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

		Three Months				Nine Months
		Ended				Ended
		September 30,				September 30,
		2007				2007
Net revenues		$	594,694			$	1,596,781
Income before income taxes			163,304				390,028
Net income			88,384				192,428
Net income applicable to common shareholders			87,439				189,593
Earnings per common share:
Basic		$	0.96			$	2.09
Diluted		$	0.93			$	2.02

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

Note 5 — Oil and Gas Properties

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

          As of September 30, 2008, we capitalized approximately $19.2 million of exploratory drilling costs associated with ongoing exploration and/or appraisal activities. Such capitalized costs may be charged against earnings in future periods if management determines that commercial quantities of hydrocarbons have not been discovered or that future appraisal drilling or development activities are not likely to occur. The following table provides a detail of our capitalized exploratory project costs at September 30, 2008 and December 31, 2007 (in thousands):

		September 30,				December 31,
		2008				2007
Huey		$	11,555			$	11,556
Castleton (part of Gunnison)			7,071				7,071
Other			531				469
Total		$	19,157			$	19,096

          As of September 30, 2008, the exploratory well costs for Castleton and Huey had been capitalized for longer than one year.

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

		2008
Beginning balance at January 1,		$	19,096
Additions pending the determination of proved reserves			1,088
Reclassifications to proved properties			(773	)
Charge to dry hole expense			(254	)
Ending balance at September 30,		$	19,157

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

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
Delay rental and geological and geophysical costs		$	1,375			$	1,426			$	4,753			$	5,478
Dry hole expense			270				50				254				166
Total exploration expense		$	1,645			$	1,476			$	5,007			$	5,644

          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 $181.2 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.

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

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

          In September 2008, we sustained damage to certain of our contracting services and oil and gas production facilities from Hurricane 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 will be operational is uncertain and not subject to our control. As of September 30, 2008, we had identified certain shelf production platforms plus other production assets that have sustained extensive damage. Our assessment of damage to our oil and gas production assets is ongoing and thus has not been fully evaluated. 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. As of September 2008, we have reached our aggregate deductibles. We believe our comprehensive coverage is sufficient to cover all our repair and inspection costs and capital redrill or rebuild costs as a result of damages sustained by the hurricane. These costs will be recorded as incurred. Insurance reimbursements will be recorded when the realization of the claim for recovery of a loss is deemed probable.

Note 6 — Details of Certain Accounts (in thousands)

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

		September 30,				December 31,
		2008				2007
Prepaid insurance		$	25,395			$	21,133
Current deferred tax assets			9,945				13,810
Insurance claims to be reimbursed			7,829				10,173
Gas imbalance			6,241				6,654
Inventory			36,686				29,925
Income tax receivable			9,805				8,838
Other prepaids			29,050				14,922
Other receivables			17,433				6,733
Other			5,994				13,394
		$	148,378			$	125,582

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

		September 30,				December 31,
		2008				2007
Restricted cash		$	35,351			$	34,788
Deposits			2,981				8,417
Deferred drydock expenses, net			64,989				47,964
Deferred financing costs			37,640				39,290
Intangible assets with definite lives, net			15,612				22,216
Intangible asset with indefinite life			6,295				7,022
Contract receivables			—				14,635
Other			3,725				2,877
		$	166,593			$	177,209

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

		September 30,				December 31,
		2008				2007
Accrued payroll and related benefits		$	48,793			$	50,389
Royalties payable			10,340				21,974
Current decommissioning liability			28,350				23,829
Unearned revenue			11,523				1,140
Billings in excess of costs			10,703				20,403
Insurance claims to be reimbursed			7,829				14,173
Accrued interest			19,890				7,090
Accrued severance(1)			1,953				14,786
Deposit			21,292				13,600
Hedge liability			5,710				10,308
Other			47,172				43,674
		$	213,555			$	221,366

Note 7 — Equity Investments

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

	•		Deepwater Gateway, L.L.C. In June 2002, we, along with Enterprise Products Partners L.P. (“Enterprise”), formed Deepwater Gateway, L.L.C. (“Deepwater Gateway”) (each with a 50% interest) to design, construct, install, own and operate a tension leg platform (“TLP”) production hub primarily for Anadarko Petroleum Corporation’s Marco Polo field in the Deepwater Gulf of Mexico. Our investment in Deepwater Gateway totaled $110.7 million and $112.8 million as of September 30, 2008 and December 31, 2007, respectively, and was included in our Production Facilities segment. Deepwater Gateway sustained minor damage to its production hub from Hurricane Ike; however, major infrastructure damage was sustained to the downstream pipeline facilities, causing temporary production shut-ins. Production had not resumed as of September 30, 2008.
	•		Independence Hub, LLC. In December 2004, we acquired a 20% interest in Independence Hub, LLC (“Independence”), an affiliate of Enterprise. Independence owns the “Independence Hub” platform located in Mississippi Canyon block 920 in a water depth of 8,000 feet. First production began in July 2007. Our investment in Independence was $92.9 million and $95.7 million as of September 30, 2008 and December 31, 2007, respectively (including capitalized interest of $6.0 million and $6.2 million at September 30, 2008 and December 31, 2007, respectively), and was included in our Production Facilities segment. Independence did not sustain major damage from Hurricane Ike and operations resumed shortly following the hurricane.

Note 8 — Long-Term Debt

Senior Unsecured Notes

          On December 21, 2007, we issued $550 million of 9.5% Senior Unsecured Notes due 2016 (“Senior Unsecured Notes”). Interest on the Senior Unsecured Notes is payable semiannually in arrears on each January 15 and July 15, commencing July 15, 2008. The Senior Unsecured Notes are fully and

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

Senior Credit Facilities

          On July 3, 2006, we entered into a credit agreement (the “Senior Credit Facilities”) under which we borrowed $835 million in a term loan (the “Term Loan”) and were initially able to borrow up to $300 million (the “Revolving Loans”) under a revolving credit facility (the “Revolving Credit Facility”). The proceeds from the Term Loan were used to fund the cash portion of the Remington Oil and Gas Corporation (“Remington”) acquisition. This facility was subsequently amended on November 27, 2007, and as part of that amendment, an accordion feature was added that allows for increases in the Revolving Credit Facility up to 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.

          The Term Loan matures on July 1, 2013 and is subject to quarterly scheduled principal payments. As a result of a $400 million prepayment made in December 2007, the quarterly scheduled principal payment was reduced from $2.1 million to $1.1 million. The Revolving Loans mature on July 1, 2011. At September 30, 2008, we had $175.0 million in borrowings outstanding under our Revolving Loans and $23.5 million of unsecured letters of credit, and there was $221.5 million available under the Revolving Loans. In October 2008, we drew down an additional $175.0 million under our Revolving Loans.

          The Term Loan currently bears interest at the one-, three- or six-month LIBOR at our election plus a 2.00% margin. Our average interest rate on the Term Loan for the nine months ended September 30, 2008 and 2007 was approximately 5.4% and 7.4%, respectively, including the effects of our interest rate swaps (see below). The Revolving Loans bear interest based on one-, three- or six-month LIBOR at our election plus a margin ranging from 1.00% to 2.25%. Margins on the Revolving Loans will fluctuate in relation to the consolidated leverage ratio as provided in the Senior Credit Facilities. Our average interest rate on the Revolving Loans for the nine months ended September 30, 2008 was approximately 5.6%.

          As the rates for our Term Loan are subject to market influences and will vary over the term of the Senior Credit Facilities, we entered into various interest rate swaps to stabilize cash flows relating to a portion of our interest payments for our Term Loan. See detailed description related to these swaps in “—Note 10 — Derivative Activities” below.

Cal Dive International, Inc. Revolving Credit Facility

          In December 2007, CDI entered into a secured credit facility with certain financial institutions, consisting of a $375 million term loan, and a $300 million revolving credit facility. This credit facility replaced the credit facility CDI entered into in November 2006 prior to its initial public offering. On December 11, 2007, CDI borrowed $375 million under the term loan to fund the cash portion of the merger consideration in connection with CDI’s acquisition of Horizon and to retire Horizon’s existing debt. At September 30, 2008, CDI had $335.0 million of term loan outstanding. In addition, CDI had $6.2 million of unsecured letters of credit outstanding with $293.8 million available under its revolving credit facility.

          Loans under this facility are non-recourse to Helix. The term loan and the revolving loans bear interest in relation to the LIBOR. During the nine months ended September 30, 2008 and 2007, CDI’s average interest rate was 5.7%.

          As the rates for CDI’s term loan are subject to market influences and will vary over the term of the loan, CDI entered into an interest rate swap to stabilize cash flows relating to a portion of its interest payments for the CDI term loan. See detailed description related to this swap in “—Note 10 — Derivative Activities” below.

Convertible Senior Notes

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

          The Convertible Senior Notes can be converted prior to the stated maturity under certain triggering events specified in the indenture governing the Convertible Senior Notes. To the extent we do not have long-term financing secured to cover the conversion, the Convertible Senior Notes would be classified as a current liability in the accompanying balance sheet. During the third quarter of 2008, no conversion triggers were met.

          For the three months ended September 30, 2008, shares underlying the Convertible Senior Notes were not included in the calculation of diluted earnings per share because our average share price for the third quarter 2008 was below the conversion price of approximately $32.14 per share. Approximately 0.6 million shares underlying the Convertible Senior Notes were included in the calculation of diluted earnings per share for the nine months ended September 30, 2008, and approximately 1.2 million and 1.7 million shares were included in the calculation for the three and nine months ended September 30, 2007, respectively, because our average share price for the respective periods was above the conversion price. In the event our average share price exceeds the conversion price, there would be a premium, payable in shares of common stock, in addition to the principal amount, which is paid in cash, and such shares would be issued on conversion. The maximum number of shares of common stock which may be issued upon conversion of the Convertible Senior Notes is 13,303,770.

MARAD Debt

          At September 30, 2008 and December 31, 2007, $123.4 million and $127.5 million was outstanding on our long-term financing for construction of the Q4000. This U.S. government guaranteed financing (“MARAD Debt”) is pursuant to Title XI of the Merchant Marine Act of 1936 which is administered by the Maritime Administration. The MARAD Debt is payable in equal semi-annual installments which began in August 2002 and matures 25 years from such date. The MARAD Debt is collateralized by the Q4000, with us guaranteeing 50% of the debt. In September 2005, we fixed the interest rate on the debt through the issuance of a 4.93% fixed-rate note with the same maturity date (February 2027).

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

Other

          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 (“HPI”). Kommandor LLC qualified as a variable interest entity under FASB Interpretation No. 46 (Revised),

Consolidation of Variable Interest Entities (“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 September 30, 2008 in our Production Facilities segment. On June 19, 2007, Kommandor LLC entered into a term loan agreement (“Nordea Loan Agreement”) with Nordea Bank Norge ASA. On August 29, 2008, the Nordea Loan Agreement was amended. Pursuant to the amended Nordea Loan Agreement, the lenders will make available to Kommandor LLC up to $64.0 million pursuant to a secured term loan facility. We have provided $40 million in interim construction financing to the joint venture on terms that would equal an arms length financing transaction, and Kommandor Rømø has provided $5 million on the same terms. Kommandor LLC will use all amounts borrowed under the Nordea Loan Agreement to repay its existing subordinated indebtedness to us and Kommandor Rømø for the long-term financing of the HPI and to fund expenses and fees related to the first stage of the conversion of the HPI. Kommandor LLC expects this borrowing to occur in the second quarter of 2009 upon the delivery of the HPI after its initial conversion, and at such time, in accordance with the provisions of FIN 46(R), the entire obligation will be included in our consolidated balance sheet. The funding of the amount set forth in the draw request is subject to certain customary conditions.

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

          Deferred financing costs of $37.6 million and $39.3 million are included in Other Assets, Net as of September 30, 2008 and December 31, 2007, respectively, and are being amortized over the life of the respective loan agreements.

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

		Helix				Helix				CDI				Senior				Convertible
		Term				Revolving				Term				Unsecured				Senior				MARAD
		Loan				Loans				Loan				Notes				Notes				Debt				Other(1)				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				175,000				80,000				—				—				4,645				—				263,971
Three to four years			4,326				—				80,000				—				—				4,877				—				89,203
Four to five years			402,870				—				15,000				—				—				5,120				—				422,990
Over five years			—				—				—				550,000				300,000				100,169				—				950,169
Long-term debt			420,174				175,000				335,000				550,000				300,000				123,449				5,000				1,908,623
Current maturities			(4,326	)			—				(80,000	)			—				—				(4,214	)			(5,000	)			(93,540	)
Long-term debt, less current maturities		$	415,848			$	175,000			$	255,000			$	550,000			$	300,000			$	119,235			$	—			$	1,815,083

          Total letters of credit outstanding at September 30, 2008 was approximately $43.3 million. These letters of credit primarily guarantee various contract bidding, contractual performance and insurance activities and shipyard commitments. The following table details our interest expense and capitalized interest for the three and nine months ended September 30, 2008 and 2007 (in thousands):

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
Interest expense		$	30,468				24,010				95,043				70,257
Interest income			(617	)			(1,107	)			(2,245	)			(7,682	)
Capitalized interest			(10,046	)			(8,935	)			(30,619	)			(20,734	)
Interest expense, net		$	19,805				13,968				62,179				41,841

Note 9 — Income Taxes

          The effective tax rate for the nine months ended September 30, 2008 and 2007 was 38% and 34%, respectively. The effective tax rate for the nine months ended September 30, 2008 increased as compared to the same prior year period because of the following factors:

	§		additional deferred tax expense was recorded as a result of the increase in the equity earnings of CDI in excess of our tax basis in CDI;
	§		the surrender of the tax losses related to our oil and gas subsidiary in the United Kingdom to other profitable subsidiaries in the United Kingdom that are taxed at a lower rate; and
	§		the allocation of goodwill to the cost basis for the Onshore Properties sale is not allowable for tax purposes.

          We believe our recorded assets and liabilities are reasonable; however, tax laws and regulations are subject to interpretation and tax litigation is inherently uncertain; therefore our assessments can involve a series of complex judgments about future events and rely heavily on estimates and assumptions. See detailed description related to a tax assessment in “—Note 18 — Commitments and Contingencies” below.

Note 10 — Derivative Activities

          We are currently exposed to market risk in three major areas: commodity prices, interest rates and foreign currency exchange rates. Our risk management activities include the use of derivative financial instruments to hedge the impact of market price risk exposures primarily related to our oil and gas production, variable interest rate exposure and foreign currency exchange rate exposure, as well as non-derivative forward sale contracts to reduce commodity price risk on sales of hydrocarbons.

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

Commodity Derivatives

          We have entered into various cash flow hedging costless collar and swap contracts to stabilize cash flows relating to a portion of our expected oil and gas production. These instruments qualified for hedge accounting and were designated as cash flow hedges under FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, (“SFAS No. 133”). During the third quarter 2008 we settled our open natural gas derivative positions. The resulting gain of $3.9 million was recognized immediately in earnings. Due to production shut-ins and the resultant deferrals caused by Hurricanes Gustav and Ike, as of September 13, 2008 (the date of Hurricane Ike), we no longer meet all of the hedging criteria required by SFAS No. 133 for our open oil derivative positions at September 30, 2008. As a result, we discontinued hedge accounting at September 13, 2008 and the change in fair value from that date through September 30, 2008 was recognized in earnings and all future changes in fair value related

to these instruments will also be recognized in earnings. We also reclassified the amounts in accumulated other comprehensive income related to the oil derivative contracts as of September 13, 2008 to earnings as a result of the production deferral mentioned above. The aggregate fair value of the hedge instruments was a net liability of $1.0 million and $8.1 million as of September 30, 2008 and December 31, 2007, respectively. We recorded unrealized gains of approximately $14.7 million and $5.3 million, net of tax expense of $7.9 million and $2.8 million, respectively, for the change in fair value of the derivatives during the three and nine months ended September 30, 2008, respectively, in accumulated other comprehensive income. For the three and nine months ended September 30, 2007, we recorded unrealized losses of approximately $0.8 million and $4.4 million, net of tax benefit of $0.4 million and $2.4 million, respectively in accumulated other comprehensive income. During the three and nine months ended September 30, 2008, we reclassified approximately $5.3 million and $24.4 million of losses from other comprehensive income to net revenues upon the sale of the related oil and gas production and approximately $1.0 million from other comprehensive income as a result of the discontinuation of hedge accounting. For the three and nine months ended September 30, 2007, we reclassified approximately $3.2 million and $5.5 million of gains from other comprehensive income to net revenues. No hedge ineffectiveness was recorded in 2007.

          As of September 30, 2008, we had the following volumes under derivative and forward sale contracts related to our oil and gas producing activities totaling 2,155 MBbl of oil and 18,076,400 MMbtu of natural gas:

Instrument

Average

Weighted

Production Period

Type

Monthly Volumes

Average Price

Crude Oil:

October 2008 — December 2008

Collar

30 MBbl

$

60.00 — $82.35

October 2008 — December 2008

Swap

42 MBbl

$106.25

October 2008 — December 2009

Forward Sale

129 MBbl

$71.82

Natural Gas:

January 2009 — December 2009

Forward Sale

1,506,367 MMBtu

$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.

          Subsequent to September 30, 2008, we entered into two additional natural gas costless collars and two natural gas swaps. The costless collars cover an average of 1,029,000 MMBtu per month at an average price of $7.00 to $7.90 per MMBtu for the period from January to December 2009. The swaps cover an average of 1,500,000 MMBtu per month at an average price of $7.02 per MMBtu for November and December 2008. We also entered into an oil costless collar for an average of 50.2 MBbl per month for the period from January to June 2009 at a price of $75.00 to $89.55.

Interest Rate Swaps

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

          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. These interest rate swaps qualified for hedge accounting. See “—Note 8 — Long-Term Debt” above for a detailed description of our Term Loan. On December 21, 2007, we prepaid a portion of our Term Loan which reduced the notional amount of our

interest rate swaps and caused our hedges to become ineffective. As a result, the interest rate swaps no longer qualified for hedge accounting treatment under 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, as such, no longer qualified for hedge accounting. During the nine months ended September 30, 2008, we recognized $2.5 million of unrealized losses as other expense as a result of the change in fair value of our interest rate swaps. An immaterial amount was recorded in income in the three months ended September 30, 2008 for hedge ineffectiveness. No ineffectiveness was recognized during the three and nine months ended September 30, 2007. As of September 30, 2008 and December 31, 2007, the aggregate fair value of the derivative instruments was a net liability of $4.6 million and $4.7 million, respectively. During the three and nine months ended September 30, 2008, we reclassified approximately $0.4 million and $1.3 million of losses, respectively, from other comprehensive income to interest expense. During the three and nine months ended September 30, 2007, we reclassified approximately $0.1 million and $0.3 million of gains, respectively.

          In addition, in April 2008, CDI entered into a two-year interest rate swap to stabilize cash flows relating to a portion of its variable interest payments on the CDI term loan. As of September 30, 2008, these interest rate swaps were highly effective and qualified for hedge accounting. The fair value of the hedge instrument was an asset of $0.8 million as of September 30, 2008.

Foreign Currency Forwards

          Because we operate in various regions in the world, we conduct a portion of our business in currencies other than the U.S. dollar. We entered into various foreign currency forwards to stabilize expected cash outflows relating to a shipyard contract where the contractual payments are denominated in euros and expected cash outflows relating to certain vessel charters denominated in British pounds. The aggregate fair value of the foreign currency forwards as of September 30, 2008 and December 31, 2007 was a net asset (liability) of ($1.4) million and $1.4 million, respectively.

Note 11 — Fair Value Measurements

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

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

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

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

	(a)		Market Approach. Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.
	(b)		Cost Approach. Amount that would be required to replace the service capacity of an asset (replacement cost).
	(c)		Income Approach. Techniques to convert expected future cash flows to a single present amount based on market expectations (including present value techniques, option-pricing and excess earnings models).

          The following table provides additional information related to assets and liabilities measured at fair value on a recurring basis at September 30, 2008 (in thousands):

																		Valuation
		Level 1				Level 2				Level 3				Total				Technique
Assets:
Interest rate swap			—			$	803				—			$	803				(c	)
Liabilities:
Oil and gas swaps and collars			—				1,046				—				1,046				(c	)
Foreign currency forwards			—				1,409				—				1,409				(c	)
Interest rate swaps			—				4,636				—				4,636				(c	)
Total			—			$	7,091				—			$	7,091

Note 12 — Comprehensive Income

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

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
Net income		$	61,468			$	83,773			$	228,466			$	199,185
Foreign currency translation gain (loss)			(26,721	)			4,775				(23,929	)			9,491
Unrealized gain (loss) on hedges, net			14,365				(1,618	)			7,513				(3,709	)
Total comprehensive income		$	49,112			$	86,930			$	212,050			$	204,967

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

		September 30,				December 31,
		2008				2007
Cumulative foreign currency translation adjustment		$	4,331			$	28,260
Unrealized gain (loss) on hedges, net			515				(6,998	)
Accumulated other comprehensive income		$	4,846			$	21,262

Note 13 — Earnings Per Share

          Basic earnings per share (“EPS”) is computed by dividing the net income available to common shareholders by the weighted average shares of outstanding common stock. The calculation of diluted EPS is similar to basic EPS, except that the denominator includes dilutive common stock equivalents and the income included in the numerator excludes the effects of the impact of dilutive common stock equivalents, if any. The computation of basic and diluted EPS for the three and nine months ended September 30, 2008 and 2007 were as follows (in thousands):

		Three Months Ended								Three Months Ended
		September 30, 2008								September 30, 2007
		Income				Shares				Income				Shares
Earnings applicable per common share — Basic		$	60,587				90,725			$	82,828				90,111
Effect of dilutive securities:
Stock options			—				227				—				368
Restricted shares			—				196				—				293
Employee stock purchase plan			—				—				—				2
Convertible Senior Notes			—				—				—				1,244
Convertible preferred stock			881				3,631				945				3,631
Earnings applicable per common share — Diluted		$	61,468				94,779			$	83,773				95,649

		Nine Months Ended								Nine Months Ended
		September 30, 2008								September 30, 2007
		Income				Shares				Income				Shares
Earnings applicable per common share — Basic		$	225,824				90,598			$	196,350				90,051
Effect of dilutive securities:
Stock options			—				292				—				386
Restricted shares			—				170				—				292
Employee stock purchase plan			—				—				—				4
Convertible Senior Notes			—				575				—				1,723
Convertible preferred stock			2,642				3,631				2,835				3,631
Earnings applicable per common share — Diluted		$	228,466				95,266			$	199,185				96,087

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

Note 14 — Stock-Based Compensation Plans

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

          During the first nine months of 2008, we granted 509,916 shares of restricted stock and 43,977 restricted stock units to certain key executives, selected management employees and non-employee members of the board of directors under the 2005 incentive plan. The grants generally have a vesting period of 20% per year over five years. The weighted average market value per restricted share and restricted stock unit was $41.11 and $41.50, respectively. There were no stock option grants in the nine months ended September 30, 2008 and 2007.

          Compensation cost is recognized over the respective vesting periods on a straight-line basis. For the three and nine months ended September 30, 2008, $0.1 million and $1.0 million, respectively, was recognized as compensation expense related to stock options (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). For the three and nine months ended September 30, 2008, $3.7 million and $15.2 million, respectively, was recognized as compensation expense related to restricted shares and restricted stock units (of which $1.1 million and $3.5 million, respectively, was related to the CDI Incentive Plan and $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). For the three and nine months ended September 30, 2007, $2.8 million and $8.7 million, respectively, was recognized as compensation expense related to restricted shares (of which $0.5 million and $1.6 million, respectively, was related to the CDI Incentive Plan). Future compensation cost associated with unvested restricted stock awards at September 30, 2008 totaled approximately $46.3 million, of which approximately $14.3 million was related to CDI Incentive Plan.

Employee Stock Purchase Plan

          Effective May 12, 1998, we adopted a qualified non-compensatory employee stock purchase plan which allows employees to acquire shares of our common stock through payroll deductions over a six-month period. The purchase price is equal to 85% of the fair market value of the common stock on either the first or last day of the subscription period, whichever is lower. Purchases under the plan are limited to the lesser of 10% of an employee’s base salary or $25,000 of our stock value. In January and July 2008, we issued 46,152 and 52,781 shares, respectively, of our common stock to our employees under the ESPP. For the three and nine months ended September 30, 2008, we recognized $0.7 million and $1.8 million, respectively, of compensation expense related to the ESPP and the CDI ESPP (of which $0.3 million and $0.9 million, respectively, of expense was related to the CDI ESPP that became effective third quarter 2007). For the three and nine months ended September 30, 2007, we recognized $0.5 million and $1.5 million, respectively, of compensation expense related to the stock purchased under the ESPP and the CDI ESPP (of which $0.3 million of expense was related to the CDI ESPP that became effective third quarter 2007).

Note 15 — Business Segment Information (in thousands)

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

          We evaluate our performance based on income before income taxes of each segment. Segment assets are comprised of all assets attributable to the reportable segment. The majority of our Production Facilities segment is accounted for under the equity method of accounting. Our investment in Kommandor LLC, a Delaware limited liability company, was consolidated in accordance with FIN 46(R) and is included in our Production Facilities segment.

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
Revenues –
Contracting Services		$	284,671			$	192,331			$	696,811			$	484,767
Shelf Contracting			278,709				176,928				595,250				461,412
Oil and Gas			134,619				141,821				499,831				414,870
Intercompany elimination			(81,783	)			(50,507	)			(184,445	)			(93,847	)
Total		$	616,216			$	460,573			$	1,607,447			$	1,267,202
Income from operations –
Contracting Services		$	56,845			$	43,697			$	115,749			$	98,779
Shelf Contracting			72,719				56,993				109,765				141,438
Production Facilities equity investments(1)			(140	)			(182	)			(434	)			(514	)
Oil and Gas			34,198				51,443				248,317				139,345
Intercompany elimination			(13,520	)			(7,078	)			(21,791	)			(15,099	)
Total		$	150,102			$	144,873			$	451,606			$	363,949
Equity in losses of OTSL		$	—			$	—			$	—			$	(10,841	)
Equity in earnings of equity investments excluding OTSL		$	8,886			$	7,889			$	25,964			$	20,086

		September 30,				December 31,
		2008				2007
Identifiable Assets –
Contracting Services		$	1,438,669			$	1,177,431
Shelf Contracting			1,258,374				1,274,050
Production Facilities			448,650				366,634
Oil and Gas			2,673,801				2,634,238
Total		$	5,819,494			$	5,452,353

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

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
Contracting Services		$	65,424			$	31,487			$	150,465			$	62,984
Shelf Contracting			16,359				19,020				33,980				30,863
Total		$	81,783			$	50,507			$	184,445			$	93,847

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

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
Contracting Services		$	12,097			$	865			$	17,989			$	3,540
Shelf Contracting			1,423				6,213				3,802				11,559
Total		$	13,520			$	7,078			$	21,791			$	15,099

Note 16 — 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 17 — Related Party Transactions

          In April 2000, we acquired a 20% working interest in Gunnison, a Deepwater Gulf of Mexico prospect of Kerr-McGee. Financing for the exploratory costs of approximately $20 million was provided by an investment partnership (OKCD Investments, Ltd. or “OKCD”), the investors of which include our President and Chief Executive Officer, Owen Kratz, and certain former Helix senior management, in exchange for a revenue interest that is an overriding royalty interest of 25% of Helix’s 20% working interest. Owen Kratz, through Class A limited partnership interests in OKCD, personally owns approximately 74% of the partnership. In 2000, OKCD also awarded Class B limited partnership interests to key Helix employees. Production began in December 2003. Payments to OKCD from us totaled $8.8 million and $20.0 million in the three and nine months ended September 30, 2008, respectively, and $5.2 million and $16.9 million in the three and nine months ended September 30, 2007, respectively.

Note 18 — Commitments and Contingencies

Commitments

          We are converting the Caesar (acquired in January 2006 for $27.5 million in cash) into a deepwater pipelay vessel. Total conversion costs are estimated to range between $200 million and $220 million, of which approximately $148 million had been incurred, with an additional $8 million committed, at September 30, 2008. The Caesar is expected to be completed in the second quarter of 2009.

          We are also constructing the Well Enhancer, a multi-service dynamically positioned dive support/well intervention vessel that will be capable of working in the North Sea and West of Shetlands to support our expected growth in that region. Total construction cost for the Well Enhancer is expected to range between $200 million to $220 million. We expect the Well Enhancer to join our fleet in second quarter 2009. At September 30, 2008, we had incurred approximately $140 million, with an additional $46 million committed to this project.

          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 which will be funded through project financing of $64 million, with the remaining amount funded through equity contributions from the partners. The partners will guarantee the project financing on a several basis. We have provided $40 million in interim construction financing to the joint venture on terms that would equal an arms length financing transaction, and Kommandor Rømø has provided $5 million on the same terms. Both of these loans will be repaid with the proceeds of the permanent financing facility.

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

          Upon completion of the initial conversion, scheduled for second quarter 2009, we will charter the HPI from Kommandor LLC, and plan to install, at 100% our cost, processing facilities and a disconnectable fluid transfer system on the HPI for use on our Phoenix field. The cost of these additional facilities is estimated to range between $175 million to $195 million and the work is expected to be completed by the end of 2009. As of September 30, 2008, approximately $194 million of costs related to the purchase of the HPI ($20 million), conversion of the HPI and construction of the additional facilities had been incurred, with an additional $20 million committed. 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 September 30, 2008 in our Production Facilities segment. Kommandor LLC has been a development stage enterprise since its formation in October 2006.

          Our projected capital expenditures on certain projects have increased as compared to the initially budgeted amounts due primarily to scope changes, escalating costs for certain materials and services due to increasing demand, and the weaker U.S. dollar earlier in 2008 with respect to foreign denominated contracts. In addition, as of September 30, 2008, we have also committed approximately $108.7 million in additional capital expenditures for exploration, development and drilling costs related to our oil and gas properties.

Contingencies

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

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

2008 stating that the price thresholds for oil and gas were exceeded for 2005, 2006 and 2007 production, and that royalties and interest are payable. ERT has appealed that order on the same basis that it appealed the prior MMS orders. As a result of our dispute with the MMS, we have recorded reserves for the disputed royalties (and any other royalties that may be claimed from the Gunnison leases), plus interest, for our portion of the Gunnison related MMS claim. The total reserved amount for this matter at September 30, 2008 and December 31, 2007 was approximately $67.3 million and $55.1 million, respectively, and was included in Other Long-term Liabilities in the accompanying condensed consolidated balance sheet included herein. At this time, it is not anticipated that any penalties would be assessed if we are unsuccessful in our appeal.

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

          We sustained damage to certain of our oil and gas production facilities in Hurricane Ike. 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. As of September 2008, we have reached our aggregate deductibles. We believe our comprehensive coverage is sufficient to cover all our repair and inspection costs and capital redrill or rebuild costs as a result of damages sustained by the hurricane. These costs will be recorded as incurred. Insurance reimbursements will be recorded when the realization of the claim for recovery of a loss is deemed probable.

Note 19 — Convertible Preferred Stock

           On January 8, 2003, we completed the private placement of $25 million of a newly designated class of cumulative convertible preferred stock (Series A-1 Cumulative Convertible Preferred Stock, par value $0.01 per share) that is convertible into 1,666,668 shares of our common stock at $15 per share. The preferred stock was issued to a private investment firm. Subsequently in June 2004, the preferred stockholder exercised its existing right and purchased $30 million in additional cumulative convertible preferred stock (Series A-2 Cumulative Convertible Preferred Stock, par value $0.01 per share). In accordance with the January 8, 2003 agreement, the $30 million in additional preferred stock is convertible into 1,964,058 shares of our common stock at $15.27 per share. In the event the holder of the convertible preferred stock elects to redeem into our common stock and our common stock price is below the conversion prices, unless we have elected to settle in cash, the holder would receive additional shares above the 1,666,668 common shares (Series A-1 tranche) and 1,964,058 common shares (Series A-2 tranche). The incremental shares would be treated as a dividend and reduce net income applicable to common shareholders. In the event our common stock price on any date is less than a certain minimum price, we must deliver notice that either (i) the conversion price will be reset to such minimum price or (ii) in the event the holder exercises its redemption rights, we will satisfy our redemption obligations either in cash, or in a combination of cash and common stock with the number of shares of common stock, determined based upon the current market price of our common stock, subject to a maximum number of shares that can be delivered. In the event our redemption obligation is triggered and our obligation cannot be fully satisfied with common stock, we will be required to redeem a portion of the preferred stock in cash. As of October 30, 2008, our stock price has not been below the minimum price since the issuance of the preferred stock.

           The preferred stock has a minimum annual dividend rate of 4%, subject to adjustment, payable quarterly in cash or common shares at our option. The dividend rate for the years ended December 31, 2007, 2006 and 2005 was 6.4%, 6.9% and 5.9%, respectively. We paid these dividends in 2007, 2006 and 2005 in cash. The holder may redeem the value of its original and additional investment in the preferred shares to be settled in common stock at the then prevailing market price or cash at our discretion. In the event we are unable to deliver registered common shares, we could be required to redeem in cash.

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

Note 20 — Recently Issued Accounting Principles

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

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

          In June 2008, the FASB issued FSP Emerging Issues Task Force 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (“FSP EITF 03-6-1”). This FSP would require unvested share-based payment awards containing non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) to be included in the computation of basic EPS according to the two-class method. The effective date of FSP EITF 03-6-1 is for fiscal years beginning after December 15, 2008 and requires all prior-period EPS data presented to be adjusted retrospectively (including interim financial statements, summaries of earnings, and selected financial data) to conform with the provisions of this FSP. FSP EITF 03-6-1 does not permit early application. This FSP changes our calculation of basic and diluted EPS and will lower previously reported basic and diluted EPS as weighted-average shares outstanding used in the EPS calculation will increase. We are currently evaluating the impact of this statement on our consolidated financial statements.

          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 (“EIFT 07-5”). This issue addresses the determination of whether an instrument (or an embedded feature) is indexed to an entity’s own stock. 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. We are currently evaluating the impact of this statement on our consolidated financial statements.

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

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

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

		As of September 30, 2008
										Non-				Consolidating
		Helix				Guarantors				Guarantors				Entries				Consolidated
ASSETS
Current assets:
Cash and cash equivalents		$	3,216			$	231			$	32,314			$	—			$	35,761
Accounts receivable, net			124,501				122,783				337,217				(7,625	)			576,876
Other current assets			113,689				57,529				49,563				(72,403	)			148,378
Total current assets			241,406				180,543				419,094				(80,028	)			761,015
Intercompany			93,997				120,873				(175,661	)			(39,209	)			—
Property and equipment, net			157,913				2,224,582				1,228,918				(3,743	)			3,607,670
Other assets:
Equity investments			3,202,791				37,088				206,805				(3,239,879	)			206,805
Goodwill			—				749,670				328,016				(275	)			1,077,411
Other assets, net			53,129				38,744				103,525				(28,805	)			166,593
		$	3,749,236			$	3,351,500			$	2,110,697			$	(3,391,939	)		$	5,819,494
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	57,877			$	171,124			$	122,146			$	(7,059	)		$	344,088
Accrued liabilities			62,057				64,822				91,037				(4,361	)			213,555
Income taxes payable			(109,650	)			103,906				1,895				3,849				—
Current maturities of long-term debt			4,326				—				163,567				(74,353	)			93,540
Total current liabilities			14,610				339,852				378,645				(81,924	)			651,183
Long-term debt			1,440,848				—				399,720				(25,485	)			1,815,083
Deferred income taxes			167,432				320,740				186,825				(5,377	)			669,620
Decommissioning liabilities			—				181,510				3,796				—				185,306
Other long-term liabilities			995				71,182				5,380				(3,025	)			74,532
Due to parent			(37,028	)			(8,329	)			37,028				8,329				—
Total liabilities			1,586,857				904,955				1,011,394				(107,482	)			3,395,724
Minority interest			—				—				—				296,248				296,248
Convertible preferred stock			55,000				—				—				—				55,000
Shareholders’ equity			2,107,379				2,446,545				1,099,303				(3,580,705	)			2,072,522
		$	3,749,236			$	3,351,500			$	2,110,697			$	(3,391,939	)		$	5,819,494