EXHIBIT 99.3
Item 8. Financial Statements and Supplementary Data.
INDEX TO FINANCIAL STATEMENTS
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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
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.
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.
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 |
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.
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 | ) |
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.
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.
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.
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%.
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 |
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.
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.
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.
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.
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.
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.
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 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.
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):
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.
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.
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 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. 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.
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.
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.
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.
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.
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 |
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.
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.
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 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.
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.
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.
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.
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. |
Note 7 — Oil and Gas Properties
We follow the successful efforts method of accounting for our interests in oil and gas properties. Under the successful efforts method, the costs of successful wells and leases containing productive reserves are capitalized. Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. Costs incurred relating to unsuccessful exploratory wells are expensed in the period the drilling is determined to be unsuccessful.
At 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.
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 |
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.
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.
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.
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.
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 |
(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 | % |
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.
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.
Note 13 — 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 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 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).
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.
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.
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.
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.
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.
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
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
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.
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.
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.
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 |
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 |
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.
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 |
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 |
(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.
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. |
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. |
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. |
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 |
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. |
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 | ||||||||||
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 | ||||||||||
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 | |||||||||
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 | |||||||||
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 | ||||||||||
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 | ||||||||||
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 | ||||||||||
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%.