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SECURITIES AND EXCHANGE COMMISSION
the Securities Exchange Act of 1934
(Address of principal executive office)
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ITEM 1 | — FINANCIAL STATEMENTS |
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
$ | $ | $ | $ | |||||||||||||
VOYAGE REVENUES(including $37,294 and $110,382 from related parties for the three and nine months ended September 30, 2009, respectively, and $53,271 and $145,504 for the three and nine months ended September 30, 2008, respectively —notes 10a, 10b,10c, 10k and 10o) | 204,509 | 252,232 | 608,460 | 728,416 | ||||||||||||
OPERATING EXPENSES | ||||||||||||||||
Voyage expenses | 29,363 | 62,548 | 76,405 | 173,736 | ||||||||||||
Vessel operating expenses (including ($200) and ($1,345) from related parties for the three and nine months ended September 30, 2008, respectively —notes 10i and 10l, note 11) | 54,857 | 57,358 | 171,619 | 165,998 | ||||||||||||
Time-charter hire expense (including $3,416 from related parties for the nine months ended September 30, 2009 —note 10n) | 27,772 | 31,474 | 89,061 | 97,382 | ||||||||||||
Depreciation and amortization | 40,981 | 39,675 | 121,366 | 117,864 | ||||||||||||
General and administrative (including $11,070 and $33,826 from related parties for the three and nine months ended September 30, 2009, respectively, and $12,718 and $42,937 for the three and nine months ended September 30, 2008, respectively —notes 10d, 10e, 10f, 10g, and note 11) | 13,820 | 14,537 | 42,140 | 49,640 | ||||||||||||
Restructuring charge (note 8) | 371 | — | 4,053 | — | ||||||||||||
Total operating expenses | 167,164 | 205,592 | 504,644 | 604,620 | ||||||||||||
Income from vessel operations | 37,345 | 46,640 | 103,816 | 123,796 | ||||||||||||
OTHER ITEMS | ||||||||||||||||
Interest expense(including $650 from related parties for the three and nine months ended September 30, 2009, respectively —notes 6 and 10p) | (9,147 | ) | (18,848 | ) | (33,532 | ) | (63,689 | ) | ||||||||
Interest income | 141 | 913 | 1,098 | 3,265 | ||||||||||||
Realized and unrealized (losses) gains on non-designated derivatives(note 11) | (37,302 | ) | (26,120 | ) | 37,716 | (33,019 | ) | |||||||||
Foreign currency exchange (loss) gain(note 11) | (4,359 | ) | 2,175 | (7,988 | ) | (795 | ) | |||||||||
Other income — net(note 9) | 2,068 | 3,067 | 7,055 | 9,436 | ||||||||||||
Total other items | (48,599 | ) | (38,813 | ) | 4,349 | (84,802 | ) | |||||||||
(Loss) income before income tax expense | (11,254 | ) | 7,827 | 108,165 | 38,994 | |||||||||||
Income tax (expense) recovery(note 12) | (20,234 | ) | 34,129 | (26,928 | ) | 34,821 | ||||||||||
Net (loss) income | (31,488 | ) | 41,956 | 81,237 | 73,815 | |||||||||||
Non-controlling interest in net (loss) income | (12,560 | ) | 19,048 | 32,831 | 41,810 | |||||||||||
Dropdown Predecessor’s interest in net (loss) income(note 1) | (5,551 | ) | 2,283 | 11,378 | 237 | |||||||||||
General partner’s interest in net (loss) income | 79 | 3,052 | 1,642 | 9,933 | ||||||||||||
Limited partners’ interest:(note 14) | ||||||||||||||||
Net (loss) income | (13,456 | ) | 17,573 | 35,386 | 21,835 | |||||||||||
Net (loss) income per: | ||||||||||||||||
- Common unit (basic and diluted) | (0.37 | ) | 0.66 | 1.13 | 1.43 | |||||||||||
- Subordinated unit (basic and diluted) | (0.42 | ) | 0.66 | 1.07 | 1.14 | |||||||||||
- Total unit (basic and diluted) | (0.39 | ) | 0.66 | 1.11 | 1.31 | |||||||||||
Weighted average number of units outstanding: | ||||||||||||||||
- Common units (basic and diluted) | 25,056,250 | 20,359,783 | 21,985,714 | 13,794,526 | ||||||||||||
- Subordinated units (basic and diluted) | 9,800,000 | 9,800,000 | 9,800,000 | 9,800,000 | ||||||||||||
- Total units (basic and diluted) | 34,856,250 | 30,159,783 | 31,785,714 | 23,594,526 | ||||||||||||
Cash distributions declared per unit | 0.45 | 0.40 | 1.35 | 1.20 | ||||||||||||
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As at | ||||||||
As at | December 31, | |||||||
September 30, | 2008 | |||||||
2009 | (Note 1) | |||||||
$ | $ | |||||||
ASSETS | ||||||||
Current | ||||||||
Cash and cash equivalents(note 6) | 143,746 | 132,348 | ||||||
Accounts receivable, net | 51,176 | 51,306 | ||||||
Net investment in direct financing leases — current | 21,362 | 22,941 | ||||||
Prepaid expenses | 32,775 | 27,129 | ||||||
Due from affiliate(note 10q) | 13,156 | 10,110 | ||||||
Current portion of derivative instruments(note 11) | 4,684 | — | ||||||
Other current assets | 1,557 | 2,585 | ||||||
Total current assets | 268,456 | 246,419 | ||||||
Vessels and equipment(note 6) | ||||||||
At cost, less accumulated depreciation of $950,732 (December 31, 2008 — $836,087) | 1,952,912 | 2,028,150 | ||||||
Net investment in direct financing leases | 40,276 | 55,710 | ||||||
Derivative instruments(note 11) | 1,368 | — | ||||||
Other assets | 17,311 | 18,728 | ||||||
Intangible assets — net(note 5) | 39,164 | 46,004 | ||||||
Goodwill — shuttle tanker segment | 127,113 | 127,113 | ||||||
Total assets | 2,446,600 | 2,522,124 | ||||||
LIABILITIES AND TOTAL EQUITY | ||||||||
Current | ||||||||
Accounts payable | 9,132 | 12,545 | ||||||
Accrued liabilities | 65,766 | 52,984 | ||||||
Due to affiliate(note 10q) | 37,633 | 8,715 | ||||||
Current portion of long-term debt(note 6) | 77,322 | 125,503 | ||||||
Current portion of derivative instruments(note 11) | 31,203 | 66,135 | ||||||
Due to joint venture partners | 754 | 21,019 | ||||||
Total current liabilities | 221,810 | 286,901 | ||||||
Long-term debt (including a loan due to parent of $220,000 as at September 30, 2009— note 6) | 1,694,116 | 1,711,711 | ||||||
Deferred income tax | 30,449 | 12,648 | ||||||
Derivative instruments(note 11) | 65,121 | 174,355 | ||||||
Other long-term liabilities | 19,166 | 25,316 | ||||||
Total liabilities | 2,030,662 | 2,210,931 | ||||||
Commitments and contingencies(notes 6, 11 and 13) | ||||||||
Total equity | ||||||||
Partners’ equity | 204,181 | 117,910 | ||||||
Non-controlling interest | 211,508 | 201,383 | ||||||
Dropdown predecessor equity | — | 13,811 | ||||||
Accumulated other comprehensive income (loss)(note 7) | 249 | (21,911 | ) | |||||
Total equity | 415,938 | 311,193 | ||||||
Total liabilities and equity | 2,446,600 | 2,522,124 | ||||||
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Nine Months Ended September 30, | ||||||||
2009 | 2008 | |||||||
$ | $ | |||||||
Cash and cash equivalents provided by (used for) | ||||||||
OPERATING ACTIVITIES | ||||||||
Net income | 81,237 | 73,815 | ||||||
Non-cash items: | ||||||||
Unrealized (gain) loss on derivative instruments(note 11) | (83,225 | ) | 22,479 | |||||
Depreciation and amortization | 121,366 | 117,864 | ||||||
Amortization of in-process revenue contract | (4,857 | ) | (7,346 | ) | ||||
Income tax expense (recovery) | 26,928 | (34,821 | ) | |||||
Foreign currency exchange loss (gain) and other — net | 6,326 | (3,221 | ) | |||||
Change in non-cash working capital items related to operating activities | 20,219 | 38,461 | ||||||
Expenditures for drydocking | (27,388 | ) | (26,083 | ) | ||||
Net operating cash flow | 140,606 | 181,148 | ||||||
FINANCING ACTIVITIES | ||||||||
Proceeds from issuance of long-term debt | 119,575 | 259,262 | ||||||
Scheduled repayments of long-term debt | (24,124 | ) | (24,923 | ) | ||||
Prepayments of long-term debt | (241,090 | ) | (138,085 | ) | ||||
Net advances to affiliate | — | (46,544 | ) | |||||
Prepayments of joint venture partner advances | (20,775 | ) | — | |||||
Joint venture partner advances | 474 | — | ||||||
Contribution of capital from Teekay Corporation to Dropdown Predecessor relating toPetrojarl Varg (note 10p) | 110,386 | 72,234 | ||||||
Purchase ofPetrojarl Vargfrom Teekay Corporation(note 10p) | (100,000 | ) | — | |||||
Equity contribution from joint venture partner | 4,772 | — | ||||||
Proceeds from equity offering | 109,227 | 216,837 | ||||||
Expenses from equity offering | (4,945 | ) | (6,171 | ) | ||||
Distribution to Teekay Corporation relating to purchase of SPT Explorer L.L.C. and SPT Navigator L.L.C. (note 10k) | — | (16,661 | ) | |||||
Excess of purchase price over the contributed basis of a 25% interest in Teekay Offshore Operating L.P. (note 10j) | — | (94,882 | ) | |||||
Cash distributions paid by the Partnership | (42,788 | ) | (28,337 | ) | ||||
Cash distributions paid by subsidiaries to non-controlling interest | (44,093 | ) | (58,641 | ) | ||||
Other | (1,114 | ) | (1,538 | ) | ||||
Net financing cash flow | (134,495 | ) | 132,551 | |||||
INVESTING ACTIVITIES | ||||||||
Expenditures for vessels and equipment | (11,726 | ) | (52,990 | ) | ||||
Purchase of 35% ofPetrojarl Vargby Teekay Corporation(note 15) | — | (134,183 | ) | |||||
Investment in direct financing lease assets | — | (537 | ) | |||||
Direct financing lease payments received | 17,013 | 16,956 | ||||||
Purchase of a 25% interest in Teekay Offshore Operating L.P.(note 10j) | — | (111,746 | ) | |||||
Net investing cash flow | 5,287 | (282,500 | ) | |||||
Increase in cash and cash equivalents | 11,398 | 31,199 | ||||||
Cash and cash equivalents, beginning of the period | 132,348 | 128,859 | ||||||
Cash and cash equivalents, end of the period | 143,746 | 160,058 | ||||||
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Accumulated | ||||||||||||||||||||||||||||||||||||
Owner’s | Other | |||||||||||||||||||||||||||||||||||
Equity | PARTNERS’ EQUITY | Comprehensive | Non- | |||||||||||||||||||||||||||||||||
(Dropdown | Limited Partners | General | Income (Loss) | controlling | ||||||||||||||||||||||||||||||||
Predecessor) | Common | Subordinated | Partner | (Note 7) | Interest | Total | ||||||||||||||||||||||||||||||
Units | $ | Units | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||
Balance as at December 31, 2008(note 14) | 13,811 | 20,425 | 246,646 | 9,800 | (135,900 | ) | 7,164 | (21,911 | ) | 201,383 | 311,193 | |||||||||||||||||||||||||
Net income(note 14) | 11,378 | 24,863 | 10,523 | 1,642 | 32,831 | 81,237 | ||||||||||||||||||||||||||||||
Unrealized net gain on qualifying cash flow hedging instruments(note 11) | — | — | — | — | 14,045 | 12,061 | 26,106 | |||||||||||||||||||||||||||||
Realized net loss on qualifying cash flow hedging instruments(note 11) | — | — | — | — | 5,272 | 4,554 | 9,826 | |||||||||||||||||||||||||||||
Comprehensive income | 117,169 | |||||||||||||||||||||||||||||||||||
Contribution of capital from Teekay Corporation to Dropdown Predecessor relating toPetrojarl Varg (note 10p) | 110,386 | — | — | — | — | — | 110,386 | |||||||||||||||||||||||||||||
Net liabilities of Dropdown Predecessor relating toPetrojarl Varg retained by Teekay Corporation on dropdown (note 10p) | 172,174 | — | — | — | 2,843 | — | 175,017 | |||||||||||||||||||||||||||||
Purchase ofPetrojarl Vargfrom Teekay Corporation(note 10p) | (307,749 | ) | (3,934 | ) | (7,712 | ) | (605 | ) | — | — | (320,000 | ) | ||||||||||||||||||||||||
Proceeds from follow-on public offering, net of offering costs(note 3) | — | 7,475 | 102,097 | — | 2,185 | — | — | 104,282 | ||||||||||||||||||||||||||||
Equity contribution from joint venture partner | — | — | — | — | — | 4,772 | 4,772 | |||||||||||||||||||||||||||||
Cash distributions | — | (27,574 | ) | (13,230 | ) | (1,984 | ) | — | (44,093 | ) | (86,881 | ) | ||||||||||||||||||||||||
Balance as at September 30, 2009 | — | 27,900 | 342,098 | 9,800 | (146,319 | ) | 8,402 | 249 | 211,508 | 415,938 | ||||||||||||||||||||||||||
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1. | Summary of Significant Accounting Policies |
Certain information and footnote disclosures required by GAAP for complete annual financial statements have been omitted and, therefore, these interim financial statements should be read in conjunction with the Partnership’s audited consolidated financial statements for the year ended December 31, 2008, which are included on Form 20-F filed on June 29, 2009. In the opinion of management of our general partner, Teekay Offshore GP L.L.C. (or theGeneral Partner), these interim unaudited consolidated financial statements reflect all adjustments, of a normal recurring nature, necessary to present fairly, in all material respects, the Partnership’s consolidated financial position, results of operations, changes in total equity and cash flows for the interim periods presented. The results of operations for the interim periods presented are not necessarily indicative of those for a full fiscal year. Historically, the utilization of shuttle tankers in the North Sea is higher in the winter months and lower in the summer months, as generally there is higher maintenance in the oil fields during the summer months, which leads to lower oil production, and thus, lower shuttle tanker utilization during that period. Significant intercompany balances and transactions have been eliminated upon consolidation. |
As required by Financial Accounting Standards Board (orFASB) ASC 805,Business Combinations, the Partnership accounted for the acquisition of interests in vessels from Teekay Corporation as a transfer of a business between entities under common control. The method of accounting for such transfers is similar to pooling of interests method of accounting. Under this method, the carrying amount of net assets recognized in the balance sheets of each combining entity is carried forward to the balance sheet of the combined entity, and no other assets or liabilities are recognized as a result of the combination. The excess of the proceeds paid, if any, by the Partnership over Teekay Corporation’s historical cost is accounted for as an equity distribution to Teekay Corporation. In addition, transfers of net assets between entities under common control are accounted for as if the transfer occurred from the date that the Partnership and the acquired vessels were both under common control of Teekay Corporation and had begun operations. As a result, the Partnership’s financial statements prior to the date the interests in these vessels were actually acquired by the Partnership are retroactively adjusted to include the results of these vessels operated during the periods under common control of Teekay Corporation. |
On September 10, 2009, the Partnership acquired from Teekay Corporation the floating production storage and offloading (orFPSO) unit, thePetrojarl Varg, together with its four-year contract with Talisman Energy. In June 2008, the Partnership acquired from Teekay Corporation its interest in two 2008-built Aframax lightering tankers, theSPT Explorerand theSPT Navigator. The acquisition included the assumption of debt and Teekay Corporation’s rights and obligations under 10-year, fixed-rate bareboat charters (with options exercisable by the charterer to extend up to an additional five years). These transactions were deemed to be business acquisitions between entities under common control. As a result, the Partnership’s balance sheet as at December 31, 2008, the Partnership’s statements of income (loss) for the three and nine months ended September 30, 2009 and 2008, the Partnership’s statement of cash flows for the nine months ended September 30, 2009 and 2008, and the Partnership’s statement of changes in total equity for the nine months ended September 30, 2009, have been retroactively adjusted to include the results of these acquired vessels (referred to herein as theDropdown Predecessor), from the date that the Partnership and the acquired vessels were both under common control of Teekay Corporation and had begun operations.SPT ExplorerandSPT Navigatorbegan operations on January 7, 2008 and March 28, 2008, respectively. Teekay Corporation acquired a 65% interest in thePetrojarl Vargon October 1, 2006, and acquired the remaining 35% interest on June 30, 2008. The June 2008 acquisition resulted in increases in vessels and equipment ($75.9 million), other non-current assets ($0.5 million), goodwill ($49.2 million), deferred income tax liability ($16.5 million), owner’s equity ($134.2 million) and a decrease in non-controlling interest of $25.1 million. The acquisition was financed with debt. |
For the three months and nine months ended September 30, 2009, the effect of adjusting the Partnership’s financial statements to account for these common control transfers (decreased) increased the Partnership’s net income by ($5.6) million and $11.4 million, respectively and (decreased) increased comprehensive income by ($4.8) million and $13.4 million, respectively. For the three and nine months ended September 30, 2008, the effect of adjusting the Partnership’s financial statements to account for these common control transfers increased the Partnership’s net income by $2.3 million and $4.0 million (of which $3.7 million is attributable to non-controlling interests), respectively, and increased comprehensive income by $1.7 million and $3.4 million, respectively. |
Teekay Corporation uses a centralized treasury system. As a result, cash and cash equivalents attributable to the operations of the Dropdown Predecessor were in certain cases, co-mingled with cash and cash equivalents from other operations of Teekay Corporation. This cash and cash equivalents are not reflected in the balance sheet of the Dropdown Predecessor. However, any cash transactions from these bank accounts that were made on behalf of companies in the Dropdown Predecessor, which were acquired by the Partnership, are reflected as increases or decreases of advances from affiliates. Any other cash transactions from these bank accounts that were directly related to the operations of the Dropdown Predecessor are reflected as increases or decreases in owner’s equity. |
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NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Cont’d)
(all tabular amounts stated in thousands of U.S. dollars, except unit and per unit data)
For periods prior to the Partnership’s acquisition of thePetrojarl Varg, the vessel was used as collateral for certain credit facilities (theVarg Credit Facilities). ThePetrojarl Varg’s pro-rata share of the Varg Credit Facilities has been allocated to the Dropdown Predecessor. The pro-rata share was determined using the relative fair value of the Varg Business compared to the fair value of all net assets used as collateral for these facilities. The Varg Credit Facilities were used directly to partially finance the purchase of the vessel. Interest has been allocated to the Dropdown Predecessor based on thePetrojarl Varg’sshare of these facilities. In addition, Teekay Corporation used certain of its corporate facilities to finance the remaining portion of the acquisition of thePetrojarl Varg. Interest has been allocated to the Dropdown Predecessor based on the amount drawn on these facilities at the time of the acquisition and Teekay Corporation’s weighted average borrowing cost. In addition, Teekay Corporation has entered into certain interest rate swaps. The Varg’s pro-rata share of these interest rate swaps has been allocated to the Dropdown Predecessor. The pro-rata share was determined using the relative collateral fair values of the Varg Credit Facilities, |
For periods prior to the Partnership’s acquisition of thePetrojarl Varg, the operations of the vessel were generally subject to Norwegian tax. The operations of the vessel were carved out from a number of different subsidiaries of Teekay Corporation. Certain of these subsidiaries were a part of one or more Norwegian tax groups. Income tax attributable to thePetrojarl Varg has been allocated using the separate return method. Under this method, income tax is calculated as if thePetrojarl Varghad been in its own tax group and not part of the larger tax group. The income taxes attributable to thePetrojarl Vargin the Dropdown Predecessor reflect its historical tax status and do not reflect its change in tax status as a result of the Partnership’s acquisition. All net operating loss carryforwards related to thePetrojarl Varg in the Dropdown Predecessor, would be available to offset future taxable income of the Dropdown Predecessor in Norway. However, none of these loss carryforwards are available to be used by the Partnership, subsequent to its acquisition of thePetrojarl Varg. Current tax payable related toPetrojarl Vargduring the Dropdown Predecessor periods, is assumed to be paid by Teekay Corporation and has been reflected as an increase in owner’s equity. |
General and administrative expenses (consisting primarily of salaries, defined benefit pension plan benefits, and other employee related costs, office rent, legal and professional fees, and travel and entertainment) were allocated to the Dropdown Predecessor based on estimated use of resources. In addition, Teekay Corporation has entered into certain foreign exchange forward contracts to minimize the impact from changes in the foreign exchange rate between the Norwegian Kroner and the US Dollar on its operating expenditures. A portion of these foreign exchange forward contracts have been accounted for as hedges and were allocated to the Dropdown Predecessor based on the relative amount of Norwegian Kroner expenditures from thePetrojarl Vargcompared to Teekay’s other operations that the contracts were entered into for. |
The consolidated financial statements reflect the combined consolidated financial position, results of operations and cash flows of the Partnership and its subsidiaries, including, as applicable, the Dropdown Predecessor. In the preparation of these consolidated financial statements, general and administrative expenses, interest expense and realized and unrealized (losses) gains on non-designated derivative instruments were not identifiable as relating solely to each specific vessel. During the three and nine months ended September 30, 2009, $0.4 million and $3.5 million of general and administrative expenses, $1.7 million and $6.5 million of interest expense, and ($6.3) million and $6.8 million in realized and unrealized (losses) gains on non-designated derivative instruments were attributable to the Dropdown Predecessor, respectively. During the three and nine months ended September 30, 2008, $1.7 million and $5.2 million of general and administrative expenses, $4.1 million and $12.0 million of interest expense, and ($5.6) million and ($6.2) million in realized and unrealized losses on non-designated derivative instruments were attributable to the Dropdown Predecessor, respectively. Management believes these allocations reasonably present the general and administrative expenses, interest expense, and realized and unrealized (losses) gains on non-designated derivative instruments of the Dropdown Predecessor. Estimates have been made when allocating expenses from Teekay Corporation to the Dropdown Predecessor and such estimates may not be reflective of actual results. |
Certain of the comparative figures have been reclassified to conform with the presentation adopted in the current period. |
The Partnership evaluated events and transactions occurring after the balance sheet date and through the day the financial statements were issued. The date of issuance of the financial statements was February 16, 2010 (date filed). | ||
Changes in Accounting Policies |
(a) | In January 2009, the Partnership adopted an amendment to FASB ASC 805,Business Combinations. This amendment requires an acquirer to recognize the assets acquired, the liabilities assumed, and any non-controlling interest in the acquiree at the acquisition date, measured at their fair values as of that date. This amendment also requires the acquirer in a business combination achieved in stages to recognize the identifiable assets and liabilities, as well as the non-controlling interest in the acquiree, at the full fair values of the assets and liabilities as if they had occurred on the acquisition date. In addition, this amendment requires that all acquisition related costs be expensed as incurred, rather than capitalized as part of the purchase price, and those restructuring costs that an acquirer expected, but was not obligated to incur, be recognized separately from the business combination. The amendment applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The Partnership’s adoption of this amendment did not have a material impact on the Partnership’s consolidated financial statements. |
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NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Cont’d)
(all tabular amounts stated in thousands of U.S. dollars, except unit and per unit data)
(b) | In January 2009, the Partnership adopted an amendment to FASB ASC 810,Consolidation, which requires us to make certain changes to the presentation of our financial statements. This amendment requires that non-controlling interests in subsidiaries held by parties other than the partners be identified, labeled and presented in the statement of financial position within equity, but separate from the partners’ equity. This amendment requires that the amount of consolidated net income (loss) attributable to the partners and to the non-controlling interest be clearly identified on the consolidated statements of income (loss). In addition, this amendment provides for consistency regarding changes in partners’ ownership including when a subsidiary is deconsolidated. Any retained non-controlling equity investment in the former subsidiary will be initially measured at fair value. Except for the presentation and disclosure provisions of this amendment, which were adopted retrospectively to the Partnership’s consolidated financial statements, this amendment was adopted prospectively. |
Consolidated net income attributable to the partners would have been different in the three and nine months ended September 30, 2009 had the amendment to FASB ASC 810 not been adopted. Losses attributable to the non-controlling interest that exceed the entity’s (Gothenburg L.L.C.) equity capital would have been charged against the majority interest, as there was no obligation of the non-controlling interest to cover such losses. However, if future earnings do materialize, the majority interest should have been credited to the extent of such losses previously absorbed. Pro forma consolidated net income (loss) attributed to non-controlling interest and to the partners and pro forma income (loss) per unit had the amendment to FASB ASC 810 not been adopted are as follows: |
Three Months Ended | Nine Months Ended | |||||||
September 30, 2009 | September 30, 2009 | |||||||
$ | $ | |||||||
Net (loss) income | (31,488 | ) | 81,237 | |||||
Pro forma non-controlling interest in net (loss) income | (12,063 | ) | 29,887 | |||||
Pro forma net (loss) income allocated to the Dropdown Predecessor | (5,551 | ) | 11,378 | |||||
Pro forma net (loss) income allocated to the Partnership | (13,874 | ) | 39,972 | |||||
Pro forma (loss) earnings per unit: | ||||||||
- Common unit (basic and diluted) | (0.39 | ) | 1.22 | |||||
- Subordinated unit (basic and diluted) | (0.44 | ) | 1.16 |
(c) | In January 2009, the Partnership adopted an amendment to FASB ASC 820 Fair Value Measurements and Disclosures, which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements for non-financial assets and non-financial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). Non-financial assets and non-financial liabilities include all assets and liabilities other than those meeting the definition of a financial asset or financial liability. The Partnership’s adoption of this amendment did not have a material impact on the Partnership’s consolidated financial statements. |
(d) | In January 2009, the Partnership adopted an amendment to FASB ASC 815Derivatives and Hedging,which requires expanded disclosures about a company’s derivative instruments and hedging activities, including increased qualitative, and credit-risk disclosures. See Note 11 of the notes to the consolidated financial statements. |
(e) | In January 2009, the Partnership adopted an amendment to FASB ASC 260,Earnings Per Share,which provides guidance on earnings-per-unit (orEPU) computations for all master limited partnerships (orMLPs) that distribute “available cash”, as defined in the respective partnership agreements, to limited partners, the general partner, and the holders of incentive distribution rights (orIDRs). MLPs will need to determine the amount of “available cash” at the end of the reporting period when calculating the period’s EPU. This amendment was applied retrospectively to all periods presented. See Note 14 of the notes to the consolidated financial statements. |
(f) | In January 2009, the Partnership adopted an amendment to FASB ASC 350,Intangibles — Goodwill and Other,which amends the factors that should be considered in developing renewal or extension of assumptions used to determine the useful life of a recognized intangible asset. The adoption of the amendment did not have a material impact on the Partnership’s consolidated financial statements. |
(g) | In January 2009, the Partnership adopted an amendment to FASB ASC 323,Investments-Equity Method and Joint Ventures,which provides addresses the accounting for the acquisition of equity method investments, for changes in value and changes in ownership levels. The adoption of this amendment did not have a material impact on the Partnership’s consolidated financial statements. |
(h) | In April 2009, the Partnership adopted an amendment to FASB ASC 825,Financial Instruments,which requires that disclosure of the fair value of financial instruments be provided on a quarterly basis and that disclosures provide qualitative and quantitative information on fair value estimates for all financial instruments not measured on the balance sheet at fair value, when practicable, with the exception of certain financial instruments (see Note 2). |
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NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Cont’d)
(all tabular amounts stated in thousands of U.S. dollars, except unit and per unit data)
(i) | In April 2009, the Partnership adopted an amendment to FASB ASC 855,Subsequent Events, which established general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. This amendment requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for selecting that date, that is, whether that date represents the date the financial statements were issued or were available to be issued. This amendment is effective for interim and annual reporting periods ending after June 15, 2009. |
(j) | In June 2009, the FASB issued the FASB ASC effective for financial statements issued for interim and annual periods ending after September 15, 2009. The ASC identifies the source of GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the Securities and Exchange Commission (orSEC) under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. On the effective date, the ASC superseded all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the ASC will become non-authoritative. The Partnership adopted the ASC on July 1, 2009 and incorporated it in the Partnership’s notes to the consolidated financial statements. |
2. | Fair Value Measurements |
The following methods and assumptions were used to estimate the fair value of each class of financial instrument: |
Cash and cash equivalents— The fair value of the Company’s cash and cash equivalents approximates its carrying amounts reported in the consolidated balance sheets. |
Due to / from affiliates— The fair value of the amounts due to and from affiliates approximates their carrying amounts reported in the consolidated balance sheets. |
Long-term debt— The fair values of the Partnership’s variable-rate long-term debt are either based on quoted market prices or estimated using discounted cash flow analyses, based on rates currently available for debt with similar terms and remaining maturities and the current credit worthiness of the Partnership. |
Due to joint venture partners and Due to parent— The fair value of the Partnership’s loans from joint venture partners and loan from parent approximates their carrying amounts reported in the accompanying consolidated balance sheets. |
Derivative instruments— The fair value of the Partnership’s derivative instruments is the estimated amount that the Partnership would receive or pay to terminate the agreements at the reporting date, taking into account current interest rates, foreign exchange rates and the current credit worthiness of both the Partnership and the derivative counterparties. The estimated amount is the present value of future cash flows. Given the current volatility in the credit markets, it is reasonably possible that the amount recorded as a derivative liability could vary by a material amount in the near term. |
The Partnership categorizes its fair value estimates using a fair value hierarchy based on the inputs used to measure fair value. The fair value hierarchy has three levels based on the reliability of the inputs used to determine fair value as follows: |
The estimated fair value of the Partnership’s financial instruments and categorization using the fair value hierarchy is as follows: |
Fair Value | September 30, 2009 | |||||||||||
Hierarchy | Carrying Amount | Fair Value | ||||||||||
Level | Asset (Liability) | Asset (Liability) | ||||||||||
$ | $ | |||||||||||
Cash and cash equivalents | — | 143,746 | 143,746 | |||||||||
Due from affiliate (note 10q) | — | 13,156 | 13,156 | |||||||||
Due to affiliate(note10q) | — | (37,633 | ) | (37,633 | ) | |||||||
Long-term debt | Level 2 | (1,551,438 | ) | (1,420,266 | ) | |||||||
Loan due to parent(note 6) | — | (220,000 | ) | (220,000 | ) | |||||||
Due to joint venture partners | — | (754 | ) | (754 | ) | |||||||
Derivative instruments(1)(note 11) | ||||||||||||
Interest rate swap agreements(2) | Level 2 | (106,912 | ) | (106,912 | ) | |||||||
Foreign currency forward contracts | Level 2 | 5,965 | 5,965 |
(1) | The Partnership transacts all of its derivative instruments through investment-grade rated financial institutions at the time of the transaction and requires no collateral from these institutions. | |
(2) | The fair value of the Partnership’s interest rate swap agreements includes $10.7 million of accrued interest which is recorded in accrued liabilities on the consolidated balance sheet. |
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Cont’d)
(all tabular amounts stated in thousands of U.S. dollars, except unit and per unit data)
The Partnership has determined that there are no non-financial assets or non-financial liabilities carried at fair value at September 30, 2009. |
3. | Public Offering |
On August 4, 2009, the Partnership completed a public offering of 6.5 million common units at a price of $14.32 per unit, for gross proceeds of $95.0 million (including the general partner’s $1.9 million proportionate capital contribution). The underwriters concurrently exercised their overallotment option to purchase an additional 975,000 units on August 4, 2009, providing additional gross proceeds of $14.2 million (including the general partner’s $0.3 million proportionate capital contribution). The Partnership used the total net proceeds of approximately $104.3 million from the equity offering to reduce amounts outstanding under one of its revolving credit facilities. |
4. | Segment Reporting |
The Partnership is engaged in the international marine transportation of crude oil through the operation of its oil tankers and floating storage and off-take (orFSO) units and FPSO units. The Partnership’s revenues are earned in international markets. |
The Partnership has four reportable segments: its shuttle tanker segment; its conventional tanker segment; its FSO segment, and its FPSO segment. The Partnership’s shuttle tanker segment consists of shuttle tankers operating primarily on fixed-rate contracts of affreightment, time-charter contracts or bareboat charter contracts. The Partnership’s conventional tanker segment consists of conventional tankers operating on fixed-rate, time-charter contracts or bareboat charter contracts. The Partnership’s FSO segment consists of its FSO units subject to fixed-rate, time-charter contracts or bareboat charter contracts. The Partnership’s FPSO segment consists of its FPSO unit subject to a fixed-rate, time-charter contract. Segment results are evaluated based on income from vessel operations. The accounting policies applied to the reportable segments are the same as those used in the preparation of the Partnership’s consolidated financial statements. |
The following tables include results for these segments from continuing operations for the periods presented in these consolidated financial statements. |
Shuttle | Conventional | |||||||||||||||||||
Tanker | Tanker | FSO | FPSO | |||||||||||||||||
Three Months ended September 30, 2009 | Segment | Segment | Segment | Segment | Total | |||||||||||||||
Voyage revenues | 132,794 | 31,409 | 14,781 | 25,525 | 204,509 | |||||||||||||||
Voyage expenses | 22,481 | 6,610 | 272 | — | 29,363 | |||||||||||||||
Vessel operating expenses | 31,751 | 6,210 | 6,876 | 10,020 | 54,857 | |||||||||||||||
Time-charter hire expense | 27,772 | — | — | — | 27,772 | |||||||||||||||
Depreciation and amortization | 23,670 | 6,208 | 5,470 | 5,633 | 40,981 | |||||||||||||||
General and administrative(1) | 11,173 | 1,124 | 892 | 631 | 13,820 | |||||||||||||||
Restructuring charge | 371 | — | — | — | 371 | |||||||||||||||
Income from vessel operations | 15,576 | 11,257 | 1,271 | 9,241 | 37,345 | |||||||||||||||
Shuttle | Conventional | |||||||||||||||||||
Tanker | Tanker | FSO | FPSO | |||||||||||||||||
Three Months ended September 30, 2008 | Segment | Segment | Segment | Segment | Total | |||||||||||||||
Voyage revenues | 168,390 | 40,652 | 17,905 | 25,285 | 252,232 | |||||||||||||||
Voyage expenses | 47,338 | 14,713 | 497 | — | 62,548 | |||||||||||||||
Vessel operating expenses | 32,469 | 6,433 | 7,045 | 11,411 | 57,358 | |||||||||||||||
Time-charter hire expense | 31,474 | — | — | — | 31,474 | |||||||||||||||
Depreciation and amortization | 22,880 | 5,636 | 5,526 | 5,633 | 39,675 | |||||||||||||||
General and administrative(1) | 9,617 | 2,458 | 804 | 1,658 | 14,537 | |||||||||||||||
Income from vessel operations | 24,612 | 11,412 | 4,033 | 6,583 | 46,640 | |||||||||||||||
Shuttle | Conventional | |||||||||||||||||||
Tanker | Tanker | FSO | FPSO | |||||||||||||||||
Nine Months ended September 30, 2009 | Segment | Segment | Segment | Segment | Total | |||||||||||||||
Voyage revenues | 396,721 | 92,738 | 45,970 | 73,031 | 608,460 | |||||||||||||||
Voyage expenses | 56,651 | 19,034 | 720 | — | 76,405 | |||||||||||||||
Vessel operating expenses | 106,010 | 17,542 | 18,955 | 29,112 | 171,619 | |||||||||||||||
Time-charter hire expense | 89,061 | — | — | — | 89,061 | |||||||||||||||
Depreciation and amortization | 70,010 | 18,166 | 16,291 | 16,899 | 121,366 | |||||||||||||||
General and administrative(1) | 32,269 | 3,841 | 2,352 | 3,678 | 42,140 | |||||||||||||||
Restructuring charge | 4,053 | — | — | — | 4,053 | |||||||||||||||
Income from vessel operations | 38,667 | 34,155 | 7,652 | 23,342 | 103,816 | |||||||||||||||
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Cont’d)
(all tabular amounts stated in thousands of U.S. dollars, except unit and per unit data)
Shuttle | Conventional | |||||||||||||||||||
Tanker | Tanker | FSO | FPSO | |||||||||||||||||
Nine Months ended September 30, 2008 | Segment | Segment | Segment | Segment | Total | |||||||||||||||
Voyage revenues | 488,715 | 114,248 | 53,400 | 72,053 | 728,416 | |||||||||||||||
Voyage expenses | 131,533 | 40,976 | 1,227 | — | 173,736 | |||||||||||||||
Vessel operating expenses | 94,365 | 18,544 | 20,737 | 32,352 | 165,998 | |||||||||||||||
Time-charter hire expense | 97,382 | — | — | — | 97,382 | |||||||||||||||
Depreciation and amortization | 68,599 | 16,612 | 18,190 | 14,463 | 117,864 | |||||||||||||||
General and administrative(1) | 35,106 | 6,531 | 2,846 | 5,157 | 49,640 | |||||||||||||||
Income from vessel operations | 61,730 | 31,585 | 10,400 | 20,081 | 123,796 | |||||||||||||||
(1) | Includes direct general and administrative expenses and indirect general and administrative expenses (allocated to each segment based on estimated use of corporate resources). |
A reconciliation of total segment assets to total assets presented in the accompanying consolidated balance sheets is as follows: |
September 30, | December 31, | |||||||
2009 | 2008 | |||||||
$ | $ | |||||||
Shuttle tanker segment | 1,538,095 | 1,584,473 | ||||||
Conventional tanker segment | 324,892 | 332,705 | ||||||
FSO segment | 105,746 | 116,789 | ||||||
FPSO segment | 317,549 | 341,172 | ||||||
Unallocated: | ||||||||
Cash and cash equivalents | 143,746 | 132,348 | ||||||
Other assets | 16,572 | 14,637 | ||||||
Consolidated total assets | 2,446,600 | 2,522,124 | ||||||
5. | Intangible Assets |
As at September 30, 2009, intangible assets consisted of: |
Gross Carrying | Accumulated | Net Carrying | ||||||||||
Amount | Amortization | Amount | ||||||||||
$ | $ | $ | ||||||||||
Contracts of affreightment | 124,250 | (85,753 | ) | 38,497 | ||||||||
Time-charter contracts | 353 | (76 | ) | 277 | ||||||||
Other intangible assets | 390 | — | 390 | |||||||||
124,993 | (85,829 | ) | 39,164 | |||||||||
As at December 31, 2008, intangible assets consisted of: |
Gross Carrying | Accumulated | Net Carrying | ||||||||||
Amount | Amortization | Amount | ||||||||||
$ | $ | $ | ||||||||||
Contracts of affreightment | 124,250 | (78,960 | ) | 45,290 | ||||||||
Time-charter contracts | 353 | (29 | ) | 324 | ||||||||
Other intangible assets | 390 | — | 390 | |||||||||
124,993 | (78,989 | ) | 46,004 | |||||||||
Aggregate amortization expense of intangible assets for the three and nine months ended September 30, 2009 was $2.3 million and $6.9 million, respectively (2008 — $2.5 million and $7.5 million, respectively), included in depreciation and amortization on the consolidated statements of income (loss). Amortization of intangible assets for the next five years subsequent to September 30, 2009 is expected to be $2.3 million (remainder of 2009), $8.1 million (2010), $7.1 million (2011), $6.1 million (2012), and $5.1 million (2013). |
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NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Cont’d)
(all tabular amounts stated in thousands of U.S. dollars, except unit and per unit data)
6. | Long-Term Debt |
September 30, | December 31, | |||||||
2009 | 2008 | |||||||
$ | $ | |||||||
U.S. Dollar-denominated Revolving Credit Facilities due through 2018 | 1,276,008 | 1,314,264 | ||||||
U.S. Dollar-denominated Term Loan Due to Parent | 220,000 | — | ||||||
U.S. Dollar-denominated Debt allocated from Parent | — | 270,778 | ||||||
U.S. Dollar-denominated Term Loans due through 2017 | 275,430 | 252,172 | ||||||
1,771,438 | 1,837,214 | |||||||
Less current portion | 77,322 | 125,503 | ||||||
Total | 1,694,116 | 1,711,711 | ||||||
As at September 30, 2009, the Partnership had seven long-term revolving credit facilities, which, as at such date, provided for borrowings of up to $1.39 billion, of which $115.0 million was undrawn. The total amount available under the revolving credit facilities reduces by $60.1 million (remainder of 2009), $132.8 million (2010), $140.0 million (2011), $147.6 million (2012), $169.6 million (2013) and $740.9 million (thereafter). Five of the revolving credit facilities are guaranteed by certain subsidiaries of the Partnership for all outstanding amounts and contain covenants that require Teekay Offshore Operating L.P. (orOPCO) to maintain the greater of a minimum liquidity (cash, cash equivalents and undrawn committed revolving credit lines with at least six months to maturity) of at least $75.0 million and 5.0% of OPCO’s total consolidated debt. The remaining revolving credit facilities are guaranteed by Teekay Corporation and contain covenants that require Teekay Corporation to maintain the greater of a minimum liquidity (cash and cash equivalents) of at least $50.0 million and 5.0% of Teekay Corporation’s total consolidated debt which has recourse to Teekay Corporation. The revolving credit facilities are collateralized by first-priority mortgages granted on 33 of the Partnership’s vessels, together with other related security. |
The Partnership has a U.S. Dollar-denominated term loan outstanding to Teekay Corporation, which, as at September 30, 2009, totaled $220 million. The senior tranche is a $160 million secured loan with a maximum term of fifteen months bearing interest based on LIBOR plus a margin of 3.25%. The junior tranche is a $60 million unsecured subordinated debt facility bearing interest at a fixed rate of 10.00%. The junior tranche matures at the earlier of the date the Partnership receives sufficient net proceeds from an equity offering to repay this tranche, and a term of five years. In November 2009 the senior tranche was repaid subsequent to the Partnership entering into a $260 million revolving credit facility relating to its FPSO, thePetrojarl Varg. (See Note 16). |
As at December 31, 2008, the Dropdown Predecessor had $270.8 million of long-term debt, which was allocated from corporate revolving credit facilities of Teekay Corporation. (See Note 1). This long-term debt, which was allocated from Teekay Corporation, was retained by Teekay Corporation on the acquisition of thePetrojarl Varg on September 10, 2009. (See Note 10p). |
As at September 30, 2009, the Partnership’s six 50%-owned subsidiaries each had an outstanding term loan, which in the aggregate totaled $275.4 million. The term loans reduce over time with quarterly and semi-annual payments and have varying maturities through 2017. All term loans are collateralized by first-priority mortgages on the vessels to which the loans relate, together with other related security. As at September 30, 2009, the Partnership had guaranteed $88.6 million of these term loans, which represents its 50% share of the outstanding vessel mortgage debt of five of these 50%-owned subsidiaries. The other owner and Teekay Corporation have guaranteed the remaining $186.8 million. |
Interest payments on the revolving credit facilities and the term loans are based on LIBOR plus a margin. At September 30, 2009, the margins ranged between 0.45% and 3.25%. The weighted-average effective interest rate on the Partnership’s variable long-term debt as at September 30, 2009 was 1.7%. This rate does not include the effect of the Partnership’s interest rate swaps (Note 11). |
The aggregate annual long-term debt principal repayments required to be made subsequent to September 30, 2009 are $10.8 million (remainder of 2009), $293.2 million (2010), $183.8 million (2011), $160.7 million (2012), $169.0 million (2013), and $953.9 million (thereafter). |
7. | Accumulated Other Comprehensive Income (Loss) |
As at September 30, 2009 and December 31, 2008, the Partnership’s accumulated other comprehensive income (loss) consisted of the following components: |
September 30, | December 31, | |||||||
2009 | 2008 | |||||||
$ | $ | |||||||
Unrealized gain (loss) on derivative instruments | 249 | (18,843 | ) | |||||
Pension adjustments | — | (3,068 | ) | |||||
249 | (21,911 | ) | ||||||
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NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Cont’d)
(all tabular amounts stated in thousands of U.S. dollars, except unit and per unit data)
8. | Restructuring Charge |
During the nine months ended September 30, 2009, the Partnership commenced the reflagging of seven of its vessels from Norwegian flag to Bahamian flag and changing the nationality mix of its crews. Under this plan, the Partnership expects to record and pay restructuring charges consisting primarily of one-time termination benefits of approximately $4.7 million during 2009. During the three and nine months ended September 30, 2009, the Partnership incurred $0.4 million and $4.1 million of restructuring costs, respectively. |
9. | Other Income — net |
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
$ | $ | $ | $ | |||||||||||||
Volatile organic compound emissions plant lease income | 1,662 | 2,677 | 5,428 | 7,642 | ||||||||||||
Miscellaneous | 406 | 390 | 1,627 | 1,794 | ||||||||||||
Other income — net | 2,068 | 3,067 | 7,055 | 9,436 | ||||||||||||
10. | Related Party Transactions and Balances |
a. | Nine of OPCO’s conventional tankers are employed on long-term time-charter contracts with a subsidiary of Teekay Corporation. Under the terms of seven of these nine time-charter contracts, OPCO is responsible for the bunker fuel expenses; however, OPCO adds the approximate amounts of these expenses to the daily hire rate plus a 4.5% margin. Pursuant to these charter contracts, OPCO earned voyage revenues of $28.9 million and $85.3 million, respectively, during the three and nine months ended September 30, 2009, compared to $38.3 million and $108.0 million, respectively, for the same periods last year. |
b. | Two of OPCO’s shuttle tankers are employed on long-term bareboat charters with a subsidiary of Teekay Corporation. Pursuant to these charter contracts, OPCO earned voyage revenues of $3.1 million and $9.3 million, respectively, during the three and nine months ended September 30, 2009, compared to $3.3 million and $11.6 million, respectively, for the same periods last year. |
c. | Two of OPCO’s FSO units are employed on long-term bareboat charters with a subsidiary of Teekay Corporation. Pursuant to these charter contracts, OPCO earned voyage revenues of $2.8 million and $8.4 million, respectively, during both the three and nine months ended September 30, 2009, and 2008. |
d. | A subsidiary of Teekay Corporation has entered into a services agreement with a subsidiary of OPCO, pursuant to which the subsidiary of OPCO provides the Teekay Corporation subsidiary with ship management services. Pursuant to this agreement, OPCO earned management fees of $0.7 million and $2.3 million, respectively, during the three and nine months ended September 30, 2009, compared to $0.8 million and $2.4 million, respectively, for the same periods last year. |
e. | Eight of OPCO’S Aframax conventional oil tankers, two FSO units and the FPSO unit are managed by subsidiaries of Teekay Corporation. Pursuant to the associated management services agreements, the Partnership incurred general and administrative expenses of $1.0 million and $2.5 million, respectively, during the three and nine months ended September 30, 2009, compared to $1.0 million and $3.0 million, respectively, for the same periods last year. During the three months ended September 30, 2009 and 2008, $0.4 million and $1.7 million, respectively, of general and administrative expenses attributable to the operations of vessels the Partnership acquired from Teekay Corporation were incurred by Teekay Corporation, but also allocated to the Partnership as part of the results of the Dropdown Predecessor. During the nine months ended September 30, 2009 and 2008, $3.5 million and $5.2 million, respectively, of general and administrative expenses attributable to the operations of vessels the Partnership acquired from Teekay Corporation were incurred by Teekay Corporation, but also allocated to the Partnership as part of the results of the Dropdown Predecessor (see Note 1). |
f. | The Partnership, OPCO and certain of OPCO’s operating subsidiaries have entered into services agreements with certain subsidiaries of Teekay Corporation in connection with the Partnership’s initial public offering, pursuant to which Teekay Corporation subsidiaries provide the Partnership, OPCO and its operating subsidiaries with administrative, advisory and technical services and ship management services. Pursuant to these services agreements, the Partnership incurred $10.1 million and $29.6 million, respectively, of these costs during the three and nine months ended September 30, 2009, compared to $10.7 million and $36.7 million, respectively, for the same periods last year. |
g. | Pursuant to the Partnership’s partnership agreement, the Partnership reimburses the General Partner for all expenses incurred by the General Partner that are necessary or appropriate for the conduct of the Partnership’s business. Pursuant to this agreement, the Partnership reimbursed $0.3 million and $0.5 million, respectively, of these costs during the three and nine months ended September 30, 2009, compared to $0.1 million and $0.4 million, respectively, for the same periods last year. |
h. | The Partnership has entered into an omnibus agreement with Teekay Corporation, Teekay LNG Partners L.P., the General Partner and others governing, among other things, when the Partnership, Teekay Corporation and Teekay LNG Partners L.P. may compete with each other and certain rights of first offering on liquefied natural gas carriers, oil tankers, shuttle tankers, FSO units and floating production, storage and offloading units. |
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NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Cont’d)
(all tabular amounts stated in thousands of U.S. dollars, except unit and per unit data)
i. | In March 2008, Teekay Corporation agreed to reimburse the Partnership for repair costs relating to one of the Partnership’s shuttle tankers. The vessel was purchased from Teekay Corporation in July 2007 and had, as of the date of acquisition, an inherent minor defect that required repairs. Pursuant to this agreement, Teekay Corporation reimbursed $0.2 million and $0.6 million, respectively, of these costs during the three and nine months ended September 30, 2008. |
j. | On June 18, 2008, the Partnership acquired from Teekay Corporation an additional 25% interest in OPCO for $205.5 million, thereby increasing the Partnership’s ownership interest in OPCO to 51%. The Partnership financed the acquisition with the net proceeds from a follow-on public offering and a concurrent private placement to Teekay Corporation of common units. The excess of the proceeds paid by the Partnership over Teekay Corporation’s historical book value for the 25% interest in OPCO was accounted for as an equity distribution to Teekay Corporation of $93.8 million. |
k. | On June 18, 2008, OPCO acquired from Teekay Corporation two ship owning subsidiaries (SPT Explorer L.L.C. and the SPT Navigator L.L.C.) for a total cost of approximately $106.0 million, including the assumption of third-party debt of approximately $89.3 million and the non-cash settlement of related party working capital of $1.2 million. The acquired subsidiaries own two 2008-built Aframax lightering tankers (theSPT Explorerand theSPT Navigator) and their related 10-year, fixed-rate bareboat charters (with options exercisable by the charterer to extend up to an additional five years) entered into with Skaugen PetroTrans, a joint venture in which Teekay Corporation owns a 50% interest. These two lightering tankers are specially designed to be used in ship-to-ship oil transfer operations. This purchase was financed with the assumption of debt, together with cash balances. The excess of the proceeds paid by the Partnership over Teekay Corporation’s historical book value was accounted for as an equity distribution to Teekay Corporation of $16.2 million. Pursuant to the bareboat charters for the vessels, OPCO earned voyage revenues of $2.5 million and $7.4 million, respectively, for the three and nine months ended September 30, 2009 compared to $2.5 million and $6.2 million, for the same periods last year, respectively (including voyage revenues earned by the Dropdown Predecessor prior to OPCO’s acquisition of the vessels — see Note 1). |
l. | In June 2008, Teekay Corporation agreed to reimburse OPCO for certain costs relating to events which occurred prior to the Partnership’s initial public offering in December 2006, totalling $0.7 million, primarily relating to the settlement of repair costs not covered by insurance providers for work performed in early 2006 on two of OPCO’s shuttle tankers. |
m. | In March 2008, a subsidiary of OPCO sold certain vessel equipment to a subsidiary of Teekay Corporation for proceeds equal to its net book value of $1.4 million. |
n. | From December 2008 to June 2009, OPCO entered into a bareboat charter contract to in-charter one shuttle tanker from a subsidiary of Teekay Corporation. Pursuant to the charter contract, OPCO incurred time-charter hire expenses of $3.4 million during the nine months ended September 30, 2009. |
o. | Two of OPCO’s in-chartered shuttle tankers were employed on single-voyage charters with a subsidiary of Teekay Corporation. Pursuant to these charter contracts, OPCO earned voyage revenues of $6.4 million and $11.3 million for the three and nine months ended September 30, 2008. |
p. | On September 10, 2009, the Partnership acquired from Teekay Corporation thePetrojarl Varg,together with its four-year fixed rate contract with Talisman Energy, for a purchase price of $320 million. The purchase price of $320 million is accounted for as an equity distribution to Teekay Corporation. To the extent the purchase price is greater than the corresponding book value, the excess is reflected as a reduction in Partners’ Equity and the remainder is shown as a reduction in Dropdown Predecessor Equity. The purchase was financed through vendor financing made available by Teekay Corporation of $220 million. The remaining $100 million was paid in cash and financed from existing debt facilities. The $220 million vendor financing from Teekay Corporation is comprised of two tranches. The senior tranche is a $160 million short-term debt facility bearing interest at LIBOR plus a margin of 3.25%. (This senior tranche was repaid in November 2009 — see Note 16). The junior tranche of the vendor financing is a $60 million unsecured subordinated debt facility bearing interest at 10% per annum. For both the three and nine months ended September 30, 2009, the Partnership incurred interest expense of $0.6 million in relation to the $220 million vendor financing from Teekay Corporation. (See Notes 1 and 6). |
On the dropdown, all assets and liabilities of thePetrojarl Vargoperations, except for the vessel and the contract with Talisman Energy, were retained by Teekay Corporation. These net assets (net liabilities) retained by Teekay Corporation totalled $(175.0) million and are accounted for as a non-cash equity contribution from Teekay Corporation. |
Teekay uses a centralized treasury system. As a result, cash and cash equivalents attributable to the operations of thePetrojarl Varg, prior to the acquisition of the vessel by the Partnership, were in certain cases, co-mingled with cash and cash equivalents from other operations of Teekay Corporation. Cash and cash equivalents in co-mingled bank accounts are not reflected in the balance sheet of the Dropdown Predecessor. However, any cash transactions from these bank accounts that were made on behalf of the Dropdown Predecessor are reflected in these financial statements as increases or decreases in Dropdown Predecessor Equity. The net amount of these equity contributions were $110.4 million for the period from January 1, 2009 to September 9, 2009 and $72.2 million for the nine months ended September 30, 2008. |
q. | At September 30, 2009, due from affiliates totaled $13.2 million (December 31, 2008 - $10.1 million) and due to affiliates totaled $37.6 million (December 31, 2008 — $8.7 million). Due to and from affiliate are non-interest bearing and unsecured. |
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NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Cont’d)
(all tabular amounts stated in thousands of U.S. dollars, except unit and per unit data)
11. | Derivative Instruments and Hedging Activities |
The Partnership uses derivatives in accordance with its overall risk management policies. The following summarizes the Partnership’s risk strategies with respect to market risk from foreign currency fluctuations and changes in interest rates. |
The Partnership hedges portions of its forecasted expenditures denominated in foreign currencies with foreign currency forward contracts. These foreign currency forward contracts are generally designated, for accounting purposes, as cash flow hedges of forecasted foreign currency expenditures. Where such instruments are designated and qualify as cash flow hedges, the effective portion of the changes in their fair value is recorded in accumulated other comprehensive income (loss), until the hedged item is recognized in earnings. At such time, the respective amount in accumulated other comprehensive income (loss) is released to earnings and is recorded within operating expenses, based on the nature of the expense. The ineffective portion of these foreign currency forward contracts has also been reported in operating expenses, based on the nature of the expense. |
During the three and nine months ended September 30, 2009 and 2008, the Partnership recognized the following realized and unrealized gains (losses) relating to foreign currency forward contracts that are designated as cash flow hedges for accounting purposes: |
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
$ | $ | $ | $ | |||||||||||||
Gains (losses) recognized in: | ||||||||||||||||
Vessel operating expenses | (782 | ) | 1,405 | (7,416 | ) | 1,734 | ||||||||||
General and administrative | 397 | 772 | 701 | 632 | ||||||||||||
Foreign currency exchange loss | — | — | — | 8 | ||||||||||||
Accumulated other comprehensive income (loss) | 14,167 | (19,000 | ) | 26,106 | (15,600 | ) | ||||||||||
Losses reclassified from: | ||||||||||||||||
Accumulated other comprehensive income | 1,688 | 2,023 | 9,826 | 1,214 |
As at September 30, 2009, the Partnership’s accumulated other comprehensive income included $0.2 million of unrealized gains on foreign currency forward contracts designated as cash flow hedges. As at September 30, 2009, the Partnership estimated, based on the current foreign exchange rates, that it would reclassify approximately $0.2 million of net gains on foreign currency forward contracts from accumulated other comprehensive gain to earnings during the next 12 months. |
Realized and unrealized gains (losses) of foreign currency forward contracts that are not designated for accounting purposes as cash flow hedges, are recognized in earnings and reported in realized and unrealized gains (losses) on non-designated derivatives in the consolidated statements of income (loss). During the three and nine months ended September 30, 2009, the Partnership recognized net realized and unrealized gains on foreign currency forward contracts of $0.4 million and $0.8 million, respectively. During the three and nine months ended September 30, 2008, the Partnership recognized net realized and unrealized losses on foreign currency forward contracts of ($4.2) million and ($1.9) million, respectively. Realized and unrealized gains (losses) of ($1.2) million and ($0.6) million, respectively, relating to foreign currency forwards contracts for the three and nine months ended September 30, 2008 were reclassified from general and administrative expenses to realized and unrealized gains (losses) on non-designated derivatives for comparative purposes. Realized and unrealized (losses) of ($1.5) million and ($1.2) million, respectively, relating to foreign currency forwards contracts for the three and nine months ended September 30, 2008 were reclassified from vessel operating expenses to realized and unrealized gains (losses) on non-designated derivatives for comparative purposes. |
As at September 30, 2009, the Partnership was committed to the following foreign currency forward contracts: |
Fair Value / Carrying | ||||||||||||||||||||||||||||
Contract Amount | Amount of Liability | Average | ||||||||||||||||||||||||||
in | (thousands of U.S. Dollars) | Forward | Expected Maturity | |||||||||||||||||||||||||
Foreign Currency | Hedge | Non-hedge | Rate(1) | 2009 | 2010 | 2011 | ||||||||||||||||||||||
(thousands) | (in thousands of U.S. Dollars) | |||||||||||||||||||||||||||
Norwegian Kroner | 801,469 | $ | 2,711 | $ | 2,423 | 6.05 | $ | 26,707 | $ | 96,068 | $ | 9,644 | ||||||||||||||||
Australian Dollar | 316 | — | — | 1.13 | 279 | — | — | |||||||||||||||||||||
British Pound | 104 | (31 | ) | — | 0.53 | 97 | 99 | — | ||||||||||||||||||||
Euro | 12,200 | 882 | (20 | ) | 0.72 | 4,737 | 12,254 | — | ||||||||||||||||||||
Singaporean Dollar | 2,200 | — | — | 1.41 | 1,560 | — | — | |||||||||||||||||||||
$ | 3,562 | $ | 2,403 | $ | 33,380 | $ | 108,421 | $ | 9,644 | |||||||||||||||||||
(1) | Average forward rate represents the contracted amount of foreign currency one U.S. Dollar will buy. |
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NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Cont’d)
(all tabular amounts stated in thousands of U.S. dollars, except unit and per unit data)
The Partnership enters into interest rate swaps, which exchange a receipt of floating interest for a payment of fixed interest to reduce the Partnership’s exposure to interest rate variability on its outstanding floating-rate debt. The Partnership has not designated, for accounting purposes, its interest rate swaps as cash flow hedges of its USD LIBOR denominated borrowings. Realized and unrealized gains (losses) relating to the Partnership’s interest rate swaps have been reported in realized and unrealized gains (losses) on non-designated derivatives in the consolidated statements of income. During the three and nine months ended September 30, 2009, the Partnership recognized net realized and unrealized (losses) gains of ($37.7) million and $36.9 million, respectively, relating to its interest rate swaps. During the three and nine months ended September 30, 2008, the Partnership recognized net realized and unrealized losses of ($21.9) million and ($31.1) million, respectively, relating to its interest rate swaps. The realized and unrealized losses of ($17.8) million and ($24.9) million, respectively relating to interest rate swaps for the three and nine months ended September 30, 2008 were reclassified from interest expense to realized and unrealized gain on non-designated derivatives for comparative purposes. |
As at September 30, 2009, the Partnership was committed to the following interest rate swap agreements: |
Fair value / | Fixed | |||||||||||||||||||
Interest | Carrying | Weighted-Average | Interest | |||||||||||||||||
Rate | Principal | Amount of | Remaining Term | Rate | ||||||||||||||||
Index | Amount | Liability(3) | (Years) | (%)(1) | ||||||||||||||||
$ | $ | |||||||||||||||||||
U.S. Dollar-denominated interest rate swaps | LIBOR | 735,000 | 53,641 | 6.2 | 4.8 | |||||||||||||||
U.S. Dollar-denominated interest rate swaps(2) | LIBOR | 722,536 | 53,271 | 7.3 | 3.7 | |||||||||||||||
1,457,536 | 106,912 | |||||||||||||||||||
(1) | Excludes the margin the Partnership pays on its variable-rate debt, which as at September 30, 2009 ranged from 0.45% and 3.25%. | |
(2) | Principal amount reduces quarterly or semi-annually. | |
(3) | The fair value of the Partnership’s interest rate swap agreements includes $10.7 million of accrued interest which is recorded in accrued liabilities on the balance sheet. |
The Partnership is potentially exposed to credit loss in the event of non-performance by the counterparties to the foreign currency forward contracts and the interest rate swap agreements. In order to minimize counterparty risk, the Partnership only enters into derivative transactions with counterparties that are rated A- or better by Standard & Poor’s or A3 or better by Moody’s at the time of the transactions. In addition, to the extent possible and practical, interest rate swaps are entered into with different counterparties to reduce concentration risk. |
12. | Income Tax (Expense) Recovery |
The components of the provision for income tax (expense) recovery are as follows: |
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
$ | $ | $ | $ | |||||||||||||
Current | (4,079 | ) | — | (4,201 | ) | — | ||||||||||
Deferred | (16,155 | ) | 34,129 | (22,727 | ) | 34,821 | ||||||||||
Income tax (expense) recovery | (20,234 | ) | 34,129 | (26,928 | ) | 34,821 | ||||||||||
13. | Commitments and Contingencies |
The Partnership may, from time to time, be involved in legal proceedings and claims that arise in the ordinary course of business. The Partnership believes that any adverse outcome, individually or in the aggregate, of any existing claims would not have a material affect on its financial position, results of operations or cash flows, when taking into account its insurance coverage and indemnifications from charterers or Teekay Corporation. |
14. | Partners’ Equity and Net Income Per Unit |
At September 30, 2009, of the Partnership’s total limited partner units outstanding, 60.74% were held by the public and the remaining units were held by a subsidiary of Teekay Corporation. |
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NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Cont’d)
(all tabular amounts stated in thousands of U.S. dollars, except unit and per unit data)
Limited Partners’ Rights | ||
Significant rights of the limited partners include the following: |
• | Right to receive distribution of available cash within approximately 45 days after the end of each quarter. |
• | No limited partner shall have any management power over the Partnership’s business and affairs; the general partner shall conduct, direct and manage our activities. |
• | The General Partner may be removed if such removal is approved by unitholders holding at least 66 2/3% of the outstanding units voting as a single class, including units held by the General Partner and its affiliates. |
Subordinated Units | ||
All of the Partnership’s subordinated units are held by a subsidiary of Teekay Corporation. Under the partnership agreement, during the subordination period applicable to the Partnership’s subordinated units, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.35 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. Distribution arrearages do not accrue on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units. |
The subordination period will extend until the first day of any quarter beginning after December 31, 2009. Thereafter the subordination period will terminate automatically and the subordinated units will convert into common units on a one-for-one basis if certain tests are met. |
For the purposes of the net income per unit calculation as defined below, during the quarters ended September 30, 2009 and September 30, 2008, the cash distribution exceeded the minimum quarterly distribution of $0.35 per unit and, consequently, the assumed distribution of net income did not result in an unequal distribution of net income between the subordinated unit holders and common unit holders for the purposes of the net income per unit calculation as defined below. |
Incentive Distribution Rights | ||
The General Partner is entitled to incentive distributions if the amount the Partnership distributes to unitholders with respect to any quarter exceeds specified target levels shown below: |
Quarterly Distribution Target Amount (per unit) | Unitholders | General Partner | ||||||
Minimum quarterly distribution of $0.35 | 98 | % | 2 | % | ||||
Up to $0.4025 | 98 | % | 2 | % | ||||
Above $0.4025 up to $0.4375 | 85 | % | 15 | % | ||||
Above $0.4375 up to $0.525 | 75 | % | 25 | % | ||||
Above $0.525 | 50 | % | 50 | % |
During the quarters ended September 30, 2009 and 2008, the cash distribution exceeded $0.4025 per unit and, consequently, the assumed distribution of net income resulted in the use of the increasing percentages to calculate the General Partner’s interest in net income for the purposes of the net income per unit calculation. |
In the event of a liquidation, all property and cash in excess of that required to discharge all liabilities will be distributed to the unitholders and the General Partner in proportion to their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of the Partnership’s assets in liquidation in accordance with the partnership agreement. | ||
Net Income (Loss) Per Unit |
Net income (loss) per unit is determined by dividing net income (loss), after deducting the amount of net income (loss) attributable to the Dropdown Predecessor, the non-controlling interest and the General Partner’s interest, by the weighted-average number of units outstanding during the applicable period. |
The General Partner’s, common unit holders’ and subordinated unitholders’ interests in net income (loss) are calculated as if all net income (loss) was distributed according to the terms of the Partnership’s partnership agreement, regardless of whether those earnings would or could be distributed. The partnership agreement does not provide for the distribution of net income (loss); rather, it provides for the distribution of available cash, which is a contractually defined term that generally means all cash on hand at the end of each quarter less the amount of cash reserves established by the Partnership’s board of directors to provide for the proper conduct of the Partnerships’ business including reserves for maintenance and replacement capital expenditure and anticipated credit needs. Unlike available cash, net income (loss) is affected by non-cash items such as depreciation and amortization, unrealized gains and losses on derivative instruments and foreign currency translation gains (losses). |
The General Partner’s interest in net income (loss) is calculated as if all net income (loss) for the period was distributed according to the terms of the partnership agreement, regardless of whether those earnings would or could be distributed. |
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NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Cont’d)
(all tabular amounts stated in thousands of U.S. dollars, except unit and per unit data)
The calculations of the basic and diluted earnings per unit are presented below. |
Three Months ended | Nine Months ended | |||||||||||||||
September | September | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
$ | $ | $ | $ | |||||||||||||
Net (loss) income | (31,488 | ) | 41,956 | 81,237 | 73,815 | |||||||||||
Net (loss) income attributable to non-controlling interest | (12,560 | ) | 19,048 | 32,831 | 41,810 | |||||||||||
Net (loss) income attributable to Dropdown Predecessor | (5,551 | ) | 2,283 | 11,378 | 237 | |||||||||||
Net (loss) income attributable to the Partnership | (13,377 | ) | 20,625 | 37,028 | 31,768 | |||||||||||
Net (loss) income attributable to: | ||||||||||||||||
Common unit holders | (9,313 | ) | 13,467 | 24,863 | 19,717 | |||||||||||
Subordinated unit holders | (4,143 | ) | 6,468 | 10,523 | 11,138 | |||||||||||
General partner interest | 79 | 690 | 1,642 | 913 | ||||||||||||
Weighted average units outstanding (basic and diluted) | ||||||||||||||||
Common unit holders | 25,056,250 | 20,359,783 | 21,985,714 | 13,794,526 | ||||||||||||
Subordinated unit holders | 9,800,000 | 9,800,000 | 9,800,000 | 9,800,000 | ||||||||||||
Net income per unit (basic and diluted) | ||||||||||||||||
Common unit holders | (0.37 | ) | 0.66 | 1.13 | 1.43 | |||||||||||
Subordinated unit holders | (0.42 | ) | 0.66 | 1.07 | 1.14 |
Pursuant to the partnership agreement, allocations to partners are made on a quarterly basis. |
15. | Supplemental Cash Flow Information |
The Partnership’s consolidated statements of cash flows for the nine months ended September 30, 2009 and 2008 reflects the Dropdown Predecessor as if the Partnership had acquired the Dropdown Predecessor when each respective vessel began operations under the ownership of Teekay Corporation. If Teekay Corporation financed the construction or purchase of the vessel prior to the Dropdown Predecessor being included in the results of the Partnership, the expenditures for the vessel by Teekay Corporation have been treated as a non-cash transaction in the Partnership’s consolidated statement of cash flows. The non-cash investing activities related to the Dropdown Predecessor were $89.4 million for expenditures for vessels and equipment in the nine months ended September 30, 2008. For non-cash changes related to thePetrojarl Varg Dropdown Predecessor, see Note 10p. |
16. | Subsequent Events |
In November 2009, the Partnership entered into a $260 million revolving credit facility secured by its FPSO, thePetrojarl Varg,and bearing interest based on LIBOR plus a margin of 3.25%. The revolving credit facility reduces over time, on a quarterly basis, and matures in 2013. A portion of this facility was used to repay the $160 million tranche of the $220 million vendor financing obtained from Teekay Corporation at the time of the acquisition of thePetrojarl Varg. |
17. | Recent Accounting Pronouncements |
In June 2009, FASB issued Statement of Financial Accounting Standards (orSFAS) No. 167,Amendments to FASB Interpretation No. 46(R). SFAS No. 167 eliminates FASB Interpretation 46(R)’s exceptions to consolidating qualifying special-purpose entities, contains new criteria for determining the primary beneficiary, and increases the frequency of required reassessments to determine whether a company is the primary beneficiary of a variable interest entity. SFAS No. 167 also contains a new requirement that any term, transaction, or arrangement that does not have a substantive effect on an entity’s status as a variable interest entity, a company’s power over a variable interest entity, or a company’s obligation to absorb losses or its right to receive benefits of an entity must be disregarded in applying FASB Interpretation 46(R)’s provisions. The elimination of the qualifying special-purpose entity concept and its consolidation exceptions means more entities will be subject to consolidation assessments and reassessments. SFAS No. 167 is effective for fiscal years beginning after November 15, 2009, and for interim periods within that first period, with earlier adoption prohibited. The Partnership is currently assessing the potential impacts, if any, on its consolidated financial statements. SFAS No. 167 will remain authoritative until such time that it is integrated into the Codification. |
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NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Cont’d)
(all tabular amounts stated in thousands of U.S. dollars, except unit and per unit data)
In August 2009, the FASB issued an amendment to FASB ASC 820Fair Value Measurements and Disclosuresthat clarifies the fair value measurement requirements for liabilities that lack a quoted price in an active market and provides clarifying guidance regarding the consideration of restrictions when estimating the fair value of a liability. This amendment will be effective for the Partnership on October 1, 2009. The Partnership is currently assessing the potential impacts, if any, on its consolidated financial statements. |
In September 2009, the FASB issued an amendment to FASB ASC 605Revenue Recognitionthat provides for a new methodology for establishing the fair value for a deliverable in a multiple-element arrangement. When vendor specific objective or third-party evidence for deliverables in a multiple-element arrangement cannot be determined, the Partnership will be required to develop a best estimate of the selling price of separate deliverables and to allocate the arrangement consideration using the relative selling price method. This amendment will be effective for the Partnership on January 1, 2010. The Partnership is currently assessing the potential impacts, if any, on its consolidated financial statements. |
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SEPTEMBER 30, 2009
ITEM 2 | — | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
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• | Our financial results reflect the results of the interests in vessels acquired from Teekay Corporation for all periods the vessels were under common control.In September 2009, we acquired thePetrojarl VargFPSO unit, together with its four-year fixed-rate contract. In June 2008, we acquired from Teekay Corporation its interests in two 2008-built Aframax tankers, theSPT Explorerand theSPT Navigator.This acquisition included the assumption of debt and Teekay Corporation’s rights and obligations under the 10-year, fixed-rate bareboat charters (with options exercisable by the charterer to extend up to an additional five years). These transactions were deemed to be business acquisitions between entities under common control. Accordingly, we have accounted for these transactions in a manner similar to the pooling of interest method. Under this method of accounting, our financial statements prior to the date the interests in these vessels were actually acquired by us are retroactively adjusted to include the results of the acquired vessels. The periods retroactively adjusted include all periods that we and the acquired vessel were both under common control of Teekay Corporation and had begun operations. As a result, our statements of income for the three and nine months ended September 30, 2009 and 2008 reflect the vessels, referred to herein as theDropdown Predecessor, as if we had acquired them when the vessels began operations under the ownership of Teekay Corporation. These vessels began operations on January 7, 2008 (SPT Explorer)and March 28, 2008 (SPT Navigator). Teekay Corporation acquired a 65% interest in thePetrojarl Vargon October 1, 2006, and acquired the remaining 35% interest on June 30, 2008. |
• | The size of our fleet continues to change.Our results of operations reflect changes in the size and composition of our fleet due to certain vessel deliveries and vessel dispositions. Please read “— Results of Operations” below for further details about vessel dispositions and deliveries. Due to the nature of our business, we expect our fleet to continue to fluctuate in size and composition. |
• | Our vessel operating costs are facing industry-wide cost pressures.The oil shipping industry is experiencing a global manpower shortage due to growth in the world fleet. This shortage resulted in significant crew wage increases during 2007, 2008, and to a lesser degree in 2009. We expect the trend of significant crew compensation increases to abate in the short term, however this could change if market conditions adjust. In addition, factors such as pressure on raw material prices and changes in regulatory requirements can also increase operating expenditures. We have taken various measures throughout 2009 in an effort to reduce costs, improve operational efficiencies, and mitigate the impact of inflation and price increases — this focus and associated actions will continue into 2010. |
• | Our financial results of operations are affected by fluctuations in currency exchange rates. Under GAAP, all foreign currency-denominated monetary assets and liabilities, such as cash and cash equivalents, accounts receivable, accounts payable, advances from affiliates and deferred income taxes are revalued and reported based on the prevailing exchange rate at the end of the period. OPCO has entered into services agreements with subsidiaries of Teekay Corporation whereby the subsidiaries operate and crew the vessels. Beginning in 2009, payments under the service agreements have been adjusted to reflect any change in Teekay Corporation’s cost of providing services based on fluctuations in the value of the Norwegian Kroner relative to the U.S. Dollar, which may result in increased payments under the services agreements if the strength of the U.S. Dollar declines relative to the Norwegian Kroner. |
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• | Our net income is affected by fluctuations in the fair value of our derivatives. Our interest rate swaps and some of our foreign currency forward contracts are not designated as hedges for accounting purposes. Although we believe these derivative instruments are economic hedges, the changes in their fair value are included in our statements of income (loss) as unrealized gains or losses on non-designated derivatives. The changes in fair value do not affect our cash flows, liquidity or cash distributions to partners. |
• | Our operations are seasonal and our financial results vary as a consequence of drydockings.Historically, the utilization of shuttle tankers in the North Sea is higher in the winter months, as favorable weather conditions in the warmer months provide opportunities for repairs and maintenance to our vessels and to the offshore oil platforms. Downtime for repairs and maintenance generally reduces oil production and, thus, transportation requirements. During 2009, eleven of our vessels completed their scheduled drydockings. Five of the vessels completed their drydocking in the third quarter of 2009. Two additional vessels completed their drydockings during the fourth quarter of 2009. From time to time, unscheduled drydockings may cause fluctuations in our financial results. |
(in thousands of U.S. dollars, except | Three Months Ended September 30, | |||||||||||
calendar-ship-days and percentages) | 2009 | 2008 | % Change | |||||||||
Voyage revenues | 132,794 | 168,390 | (21.1 | ) | ||||||||
Voyage expenses | 22,481 | 47,338 | (52.5 | ) | ||||||||
Net voyage revenues | 110,313 | 121,052 | (8.9 | ) | ||||||||
Vessel operating expenses | 31,751 | 32,469 | (2.2 | ) | ||||||||
Time-charter hire expense | 27,772 | 31,474 | (11.8 | ) | ||||||||
Depreciation and amortization | 23,670 | 22,880 | 3.5 | |||||||||
General and administrative(1) | 11,173 | 9,617 | 16.2 | |||||||||
Restructuring costs | 371 | — | 100.0 | |||||||||
Income from vessel operations | 15,576 | 24,612 | (36.7 | ) | ||||||||
Calendar-Ship-Days | ||||||||||||
Owned Vessels | 2,484 | 2,484 | — | |||||||||
Chartered-in Vessels | 763 | 846 | (9.8 | ) | ||||||||
Total | 3,247 | 3,330 | (2.5 | ) | ||||||||
(in thousands of U.S. dollars, except | Nine Months Ended September 30, | |||||||||||
calendar-ship-days and percentages) | 2009 | 2008 | % Change | |||||||||
Voyage revenues | 396,721 | 488,715 | (18.8 | ) | ||||||||
Voyage expenses | 56,651 | 131,533 | (56.9 | ) | ||||||||
Net voyage revenues | 340,070 | 357,182 | (4.8 | ) | ||||||||
Vessel operating expenses | 106,010 | 94,365 | 12.3 | |||||||||
Time-charter hire expense | 89,061 | 97,382 | (8.5 | ) | ||||||||
Depreciation and amortization | 70,010 | 68,599 | 2.1 | |||||||||
General and administrative(1) | 32,269 | 35,106 | (8.1 | ) | ||||||||
Restructuring costs | 4,053 | — | 100.0 | |||||||||
Income from vessel operations | 38,667 | 61,730 | (37.4 | ) | ||||||||
Calendar-Ship-Days | ||||||||||||
Owned Vessels | 7,371 | 7,314 | 0.8 | |||||||||
Chartered-in Vessels | 2,497 | 2,696 | (7.4 | ) | ||||||||
Total | 9,868 | 10,010 | (1.4 | ) | ||||||||
(1) | Includes direct general and administrative expenses and indirect general and administrative expenses (allocated to the shuttle tanker segment based on estimated use of corporate resources). |
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• | decreases of $14.3 million and $40.7 million, respectively, for the three and nine months ended September 30, 2009, due to fewer revenue days from shuttle tankers servicing contracts of affreightment and from trading in the conventional spot market, as well as lower spot rates achieved in the conventional spot market, compared to the same periods last year; and |
• | a decrease of $1.8 million for both the three and nine months ended September 30, 2009, due to a decrease in the recovery of certain Norwegian environmental taxes from our customers in the Heidrun oil field during the three months ended September 30, 2009 as compared to the same period last year; |
partially offset by |
• | increases of $3.4 million and $7.8 million, respectively, for the three and nine months ended September 30, 2009, due to rate increases on certain contracts of affreightment; |
• | increases of $1.4 million and $6.7 million, respectively, for the three and nine months ended September 30, 2009, due to a decrease in the number of offhire days resulting from scheduled drydockings and unexpected repairs compared to the same periods last year; |
• | an increase of $6.3 million for the nine months ended September 30, 2009, due to a new time-charter agreement which began in December 2008; and |
• | increases of $0.5 million and $2.8 million for the three and nine months ended September 30, 2009, respectively, due to a decline in bunker prices during the nine months ended September 30, 2009 compared to the same periods last year. |
• | a decrease of $1.7 million for the three months ended September 30, 2009, relating to repairs and maintenance performed for certain vessels compared to the same period last year; and |
• | a decrease of $1.1 million for the three months ended September 30, 2009, due to a decrease in service costs; |
partially offset by |
• | a net increase of $2.1 million for the three months ended September 30, 2009, from realized and unrealized losses on our designated foreign currency forward contracts. |
• | a net increase of $8.6 million for the nine months ended September 30, 2009, from realized and unrealized losses on our designated foreign currency forward contracts; |
• | an increase $3.4 million for the nine months ended September 30, 2009, due to the 2008 Shuttle Tanker Acquisition and an additional bareboat chartered-in vessel beginning in December 2008; and |
• | an increase of $2.9 million the nine months ended September 30, 2009, due to an increase in service costs from the rising cost of commodities as well as the scope of service activities performed; |
partially offset by |
• | a decrease of $4.1 million for the nine months ended September 30, 2009, relating to repairs and maintenance performed for certain vessels, compared to the same period last year. |
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(in thousands of U.S. dollars, except | Three Months Ended September 30, | |||||||||||
calendar-ship-days and percentages) | 2009 | 2008 | % Change | |||||||||
Voyage revenues | 31,409 | 40,652 | (22.7 | ) | ||||||||
Voyage expenses | 6,610 | 14,713 | (55.1 | ) | ||||||||
Net voyage revenues | 24,799 | 25,939 | (4.4 | ) | ||||||||
Vessel operating expenses | 6,210 | 6,433 | (3.5 | ) | ||||||||
Depreciation and amortization | 6,208 | 5,636 | 10.1 | |||||||||
General and administrative(1) | 1,124 | 2,458 | (54.3 | ) | ||||||||
Income from vessel operations | 11,257 | 11,412 | (1.4 | ) | ||||||||
Calendar-Ship-Days | ||||||||||||
Owned Vessels | 1,012 | 1,012 | — | |||||||||
(in thousands of U.S. dollars, except | Nine Months Ended September 30, | |||||||||||
calendar-ship-days and percentages) | 2009 | 2008 | % Change | |||||||||
Voyage revenues | 92,738 | 114,248 | (18.8 | ) | ||||||||
Voyage expenses | 19,034 | 40,976 | (53.5 | ) | ||||||||
Net voyage revenues | 73,704 | 73,272 | 0.6 | |||||||||
Vessel operating expenses | 17,542 | 18,544 | (5.4 | ) | ||||||||
Depreciation and amortization | 18,166 | 16,612 | 9.4 | |||||||||
General and administrative(1) | 3,841 | 6,531 | (41.2 | ) | ||||||||
Income from vessel operations | 34,155 | 31,585 | 8.1 | |||||||||
Calendar-Ship-Days | ||||||||||||
Owned Vessels | 3,003 | 2,919 | 2.9 | |||||||||
(1) | Includes direct general and administrative expenses and indirect general and administrative expenses (allocated to the conventional tanker segment based on estimated use of corporate resources). |
• | a decrease of $2.7 million in net bunker revenues due to a general decrease in bunker index prices during the three months ended September 30, 2009 compared to the same period last year; |
partially offset by |
• | an increase of $0.6 million due to fewer scheduled drydockings compared to the same period last year; and |
• | an increase of $0.7 million due to an increase in the daily hire rates for all nine time-charter contracts with Teekay Corporation compared to the same period last year. |
• | an increase of $2.1 million due to an increase in the daily hire rates for all nine time-charter contracts with Teekay Corporation compared to the same period last year; |
• | an increase of $1.4 million due to the 2008 Conventional Tanker Acquisitions; and |
• | an increase of $1.2 million due to fewer scheduled drydockings compared to the same period last year; |
partially offset by |
• | a decrease of $3.8 million in net bunker revenues due to a general decrease in bunker index prices during the nine months ended September 30, 2009 compared to the same period last year. |
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• | a decrease of $0.1 million and $0.6 million, respectively, for the three and nine months ended September 30, 2009, due to an decrease in the consumption and use of consumables, lube oil, and freight; and |
• | a decrease of $0.3 million in crew and manning costs for the nine months ended September 30, 2009; and |
• | a decrease of $0.1 million in insurance costs for the three months ended September 30, 2009. |
• | an increase of $0.5 million and $1.0 million, respectively, for the three and nine months ending September 30, 2009, resulting from an increase in the amortization of drydocking costs; and |
• | an increase of $0.4 million for the nine months ending September 30, 2009 resulting from the 2008 Conventional Tanker Acquisitions. |
(in thousands of U.S. dollars, except | Three Months Ended September 30, | |||||||||||
calendar-ship-days and percentages) | 2009 | 2008 | % Change | |||||||||
Voyage revenues | 14,781 | 17,905 | (17.4 | ) | ||||||||
Voyage expenses | 272 | 497 | (45.3 | ) | ||||||||
Net voyage revenues | 14,509 | 17,408 | (16.7 | ) | ||||||||
Vessel operating expenses | 6,876 | 7,045 | (2.4 | ) | ||||||||
Depreciation and amortization | 5,470 | 5,526 | (1.0 | ) | ||||||||
General and administrative(1) | 892 | 804 | 10.9 | |||||||||
Income from vessel operations | 1,271 | 4,033 | (68.5 | ) | ||||||||
Calendar-Ship-Days | ||||||||||||
Owned Vessels | 460 | 460 | — | |||||||||
(in thousands of U.S. dollars, except | Nine Months Ended September 30, | |||||||||||
calendar-ship-days and percentages) | 2009 | 2008 | % Change | |||||||||
Voyage revenues | 45,970 | 53,400 | (13.9 | ) | ||||||||
Voyage expenses | 720 | 1,227 | (41.3 | ) | ||||||||
Net voyage revenues | 45,250 | 52,173 | (13.3 | ) | ||||||||
Vessel operating expenses | 18,955 | 20,737 | (8.6 | ) | ||||||||
Depreciation and amortization | 16,291 | 18,190 | (10.4 | ) | ||||||||
General and administrative(1) | 2,352 | 2,846 | (17.4 | ) | ||||||||
Income from vessel operations | 7,652 | 10,400 | (26.4 | ) | ||||||||
Calendar-Ship-Days | ||||||||||||
Owned Vessels | 1,365 | 1,370 | (0.4 | ) | ||||||||
(1) | Includes direct general and administrative expenses and indirect general and administrative expenses (allocated to the FSO segment based on estimated use of corporate resources). |
• | a decrease of $3.1 million for the three and nine months ended September 30, 2009, compared to the same periods last year, due to the scheduled drydocking of one vessel during the three months ended September 30, 2009; and | ||
• | a decrease of $4.4 million for the nine months ended September 30, 2009, due to the strengthening of the U.S. Dollar against the Norwegian Kroner and Australian Dollar compared to the same period last year. |
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(in thousands of U.S. dollars, except | Three Months Ended September 30, | |||||||||||
calendar-ship-days and percentages) | 2009 | 2008 | % Change | |||||||||
Voyage revenues | 25,525 | 25,285 | 0.9 | |||||||||
Vessel operating expenses | 10,020 | 11,411 | (12.2 | ) | ||||||||
Depreciation and amortization | 5,633 | 5,633 | — | |||||||||
General and administrative(1) | 631 | 1,658 | (61.9 | ) | ||||||||
Income from vessel operations | 9,241 | 6,583 | 40.4 | |||||||||
Calendar-Ship-Days | ||||||||||||
Owned Vessel | 92 | 92 | — | |||||||||
(in thousands of U.S. dollars, except | Nine Months Ended September 30, | |||||||||||
calendar-ship-days and percentages) | 2009 | 2008 | % Change | |||||||||
Voyage revenues | 73,031 | 72,053 | 1.4 | |||||||||
Vessel operating expenses | 29,112 | 32,352 | (10.0 | ) | ||||||||
Depreciation and amortization | 16,899 | 14,463 | 16.8 | |||||||||
General and administrative(1) | 3,678 | 5,157 | (28.7 | ) | ||||||||
Income from vessel operations | 23,342 | 20,081 | 16.2 | |||||||||
Calendar-Ship-Days | ||||||||||||
Owned Vessels | 273 | 274 | (0.4 | ) | ||||||||
(1) | Includes direct general and administrative expenses and indirect general and administrative expenses (allocated to the FPSO segment based on estimated use of corporate resources). |
• | increases of $1.5 million and $3.0 million, respectively, for the three and nine months ended September 30, 2009, as thePetrojarl Vargcommenced a new four-year fixed-rate contract extension with Talisman Energy beginning in the third quarter of 2009; |
partially offset by |
• | decreases of $1.3 million and $2.0 million, respectively, for the three and nine months ended September 30, 2009, as a result of decreases in miscellaneous service revenues as compared to the same periods last year. |
• | a decrease of $1.4 million and $6.6 million, respectively, for the three and nine months ended September 30, 2009 due to the strengthening of the U.S. Dollar against the Norwegian Kroner compared to the same periods last year; and | ||
• | a decrease of $1.7 million for the nine months ended September 30, 2009, due to a decrease in service costs; |
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partially offset by |
• | an increase of $5.0 million for the nine months ended September 30, 2009, resulting from an increase in salaries for crew and officers, primarily due to general wage escalations. |
• | decreases of $7.7 million and $20.2 million, respectively, due to a decline in interest rates during the three and nine months ended September 30, 2009, compared to the same periods last year; |
• | decreases of $0.7 million and $6.2 million, respectively, for the three and nine months ended September 30, 2009, related to scheduled repayments and prepayments of debt during 2008 and 2009; and |
• | decreases of $1.7 million and $4.9 million, respectively, for the three and nine months ended September 30, 2009, from the financing of thePetrojarl Varg(including the Dropdown Predecessor) mainly due to a decrease in interest rates. |
Three Months Ended, September 30 | Nine Months Ended, September 30 | |||||||||||||||
(in thousands of U.S. Dollars) | 2009 | 2008 | 2009 | 2008 | ||||||||||||
Realized (losses) gains | ||||||||||||||||
Interest rate swaps | (12,743 | ) | (8,048 | ) | (34,621 | ) | (13,752 | ) | ||||||||
Foreign currency forward contracts | (93 | ) | 730 | (4,071 | ) | 2,415 | ||||||||||
(12,836 | ) | (7,318 | ) | (38,692 | ) | (11,337 | ) | |||||||||
Unrealized (losses) gains | ||||||||||||||||
Interest rate swaps | (24,942 | ) | (13,830 | ) | 71,538 | (17,326 | ) | |||||||||
Foreign currency forward contracts | 476 | (4,972 | ) | 4,870 | (4,356 | ) | ||||||||||
(24,466 | ) | (18,802 | ) | 76,408 | (21,682 | ) | ||||||||||
Total realized and unrealized (losses) gains on non-designated derivative instruments | (37,302 | ) | (26,120 | ) | 37,716 | (33,019 | ) | |||||||||
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Nine Months Ended September 30, | ||||||||
(in thousands of U.S. dollars) | 2009 | 2008 | ||||||
Net cash flow from operating activities | 140,606 | 181,148 | ||||||
Net cash flow from financing activities | (134,495 | ) | 132,551 | |||||
Net cash flow from investing activities | 5,287 | (282,500 | ) |
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• | incurring or guaranteeing indebtedness (applicable to our term loans and two of our revolving credit facilities); |
• | changing ownership or structure, including by mergers, consolidations, liquidations and dissolutions; |
• | making dividends or distributions when in default of the relevant loans; |
• | making capital expenditures in excess of specified levels; |
• | making certain negative pledges or granting certain liens; |
• | selling, transferring, assigning or conveying assets; or |
• | entering into a new line of business. |
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Balance | 2010 | 2012 | ||||||||||||||||||
of | and | and | Beyond | |||||||||||||||||
Total | 2009 | 2011 | 2013 | 2013 | ||||||||||||||||
(in millions of U.S. dollars) | ||||||||||||||||||||
Long-term debt(1) | 1,771.4 | 10.8 | 477.0 | 329.7 | 953.9 | |||||||||||||||
Chartered-in vessels (operating leases) | 326.0 | 28.3 | 165.0 | 103.6 | 29.1 | |||||||||||||||
Total contractual obligations | 2,097.4 | 39.1 | 642.0 | 433.3 | 983.0 | |||||||||||||||
(1) | Excludes expected interest payments of $8.7 million (remainder of 2009), $56.7 million (2010 and 2011), $43.8 million (2012 and 2013) and $16.4 million (beyond 2013). Expected interest payments are based on LIBOR, plus margins which ranged between 0.45% and 3.25% as at September 30, 2009. |
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• | our future growth prospects; |
• | increases to liquidity or cash flows from thePetrojarl VargFPSO acquisition and refinancing; |
• | results of operations and revenues and expenses; |
• | offshore and tanker market fundamentals, including the balance of supply and demand in the offshore and tanker market; |
• | oil fields adjacent to thePetrojarl Varg FPSO becoming operational and our ability to service these fields; |
• | future capital expenditures and availability of capital resources to fund capital expenditures; |
• | offers of shuttle tankers, FSOs and FPSOs and related contracts from Teekay Corporation; |
• | obtaining offshore projects that we or Teekay Corporation bid on or may be awarded; |
• | delivery dates of and financing for newbuildings or existing vessels; |
• | vessel operating and crewing costs for vessels; |
• | entrance into joint ventures and partnerships with companies; |
• | the commencement of service of newbuildings or existing vessels; |
• | the duration of drydockings; |
• | potential newbuilding order cancellations; |
• | the future valuation of goodwill; |
• | our liquidity needs; |
• | our compliance with covenants under our credit facilities; |
• | our hedging activities relating to foreign exchange, interest rate and spot market risks; |
• | the ability of the counterparties for our derivative contracts to fulfill their contractual obligations; |
• | our exposure to foreign currency fluctuations, particularly in Norwegian Kroner; and |
• | the outcome of claims and legal action arising from the collision involving theNavion Hispania. |
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SEPTEMBER 30, 2009
PART I — FINANCIAL INFORMATION
ITEM 3 | — | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Balance | ||||||||||||||||||||||||||||||||||||
of | Fair Value | |||||||||||||||||||||||||||||||||||
2009 | 2010 | 2011 | 2012 | 2013 | Thereafter | Total | Liability | Rate(1) | ||||||||||||||||||||||||||||
(in millions of U.S. dollars, except percentages) | ||||||||||||||||||||||||||||||||||||
Long-Term Debt: | ||||||||||||||||||||||||||||||||||||
Variable Rate(2) | 10.8 | 293.2 | 183.8 | 160.7 | 169.0 | 893.9 | 1,711.4 | (1,580.3 | ) | 1.7 | % | |||||||||||||||||||||||||
Fixed Rate | — | — | — | — | — | 60.0 | 60.0 | (60.0 | ) | 10.0 | % | |||||||||||||||||||||||||
Interest Rate Swaps: | ||||||||||||||||||||||||||||||||||||
Contract Amount(3) | 342.8 | 68.1 | 108.7 | 214.2 | 19.9 | 703.8 | 1,457.5 | (106.9 | ) | 4.3 | % | |||||||||||||||||||||||||
Average Fixed Pay Rate(2) | 4.9 | % | 3.0 | % | 2.7 | % | 2.5 | % | 4.9 | % | 4.8 | % | 4.3 | % |
(1) | Rate refers to the weighted-average effective interest rate for our debt, including the margin paid on our floating-rate debt and the average fixed pay rate for interest rate swaps. The average fixed pay rate for interest rate swaps excludes the margin paid on the floating-rate debt, which as of September 30, 2009 ranged from 0.45% to 3.25%. | |
(2) | Interest payments on floating-rate debt and interest rate swaps are based on LIBOR. | |
(3) | The average variable receive rate for interest rate swaps is set quarterly at the 3-month LIBOR or semi-annually at the 6-month LIBOR. |
Contract Amount in | Average | Expected Maturity | ||||||||||||||||||
Foreign Currency | Forward Rate(1) | 2009 | 2010 | 2011 | ||||||||||||||||
(thousands) | (in thousands of U.S. Dollars) | |||||||||||||||||||
Norwegian Kroner | 801,469 | 6.05 | $ | 26,707 | $ | 96,068 | $ | 9,644 | ||||||||||||
Australian Dollar | 316 | 1.13 | 279 | — | — | |||||||||||||||
British Pound | 104 | 0.53 | 97 | 99 | — | |||||||||||||||
Euro | 12,200 | 0.72 | 4,737 | 12,254 | — | |||||||||||||||
Singaporean Dollar | 2,200 | 1.41 | 1,560 | — | — | |||||||||||||||
$ | 33,380 | $ | 108,421 | $ | 9,644 | |||||||||||||||
(1) | Average forward rate represents the contracted amount of foreign currency one U.S. Dollar will buy. |
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SEPTEMBER 30, 2009
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SEPTEMBER 30, 2009
On November 13, 2006, a Teekay Offshore Operating L.P. (orOPCO) shuttle tanker, theNavion Hispania, collided with theNjord Bravo, a floating storage and offtake unit, while preparing to load an oil cargo from theNjord Bravo. TheNjord Bravoservices the Njord field, which is operated by StatoilHydro Petroleum AS (orStatoilHydro) and is located off the Norwegian coast. At the time of the incident, StatoilHydro was chartering theNavion Hispaniafrom OPCO. TheNavion Hispaniaand theNjord Bravoboth incurred damages as a result of the collision. |
In November 2007, Navion Offshore Loading AS, a subsidiary of OPCO, and two subsidiaries of Teekay Corporation were named as co-defendants in a legal action filed by Norwegian Hull Club (the hull and machinery insurers of theNjord Bravo) and various licensees in the Njord field. The initial claim sought damages for vessel repairs, expenses for a replacement vessel and other amounts related to production stoppage on the field, totalling NOK 256,000,000 (approximately USD$43 million). The Stavanger Conciliation Council referred the matter to the Stavanger District Court. In November 2009, a revised claim was received in the amount of NOK 213,000,000 (approximately USD $36 million). |
The Partnership believes the likelihood of any losses relating to the claim is remote. OPCO believes that the charter contract relating to theNavion Hispaniarequires that StatoilHydro be responsible and indemnify OPCO for all losses relating to the damage to theNjord Bravo. OPCO and Teekay Corporation also maintain P&I insurance for damages to theNavion Hispaniaand insurance for collision-related costs and claims. The Partnership believes that these insurance policies will cover the costs related to this incident, including any costs not indemnified by StatoilHydro, subject to standard deductibles. In addition, Teekay Corporation has agreed to indemnify the Partnership, OPCO and OPCO’s subsidiaries for any losses they may incur in connection with this incident. |
Tax Risks |
In addition to the other information set forth in this Report on Form 6-K, including the information stated below, you should carefully consider the risk factors discussed in Part I, “Item 3. Key Information — Risk Factors” in our Annual Report on Form 20-F for the year ended December 31, 2008, which could materially affect our business, financial condition or results of operations. |
U.S. tax authorities could treat us as a “passive foreign investment company,” which could have adverse U.S. federal income tax consequences to U.S. holders. |
A foreign entity taxed as a corporation for U.S. federal income tax purposes will be treated as a “passive foreign investment company” (orPFIC) for U.S. federal income tax purposes if at least 75.0% of its gross income for any taxable year consists of certain types of “passive income,” or at least 50.0% of the average value of the entity’s assets produce or are held for the production of those types of “passive income.” For purposes of these tests, “passive income” includes dividends, interest, and gains from the sale or exchange of investment property and rents and royalties, other than rents and royalties that are received from unrelated parties in connection with the active conduct of a trade or business. For purposes of these tests, income derived from the performance of services does not constitute “passive income.” |
There are legal uncertainties involved in determining whether the income derived from our time chartering activities constitutes rental income or income derived from the performance of services, including the decision inTidewater Inc. v. United States, 565 F.2d 299 (5th Cir. April 13, 2009), which held that income derived from certain time chartering activities should be treated as rental income rather than services income for purposes of a foreign sales corporation provision of the U.S. Internal Revenue Code of 1986, as amended (or theCode), and a recent unofficial IRS pronouncement issued to provide guidance to IRS field employees and examiners, which cites theTidewaterdecision favorably in support of the conclusion that income derived by foreign taxpayers from time chartering vessels engaged in the exploration for, or exploitation of, natural resources on the Outer Continental Shelf in the Gulf of Mexico is characterized as leasing or rental income for purposes of the income sourcing provisions of the Code. However, we believe that the nature of our time chartering activities, as well as our time charter contracts, differ in certain material respects from those at issue inTidewater. Consequently, based on our current assets and operations, we intend to take the position that we are not now and have never been a PFIC. No assurance can be given, however, that the IRS will accept our position or that we would not constitute a PFIC for any future taxable year if there were to be changes in our assets, income or operations. |
If the IRS were to determine that we are or have been a PFIC for any taxable year, U.S. holders of our common units will face adverse U.S. federal income tax consequences. Under the PFIC rules, unless those U.S. holders make certain elections available under the Code, such holders would be liable to pay tax at ordinary income tax rates plus interest upon certain distributions and upon any gain from the disposition of our common units, as if such distribution or gain had been recognized ratably over the U.S. holder’s holding period. Please read Part II, Item 5 — “Material U.S. Federal Income Tax Consideration — United States Federal Income Taxation of U.S. Holders — Consequences of Possible PFIC Classification.” |
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We are subject to taxes, which reduces our cash available for distribution to you. |
We or our subsidiaries are subject to tax in certain jurisdictions in which we or our subsidiaries are organized, own assets or have operations, which reduces the amount of our cash available for distribution. In computing our tax obligations in these jurisdictions, we are required to take various tax accounting and reporting positions on matters that are not entirely free from doubt and for which we have not received rulings from the governing authorities. We cannot assure you that upon review of these positions the applicable authorities will agree with our positions. A successful challenge by a tax authority could result in additional tax imposed on us or our subsidiaries, further reducing the cash available for distribution. For example, authorities in Norway recently asserted certain positions that may result in additional tax imposed on our subsidiaries in Norway. We have established reserves in our financial statements that we believe are adequate to cover our liability for any such additional taxes. We cannot assure you that such reserves will be sufficient to cover any additional tax liability that may be imposed on our Norway subsidiaries. |
In addition, changes in our operations or ownership could result in additional tax being imposed on us, OPCO or our or its subsidiaries in jurisdictions in which operations are conducted. For example, Teekay Corporation now holds less than 50.0% of the value of our outstanding units, and therefore we expect that our U.S. source income will be subject to taxation under Section 883 of the Code for taxable years beginning in 2010. Please read Part II, Item 5 — “Taxation of the Partnership — United States Taxation — The Section 883 Exemption.” | ||
Risks Related to the Petrojarl Varg |
The ownership and operation of thePetrojarl Varggenerally results in risks similar to the ownership and operation of our other vessels, as discussed in our Annual Report on Form 20-F for the year ended December 31, 2008. Those risks including the following: |
The redeployment risk of FPSO units is high given their lack of alternative uses and significant modification costs. |
FPSO units are specialized vessels that have very limited alternative uses and high fixed costs. In addition, FPSO units typically require substantial capital investments prior to being redeployed to a new field and production service agreement. If an oil field no longer produces oil or is abandoned or the contract term is not extended, we will no longer generate revenue under the related contract and will need to seek to redeploy affected vessels. If FPSO units are not, as a result of contract termination or otherwise, subject to a long-term profitable contract, we may be required to bid for projects at unattractive rates in order to reduce our losses relating to the vessels. Talisman Energy might not extend thePetrojarl Vargoperations contract beyond 2013, or may terminate the operations contract if the Varg field does not yield sufficient revenues. Oil production of the Varg field has declined in the past and may decline in the future. Any idle time prior to the commencement of a new contract or our inability to redeploy the vessels at acceptable rates may have an adverse effect on our business and operating results. |
Marine transportation is inherently risky, particularly in the extreme conditions in which many of our vessels, including the Petrojarl Varg, operate. An incident involving significant loss of product or environmental contamination by any of our vessels could harm our reputation and business. |
ThePetrojarl Vargand the vessels that service her are at risk of being damaged or lost because of events such as: |
• | marine disasters; | ||
• | bad weather; | ||
• | mechanical failures; | ||
• | capsizing, fire, explosions and collisions; | ||
• | piracy; | ||
• | human error; and | ||
• | war and terrorism. |
ThePetrojarl Vargoperates in the North Sea. Harsh weather conditions in this region may increase the risk of collisions, oil spills, or mechanical failures. |
An accident involving thePetrojarl Vargcould result in any of the following: |
• | death or injury to persons, loss of property or damage to the environment and natural resources; | ||
• | delays in the delivery of cargo; | ||
• | loss of revenues from its operation and charter contracts; | ||
• | liabilities or costs to recover any spilled oil or other petroleum products and to restore the eco-system where the spill occurred; | ||
• | governmental fines, penalties or restrictions on conducting business; | ||
• | higher insurance rates; and | ||
• | damage to our reputation and customer relationships generally. |
Any of these results could have a material adverse effect on our business, financial condition and operating results. In addition, any damage to, or environmental contamination involving, oil production facilities serviced could suspend that service and result in loss of revenues. |
We may experience operational problems with the Petrojarl Varg that reduce revenue and increase costs. |
FPSO units are complex and their operation is technically challenging, and we have not had experience operating FPSOs prior to our recent acquisition of thePetrojarl Varg. Marine transportation operations are subject to mechanical risks and problems. Operational problems may lead to loss of revenue or higher than anticipated operating expenses or require additional capital expenditures. Any of these results could harm our business, financial condition and operating results. |
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Because certain payments under the Petrojarl Varg operations contract are based on the volume of oil produced, the revenue from the Petrojarl Varg depends upon continued production from existing or new oil fields, which is beyond our control and generally declines naturally over time. Any decrease in the volume of oil produced or transported could adversely affect our business and operating results. |
Payments made to us under thePetrojarl Vargoperations contract are partially based on an incentive component. Payments under this contract are based upon the volume of oil produced, which depends upon the level of oil production at the Varg field. Oil production levels are affected by several factors, many of which are beyond our control, including: geologic factors, including general declines in production that occur naturally over time; mechanical failure or operator error; the rate of technical developments in extracting oil; the availability of necessary drilling and other governmental permits; the availability of qualified personnel and equipment; strikes, employee lockouts or other labor unrest; and regulatory changes;. In addition, the volume of oil may be adversely affected by extended repairs to oil field installations or suspensions of field operations as a result of oil spills or otherwise. |
The rate of oil production at the Varg field may decline from existing or future levels. If such a reduction occurs, we may receive a reduced or no incentive payment. In addition, Talisman Energy may terminate thePetrojarl Vargoperations contract if the Varg field does not yield sufficient revenues. Any idle time prior to the commencement of a new contract or our inability to redeploy the vessels at acceptable rates may have an adverse effect on our business and operating results. |
Over time, the value of the Petrojarl Varg may decline, which could adversely affect our operating results. |
Values for FPSO units such as thePetrojarl Vargcan fluctuate substantially over time due to a number of different factors, including: |
• | prevailing economic conditions in oil and energy markets; | ||
• | a substantial or extended decline in demand for oil; | ||
• | increases in the supply of vessel capacity; | ||
• | the cost of retrofitting or modifying existing vessels, as a result of technological advances in vessel design or equipment, changes in applicable environmental or other regulations or standards, or otherwise, and | ||
• | a decrease in oil reserves in the Varg field and other fields in which thePetrojarl Vargmight otherwise be deployed. |
If operation of thePetrojarl Vargis not profitable, or if we cannot re-deploy it at attractive rates upon termination of its operations and charter contracts, rather than continue to incur costs to maintain and finance the vessel, we may seek to dispose of it. Our inability to dispose of the vessel at a reasonable value could result in a loss on its sale and adversely affect our results of operations and financial condition. Further, if we determine at any time that thePetrojarl Varg’s future useful life and earnings require us to impair its value on our financial statements, we may need to recognize a significant charge against our earnings. |
None |
None |
None |
Taxation of the Partnership |
United States Taxation |
The following discussion updates our disclosure contained in our Annual Report on Form 20-F. The discussion is for general information purposes only and does not purport to be a comprehensive description of all the U.S. federal income tax considerations applicable to us. The discussion is based upon provisions of the U.S. Internal Revenue Code of 1986, as amended (or theCode), final, temporary and proposed regulations thereunder (orTreasury Regulations) and administrative rulings and court decisions, all as currently existing or in effect as of the date of this Report, all of which are subject to change, possibly with retroactive effect. Changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “we,” “our” or “us” are references to Teekay Offshore Partners, L.P. |
Election to be Taxed as a Corporation |
We have elected to be taxed as a corporation for U.S. federal income tax purposes. As such, we are subject to U.S. federal income tax on our income to the extent it is from U.S. sources or otherwise is effectively connected with the conduct of a trade or business in the United States as discussed below. |
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Taxation of Operating Income. |
A significant portion of our gross income will be attributable to the transportation of crude oil and related products. For this purpose, gross income attributable to transportation (orTransportation Income) includes income derived from, or in connection with, the use (or hiring or leasing for use) of a vessel to transport cargo, or the performance of services directly related to the use of any vessel to transport cargo, and thus includes both time charter or bareboat charter income. |
Transportation Income that is attributable to transportation that begins or ends (but not both) in the United States (orU.S. Source International Transportation Income) will be considered to be 50.0% derived from sources within the United States. Transportation Income attributable to transportation that both begins and ends in the United States (orU.S. Source Domestic Transportation Income) will be considered to be 100.0% derived from sources within the United States. Transportation Income attributable to transportation exclusively between non-U.S. destinations will be considered to be 100% derived from sources outside the United States. Transportation Income derived from sources outside the United States generally will not be subject to U.S. federal income tax. |
Based on our current operations, we expect substantially all of our Transportation Income to be from sources outside the United States and not subject to U.S. federal income tax. However, certain of our activities give rise to U.S. Source International Transportation Income, and future expansion of our operations could result in an increase in the amount of U.S. Source International Transportation Income, as well as give rise to U.S. Source Domestic Transportation Income, all of which will be subject to U.S. federal income taxation, unless, with respect to U.S. Source International Transportation Income, the exemption from U.S. taxation under Section 883 of the Code (or theSection 883 Exemption) applies. |
The Section 883 Exemption. In general, the Section 883 Exemption provides that if a non-U.S. corporation satisfies the requirements of Section 883 of the Code and the Treasury Regulations thereunder, it will not be subject to the net basis tax and branch profits tax or 4.0% gross basis tax described below on its U.S. Source International Transportation Income. The Section 883 Exemption only applies to U.S. Source International Transportation Income and generally may be applicable in the event Teekay Corporation (or certain other qualifying shareholders) own more than 50.0% of our outstanding equity interests for more than half of the number of days in a given taxable year. |
A non-U.S. corporation will qualify for the Section 883 Exemption if, among other things, it satisfies the following three requirements: |
We are organized under the laws of the Republic of the Marshall Islands. The U.S. Treasury Department has recognized the Republic of the Marshall Islands as a jurisdiction that grants an Equivalent Exemption; therefore, we meet the first requirement for the Section 883 Exemption. We expect that we will satisfy the substantiation, reporting and other requirements and therefore meet the third requirement for the Section 883 Exemption. With respect to the second requirement, we do not believe that we met the Controlled Foreign Corporation test or the Publicly Traded test in 2009 and we do not expect to meet these tests in 2010 or subsequent years. As a result, our ability to qualify for the Section 883 Exemption depends on our ability to satisfy the Qualified Shareholder test. |
With respect to the Qualified Shareholder test, we believe that Teekay Corporation owned more than 50.0% of the value of our outstanding equity interests for more than half of the number of days during 2009. As such, we believe that we satisfied the Qualified Shareholder test for 2009 and the U.S. Source International Transportation Income we earned in 2009 was exempt from U.S. federal income taxation by reason of the Section 883 Exemption. Teekay Corporation, however, now owns less than 50.0% of the value of our outstanding equity interests. As such, we expect that for 2010 and all succeeding years, we will not satisfy the Qualified Shareholder test and therefore we will not qualify for the Section 883 Exemption and our U.S. Source International Transportation Income will not be exempt from U.S. federal income taxation. |
The Net Basis Tax and Branch Profits Tax. If we earn U.S. Source Domestic Transportation Income, or U.S. Source International Transportation Income and the Section 883 Exemption does not apply, such income may be treated as effectively connected with the conduct of a trade or business in the United States (orEffectively Connected Income) if we have a fixed place of business in the United States and substantially all of our U.S. source Transportation Income is attributable to regularly scheduled transportation or, in the case of bareboat charter income, is attributable to a fixed placed of business in the United States. Based on our current operations, none of our anticipated U.S. Source International Transportation Income is attributable to regularly scheduled transportation or a fixed place of business in the United States. As a result, we do not anticipate that any of our U.S. Source International Transportation Income will be treated as Effectively Connected Income. However, there is no assurance that we will not earn income pursuant to regularly scheduled transportation or bareboat charters attributable to a fixed place of business in the United States in the future, which would result in such income being treated as Effectively Connected Income. In addition, U.S. Source Domestic Transportation Income generally is treated as Effectively Connected Income. |
Any income we earn that is treated as Effectively Connected Income would be subject to U.S. federal corporate income tax (the highest statutory rate currently is 35.0%). In addition, if we earn income that is treated as Effectively Connected Income, a 30.0% branch profits tax imposed under Section 884 of the Code generally would apply to such income, and a branch interest tax could be imposed on certain interest paid or deemed paid by us. |
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On the sale of a vessel that has produced Effectively Connected Income, we could be subject to the net basis corporate income tax and to the 30.0% branch profits tax with respect to our gain not in excess of certain prior deductions for depreciation that reduced Effectively Connected Income. Otherwise, we would not be subject to U.S. federal income tax with respect to gain realized on the sale of a vessel, provided the sale is considered to occur outside of the United States under U.S. federal income tax principles. |
The 4.0% Gross Basis Tax. We will be subject to a 4.0% U.S. federal income tax on our U.S. source Transportation Income, without benefit of deductions, for any year for which the Section 883 Exemption does not apply and the net basis tax and branch profits tax does not apply. In this regard, we estimate that we will be subject to less than $500,000 of U.S. federal income tax in 2010 based on the amount of U.S. Source International Transportation Income we earned for 2008 and 2009. The amount of such tax for which we are liable for any year will depend upon the amount of income we earn from voyages into or out of the United States in such year, however, which is not within our complete control. |
Material U.S. Federal Income Tax Considerations |
The following discussion updates our disclosure contained in our Annual Report on Form 20-F.The following is a discussion of the material U.S. federal income tax considerations that may be relevant to unitholders. This discussion is based upon provisions of the Internal Revenue Code of 1986, as amended (or theCode), final and temporary regulations thereunder (orTreasury Regulations), and current administrative rulings and court decisions, all as existing or in effect as of the date of this Report, all of which are subject to change, possibly with retroactive effect. Changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “we,” “our” or “us” are references to Teekay Offshore Partners, L.P. |
United States Federal Income Taxation of U.S. Holders |
The following summary applies only to beneficial owners of our common units that own the units as “capital assets” (generally, for investment purposes) and does not comment on all aspects of U.S. federal income taxation which may be important to particular unitholders in light of their individual circumstances, such as unitholders subject to special tax rules (e.g., financial institutions, insurance companies, broker-dealers, tax-exempt organizations, or former citizens or long-term residents of the United States), persons that will hold the common units as part of a straddle, hedge, conversion, constructive sale, or other integrated transaction for U.S. federal income tax purposes, partnerships or other entities treated as pass-through entities for U.S. federal income tax purposes or their partners, or to persons that have a functional currency other than the U.S. dollar, all of whom may be subject to tax rules that differ significantly from those summarized below. If a partnership or other entity taxed as a pass-through entity holds our common units, the tax treatment of a partner or owner thereof generally will depend upon the status of the partner or owner and upon the activities of the partnership or pass-through entity. If you are a partner in a partnership or owner of a pass-through entity holding our common units, you should consult your tax advisor. |
This summary does not discuss any U.S. state or local, estate or alternative minimum tax considerations regarding the ownership or disposition of common units. Each unitholder is urged to consult its tax advisor regarding the U.S. federal, state, local and other tax consequences of the ownership or disposition of common units. |
As used herein, the termU.S. Holdermeans a beneficial owner of our common units that is a U.S. citizen or U.S. resident alien, a corporation or other entity taxable as a corporation for U.S. federal income tax purposes, that was created or organized in or under the laws of the United States, any state thereof or the District of Columbia, an estate whose income is subject to U.S. federal income taxation regardless of its source, or a trust that either is subject to the supervision of a court within the United States and has one or more U.S. persons with authority to control all of its substantial decisions or has a valid election in effect under applicable U.S. Treasury Regulations to be treated as a United States person. |
Distributions |
We have elected to be taxed as a corporation for U.S. federal income tax purposes. Subject to the discussion of passive foreign investment companies (orPFICs) below, any distributions made by us with respect to our common units to a U.S. Holder generally will constitute dividends, which may be taxable as ordinary income or “qualified dividend income” as described in more detail below, to the extent of our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. Distributions in excess of our earnings and profits will be treated first as a nontaxable return of capital to the extent of the U.S. Holder’s tax basis in its common units on a dollar-for-dollar basis and thereafter as capital gain. U.S. Holders that are corporations generally will not be entitled to claim a dividends received deduction with respect to any distributions they receive from us. Dividends paid with respect to our common units generally will be treated as “passive category income” or, in the case of certain types of U.S. Holders, “general category income” for purposes of computing allowable foreign tax credits for U.S. federal income tax purposes. |
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Special rules may apply to any “extraordinary dividend” paid by us. An extraordinary dividend is, generally, a dividend with respect to a share of stock if the amount of the dividend is equal to or in excess of 10.0% of a stockholder’s adjusted basis (or fair market value in certain circumstances) in such stock. If we pay an “extraordinary dividend” on our common units that is treated as “qualified dividend income,” then any loss derived by a U.S. Individual Holder from the sale or exchange of such common units will be treated as long-term capital loss to the extent of such dividend. | ||
Consequences of Possible PFIC Classification |
A non-U.S. entity treated as a corporation for U.S. federal income tax purposes will be a PFIC in any taxable year in which, after taking into account the income and assets of the corporation and certain subsidiaries pursuant to a “look through” rule, either: (i) at least 75.0% of its gross income is “passive” income; or (ii) at least 50.0% of the average value of its assets is attributable to assets that produce passive income or are held for the production of passive income. For purposes of these tests, “passive income” includes dividends, interest, and gains from the sale or exchange of investment property and rents and royalties other than rents and royalties that are received from unrelated parties in connection with the active conduct of a trade or business. For purposes of these tests, income derived from the performance of services does not constitute “passive income.” |
There are legal uncertainties involved in determining whether the income derived from our time chartering activities constitutes rental income or income derived from the performance of services, including the decision inTidewater Inc. v. United States, 565 F.2d 299 (5th Cir. April 13, 2009), which held that income derived from certain time chartering activities should be treated as rental income rather than services income for purposes of a foreign sales corporation provision of the Code, and a recent unofficial IRS pronouncement issued to provide guidance to IRS field employees and examiners, which cites theTidewaterdecision favorably in support of the conclusion that income derived by foreign taxpayers from time chartering vessels engaged in the exploration for, or exploitation of, natural resources on the Outer Continental Shelf in the Gulf of Mexico is characterized as leasing or rental income for purposes of the income sourcing provisions of the Code. However, we believe that the nature of our time chartering activities, as well as our time charter contracts, differ in certain material respects from those at issue inTidewater.Consequently, based on our current assets and operations, we intend to take the position that we are not now and have never been a PFIC. No assurance can be given, however, that the IRS will accept our position or that we would not constitute a PFIC for any future taxable year if there were to be changes in our assets, income or operations. |
Current law provides that dividends received by a U.S. Individual Holder from a qualified foreign corporation are subject to U.S. federal income tax at preferential rates through 2010. However, if we are classified as a PFIC for a taxable year in which we pay a dividend or the immediately preceding taxable year, we would not be considered a qualified foreign corporation, and a U.S. Individual Holder receiving such dividends would not be eligible for the reduced rate of U.S. federal income tax. |
Additionally, as discussed more fully below, if we were to be treated as a PFIC for any taxable year, a U.S. Holder would be subject to different taxation rules depending on whether the U.S. Holder makes an election to treat us as a “Qualified Electing Fund” (aQEF election). As an alternative to making a QEF election, a U.S. Holder should be able to make a “mark-to-market” election with respect to our common units, as discussed below. |
Taxation of U.S. Holders Making a Timely QEF Election. If a U.S. Holder makes a timely QEF election (anElecting Holder), the Electing Holder must report for U.S. federal income tax purposes the Electing Holder’s pro rata share of our ordinary earnings and net capital gain, if any, for our taxable years that end with or within the Electing Holder’s taxable year, regardless of whether or not the Electing Holder received distributions from us in that year. The Electing Holder’s adjusted tax basis in the common units will be increased to reflect taxed but undistributed earnings and profits. Distributions of earnings and profits that were previously taxed will result in a corresponding reduction in the Electing Holder’s adjusted tax basis in common units and will not be taxed again once distributed. An Electing Holder generally will recognize capital gain or loss on the sale, exchange or other disposition of our common units. A U.S. Holder makes a QEF election with respect to any year that we are a PFIC by filing IRS Form 8621 with his U.S. federal income tax return. |
If a U.S. Holder has not made a timely and effective QEF election with respect to the first year in the holder’s holding period of our common units during which we qualified as a PFIC, the holder may be treated as having made a timely and effective QEF election by filing IRS Form 8621 with the holder’s timely filed U.S. federal income tax return (including extensions) and, under the rules of Section 1291 of the Code, a “deemed sale election” to recognize any gain that the holder would otherwise recognize if the holder sold the holder’s common units on the “qualification date”. The qualification date is the first day of our taxable year in which we qualified as a “qualified electing fund” with respect to such U.S. Holder. In addition to the above rules, under very limited circumstances, a U.S. Holder may make a retroactive QEF election if the holder failed to file the QEF election documents in a timely manner. |
If a U.S. Holder has made a QEF election with respect to us, then we would have to annually provide the holder with certain information concerning the subsidiary’s income and gain, calculated in accordance with the Code, and also would have to comply with certain record-keeping requirements imposed on a qualified electing fund in order for the holder to satisfy the qualified electing fund reporting rules. We have not provided our U.S. Holders with such qualified electing fund information in prior tax years and do not intend to provide such qualified electing fund information in the current tax year. If contrary to our expectations, we determine that we are or will be a PFIC for any taxable year, we will provide each U.S. Holder with the information necessary to make the QEF election described above. |
A U.S. Holder’s QEF election will not be valid unless we agree to provide certain information annually to the holder to be included with his U.S. federal income tax return. Accordingly, you will not be able to make a QEF election at this time, notwithstanding the present uncertainty regarding whether we are a PFIC. |
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Taxation of U.S. Holders Making a “Mark-to-Market” Election. If we were to be treated as a PFIC for any taxable year and, as we anticipate, our units were treated as “marketable stock,” then, as an alternative to making a QEF election, a U.S. Holder would be allowed to make a “mark-to-market” election with respect to our common units, provided the U.S. Holder completes and files IRS Form 8621 in accordance with the relevant instructions and related Treasury Regulations. If that election is made, the U.S. Holder generally would include as ordinary income in each taxable year the excess, if any, of the fair market value of the U.S. Holder’s common units at the end of the taxable year over the holder’s adjusted tax basis in the common units. The U.S. Holder also would be permitted an ordinary loss in respect of the excess, if any, of the U.S. Holder’s adjusted tax basis in the common units over the fair market value thereof at the end of the taxable year, but only to the extent of the net amount previously included in income as a result of the mark-to-market election. A U.S. Holder’s tax basis in his common units would be adjusted to reflect any such income or loss recognized. Gain recognized on the sale, exchange or other disposition of our common units would be treated as ordinary income, and any loss recognized on the sale, exchange or other disposition of the common units would be treated as ordinary loss to the extent that such loss does not exceed the net mark-to-market gains previously included in income by the U.S. Holder. Because the mark-to-market election only applies to marketable stock, however, it would not apply to a U.S. Holder’s indirect interest in any of our subsidiaries that were also determined to be PFICs. |
Taxation of U.S. Holders Not Making a Timely QEF or Mark-to-Market Election. If we were to be treated as a PFIC for any taxable year, a U.S. Holder who does not make either a QEF election or a “mark-to-market” election for that year (aNon-Electing Holder) would be subject to special rules resulting in increased tax liability with respect to (1) any excess distribution (i.e., the portion of any distributions received by the Non-Electing Holder on our common units in a taxable year in excess of 125.0% of the average annual distributions received by the Non-Electing Holder in the three preceding taxable years, or, if shorter, the Non-Electing Holder’s holding period for the common units), and (2) any gain realized on the sale, exchange or other disposition of the units. Under these special rules: |
• | the excess distribution or gain would be allocated ratably over the Non-Electing Holder’s aggregate holding period for the common units; |
• | the amount allocated to the current taxable year and any taxable year prior to the taxable year we were first treated as a PFIC with respect to the Non-Electing Holder would be taxed as ordinary income; and |
• | the amount allocated to each of the other taxable years would be subject to tax at the highest rate of tax in effect for the applicable class of taxpayers for that year, and an interest charge for the deemed deferral benefit would be imposed with respect to the resulting tax attributable to each such other taxable year. |
These rules generally would not apply to a qualified pension, profit sharing or other retirement trust or other tax-exempt organization that did not borrow money or otherwise utilize leverage in connection with its acquisition of our common units. If we were treated as a PFIC for any taxable year and a Non-Electing Holder who is an individual dies while owning our common units, such holder’s successor generally would not receive a step-up in tax basis with respect to such units. |
U.S. Holders are urged to consult their own tax advisors regarding the availability and advisability of, and procedure for, making QEF, Mark-to-Market Elections and other available elections with respect to us, and the U.S. federal income tax consequences of making such elections. | ||
Consequences of Possible Controlled Foreign Corporation Classification |
If more than 50.0% of either the total combined voting power of our outstanding units entitled to vote or the total value of all of our outstanding units were owned, directly, indirectly or constructively, by citizens or residents of the United States, U.S. partnerships or corporations, or U.S. estates or trusts (as defined for U.S. federal income tax purposes), each of which owned, directly, indirectly or constructively, 10.0% or more of the total combined voting power of our outstanding units entitled to vote (aUnited States Stockholder), we generally would be treated as a controlled foreign corporation (orCFC). United States Stockholders of a CFC are treated as receiving current distributions of their shares of certain income of the CFC without regard to any actual distributions and are subject to other burdensome U.S. federal income tax and administrative requirements, but generally are not also subject to the requirements generally applicable to owners of a PFIC. In addition, a person who is or has been a United States Stockholder of a CFC may recognize ordinary income on the disposition of shares of the CFC. Although we currently are not a CFC, U.S. persons purchasing a substantial interest in us should consult their tax advisors about the potential implications of being treated as a United States Stockholder in the event we were to become a CFC in the future. | ||
Sale, Exchange or other Disposition of Common Units |
Assuming we do not constitute a PFIC or CFC for any taxable year, a U.S. Holder generally will recognize taxable gain or loss upon a sale, exchange or other disposition of our common units in an amount equal to the difference between the amount realized by the U.S. Holder from such sale, exchange or other disposition and the U.S. Holder’s tax basis in such units. Subject to the discussion of extraordinary dividends above, such gain or loss will be treated as long-term capital gain or loss if the U.S. Holder’s holding period is greater than one year at the time of the sale, exchange or other disposition, and subject to preferential capital gain tax rates. Such capital gain or loss will generally be treated as U.S.-source gain or loss, as applicable, for U.S. foreign tax credit purposes. A U.S. Holder’s ability to deduct capital losses is subject to certain limitations. | ||
United States Federal Income Taxation of Non-U.S. Holders |
As used herein, the termNon-U.S. Holdermeans a beneficial owner of our common units (other than a partnership, including any entity or arrangement treated as a partnership for U.S. federal income tax purposes) that is not a U.S. Holder. |
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Distributions | ||
Distributions we make to a Non-U.S. Holder will not be subject to U.S. federal income tax or withholding tax if the Non-U.S. Holder is not engaged in a U.S. trade or business. If the Non-U.S. Holder is engaged in a U.S. trade or business, distributions we make will be subject to U.S. federal income tax to the extent those distributions constitute income effectively connected with that Non-U.S. Holder’s U.S. trade or business. However, distributions made to a Non-U.S. Holder that is engaged in a trade or business may be exempt from taxation under an income tax treaty if the income represented thereby is not attributable to a U.S. permanent establishment maintained by the Non-U.S. Holder. | ||
Disposition of Common Units |
The U.S. federal income taxation of Non-U.S. Holders on any gain resulting from the disposition of our common units generally is the same as described above regarding distributions. However, an individual Non-U.S. Holder may be subject to tax on gain resulting from the disposition of our common units if the holder is present in the United States for 183 days or more during the taxable year in which those shares are disposed and meets certain other requirements. |
Backup Withholding and Information Reporting | ||
In general, payments of distributions or the proceeds of a disposition of common units to a non-corporate U.S. Holder will be subject to information reporting requirements. These payments to a non-corporate U.S. Holder also may be subject to backup withholding if the non-corporate U.S. Holder: |
• | fails to provide an accurate taxpayer identification number; |
• | is notified by the IRS that it has failed to report all interest or distributions required to be shown on its U.S. federal income tax returns; or |
• | in certain circumstances, fails to comply with applicable certification requirements. |
Non-U.S. Holders may be required to establish their exemption from information reporting and backup withholding on payments within the United States, or through a U.S. payor or U.S. middleman (within the meaning of the Treasury Regulations), by certifying their status on IRS Form W-8BEN, W-8ECI or W-8IMY, as applicable. |
Backup withholding is not an additional tax. Rather, a unitholder generally may obtain a credit for any amount withheld against its liability for U.S. federal income tax (and a refund of any amounts withheld in excess of such liability) by filing a return with the IRS. | ||
Regulations |
The following discussion updates relevant disclosure in our Report on Form 20-F for the year ended December 31, 2008, as it pertains to certain United States environmental regulations and other environmental initiatives. |
Environmental Regulations — The United States Regulations. |
Effective as of July 31, 2009, the limit under the Oil Pollution Act of 1990 for double-hulled tank vessels was increased from the greater of $1,900 per gross tonne or $16.0 million per double hulled tanker per incident to $2,000 per gross tonne or $17.1 million per double hulled tanker per incident, subject to possible further adjustment for inflation. |
Environmental Regulation — Other Environmental Initiatives. |
• | The liability limits in countries that have ratified the 1992 Protocol to the International Convention on Civil Liability for Oil Pollution Damage, 1969, as amended, are currently approximately $6.9 million plus approximately $970 per gross registered tonne above 5,000 gross tonnes with an approximate maximum of $138 million per vessel and the exact amount tied to a unit of account which varies according to a basket of currencies. |
• | Since January 2009, several environmental Groups and industry associations have filed challenges in U.S. federal court to the Environmental Protection Agency’s issuance of a Clean Water Act permit entitled the “Vessel General Permit.” These cases have been consolidated in the D. C. Circuit and have not yet been resolved. |
• | The EU Directive 33/2005 (the “Directive”) came into force on January 1st, 2010. Under this legislation, vessels are required to burn fuel with sulphur content below 0.1% while berthed or anchored in an EU port. Currently, the only grade of fuel meeting this low sulphur content requirement is low sulphur marine gas oil (LSMGO). |
Certain capital modifications are necessary in order to optimize the operation on LSMGO for equipment originally designed to operate on Heavy Fuel Oil (HFO). The estimated cost of such capital modifications is $4.6 million. Furthermore, bunker fuel costs will increase as LSMGO is more expensive than HFO that is currently in use. |
Given that some equipment modification kits were not available until recently, several industry associations and groups have appealed to the EU on the need for a grace period before the new regulations are enforced. |
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None |
• | REGISTRATION STATEMENT ON FORM S-8 (NO. 333-147682) FILED WITH THE SEC ON NOVEMBER 28, 2007 | |
• | REGISTRATION STATEMENT ON FORM F-3 (NO. 333-150682) FILED WITH THE SEC ON MAY 6, 2008 |
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TEEKAY OFFSHORE PARTNERS L.P. | ||||
By: | Teekay Offshore GP L.L.C., its general partner | |||
Date: February 16, 2010 | By: | /s/ Peter Evensen | ||
Peter Evensen | ||||
Chief Executive Officer and Chief Financial Officer (Principal Financial and Accounting Officer) |
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