CONSOLIDATED FINANCIAL STATEMENTS AND
For the Year Ended December 31, 2003
Exhibit 2
MANAGEMENT’S REPORT
The management of Husky Energy Inc. is responsible for the financial information and operating data presented in this annual report.
The financial statements have been prepared by management in accordance with generally accepted accounting principles. When alternative accounting methods exist, management has chosen those it deems most appropriate in the circumstances. Financial statements are not precise as they include certain amounts based on estimates and judgements. Management has determined such amounts on a reasonable basis in order to ensure that the financial statements are presented fairly, in all material respects. Financial information presented elsewhere in this annual report has been prepared on a basis consistent with that in the financial statements.
Husky Energy Inc. maintains systems of internal accounting and administrative controls. These systems are designed to provide reasonable assurance that the financial information is relevant, reliable and accurate and that the Company’s assets are properly accounted for and adequately safeguarded. The system of internal controls is further supported by an internal audit function.
The Audit Committee of the Board of Directors, composed of non-management directors, meets regularly with management, as well as the external auditors, to discuss auditing (external, internal and joint venture), internal controls, accounting policy, financial reporting matters and reserves determination process. The Committee reviews the annual consolidated financial statements with both management and the independent auditors and reports its findings to the Board of Directors before such statements are approved by the Board.
The consolidated financial statements have been audited by KPMG LLP, the independent auditors, in accordance with generally accepted auditing standards on behalf of the shareholders. KPMG LLP have full and free access to the Audit Committee.
John C. S. Lau | Neil McGee | |
President & | Vice President & | |
Chief Executive Officer | Chief Financial Officer |
Calgary, Alberta, Canada
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AUDITORS’ REPORT TO THE SHAREHOLDERS
We have audited the consolidated balance sheets of Husky Energy Inc., as at December 31, 2003, 2002 and 2001 and the consolidated statements of earnings, retained earnings, and cash flows for each of the years in the three-year period ended December 31, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audit in accordance with Canadian generally accepted auditing standards and auditing standards generally accepted in the United States of America. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.
In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2003, 2002 and 2001 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2003 in accordance with Canadian generally accepted accounting principles.
KPMG LLP
Calgary, Alberta, Canada
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CONSOLIDATED BALANCE SHEETS
As at December 31 | |||||||||||||
2003 | 2002 | 2001 | |||||||||||
(millions of dollars) | |||||||||||||
Assets | |||||||||||||
Current assets | |||||||||||||
Cash and cash equivalents | $ | 3 | $ | 306 | $ | — | |||||||
Accounts receivable(note 4) | 618 | 572 | 376 | ||||||||||
Inventories(note 5) | 211 | 243 | 226 | ||||||||||
Prepaid expenses | 33 | 23 | 24 | ||||||||||
865 | 1,144 | 626 | |||||||||||
Property, plant and equipment, net(notes 1, 6)(full cost accounting) | 10,685 | 9,347 | 8,715 | ||||||||||
Goodwill(note 7) | 120 | — | — | ||||||||||
Other assets(note 11) | 112 | 84 | 29 | ||||||||||
$ | 11,782 | $ | 10,575 | $ | 9,370 | ||||||||
Liabilities and Shareholders’ Equity | |||||||||||||
Current liabilities | |||||||||||||
Bank operating loans(note 9) | $ | 71 | $ | — | $ | 100 | |||||||
Accounts payable and accrued liabilities(note 10) | 1,126 | 794 | 805 | ||||||||||
Long-term debt due within one year(note 11) | 259 | 421 | 144 | ||||||||||
1,456 | 1,215 | 1,049 | |||||||||||
Long-term debt(note 11) | 1,439 | 1,964 | 1,948 | ||||||||||
Other long-term liabilities(note 12) | 390 | 266 | 228 | ||||||||||
Future income taxes(note 13) | 2,608 | 2,003 | 1,659 | ||||||||||
Commitments and contingencies(note 14) | |||||||||||||
Shareholders’ equity | |||||||||||||
Capital securities and accrued return(note 15) | 298 | 364 | 367 | ||||||||||
Common shares(note 16) | 3,457 | 3,406 | 3,397 | ||||||||||
Retained earnings | 2,134 | 1,357 | 722 | ||||||||||
5,889 | 5,127 | 4,486 | |||||||||||
$ | 11,782 | $ | 10,575 | $ | 9,370 | ||||||||
On behalf of the Board: | ||
John C. S. Lau Director | Martin J. G. Glynn Director |
The accompanying notes to the consolidated financial statements are an integral part of these statements.
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CONSOLIDATED STATEMENTS OF EARNINGS
Year ended December 31 | |||||||||||||
2003 | 2002 | 2001 | |||||||||||
(millions of dollars, except per | |||||||||||||
share amounts) | |||||||||||||
Sales and operating revenues, net of royalties | $ | 7,658 | $ | 6,384 | $ | 6,596 | |||||||
Costs and expenses | |||||||||||||
Cost of sales and operating expenses | 4,825 | 4,009 | 4,425 | ||||||||||
Selling and administration expenses | 119 | 94 | 88 | ||||||||||
Depletion, depreciation and amortization(notes 1, 6) | 1,058 | 939 | 807 | ||||||||||
Interest — net(note 11) | 73 | 104 | 101 | ||||||||||
Foreign exchange(note 11) | (215 | ) | 13 | 94 | |||||||||
Other — net | 3 | 1 | 7 | ||||||||||
5,863 | 5,160 | 5,522 | |||||||||||
Earnings before income taxes | 1,795 | 1,224 | 1,074 | ||||||||||
Income taxes(note 13) | |||||||||||||
Current | 147 | 66 | 20 | ||||||||||
Future | 327 | 354 | 400 | ||||||||||
474 | 420 | 420 | |||||||||||
Net earnings | $ | 1,321 | $ | 804 | $ | 654 | |||||||
Earnings per share(note 16) | |||||||||||||
Basic | $ | 3.23 | $ | 1.88 | $ | 1.49 | |||||||
Diluted | $ | 3.22 | $ | 1.88 | $ | 1.48 |
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Year ended December 31 | |||||||||||||
2003 | 2002 | 2001 | |||||||||||
(millions of dollars) | |||||||||||||
Beginning of year | $ | 1,357 | $ | 722 | $ | 253 | |||||||
Net earnings | 1,321 | 804 | 654 | ||||||||||
Dividends on common shares(note 16) | (580 | ) | (151 | ) | (150 | ) | |||||||
Return on capital securities(note 15) | 38 | (29 | ) | (53 | ) | ||||||||
Related future income taxes(note 13) | (2 | ) | 11 | 18 | |||||||||
End of year | $ | 2,134 | $ | 1,357 | $ | 722 | |||||||
The accompanying notes to the consolidated financial statements are an integral part of these statements.
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CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended December 31 | ||||||||||||||
2003 | 2002 | 2001 | ||||||||||||
(millions of dollars) | ||||||||||||||
Operating activities | ||||||||||||||
Net earnings | $ | 1,321 | $ | 804 | $ | 654 | ||||||||
Items not affecting cash | ||||||||||||||
Depletion, depreciation and amortization | 1,058 | 939 | 807 | |||||||||||
Future income taxes | 327 | 354 | 400 | |||||||||||
Foreign exchange(note 11) | (242 | ) | — | 82 | ||||||||||
Other | (5 | ) | (1 | ) | 3 | |||||||||
Cash flow from operations | 2,459 | 2,096 | 1,946 | |||||||||||
Change in non-cash working capital(note 8) | 113 | (204 | ) | (16 | ) | |||||||||
Cash flow — operating activities | 2,572 | 1,892 | 1,930 | |||||||||||
Financing activities | ||||||||||||||
Bank operating loans financing — net | 71 | (100 | ) | 66 | ||||||||||
Long-term debt issue | 598 | 972 | — | |||||||||||
Long-term debt repayment | (971 | ) | (678 | ) | (356 | ) | ||||||||
Settlement of cross currency swap | (32 | ) | — | — | ||||||||||
Return on capital securities payment | (29 | ) | (31 | ) | (30 | ) | ||||||||
Debt issue costs | — | (9 | ) | — | ||||||||||
Deferred credits | — | — | (4 | ) | ||||||||||
Proceeds from exercise of stock options | 51 | 9 | 9 | |||||||||||
Proceeds from interest swaps monetization | 44 | — | — | |||||||||||
Dividends on common shares | (580 | ) | (151 | ) | (150 | ) | ||||||||
Change in non-cash working capital(note 8) | 48 | (9 | ) | 42 | ||||||||||
Cash flow — financing activities | (800 | ) | 3 | (423 | ) | |||||||||
Available for investing | 1,772 | 1,895 | 1,507 | |||||||||||
Investing activities | ||||||||||||||
Capital expenditures | (1,905 | ) | (1,692 | ) | (1,473 | ) | ||||||||
Corporate acquisitions | (809 | ) | (3 | ) | (125 | ) | ||||||||
Asset sales | 511 | 93 | 67 | |||||||||||
Other | 5 | (20 | ) | 6 | ||||||||||
Change in non-cash working capital(note 8) | 123 | 33 | 18 | |||||||||||
Cash flow — investing activities | (2,075 | ) | (1,589 | ) | (1,507 | ) | ||||||||
Increase (decrease) in cash and cash equivalents | (303 | ) | 306 | — | ||||||||||
Cash and cash equivalents at beginning of year | 306 | — | — | |||||||||||
Cash and cash equivalents at end of year | $ | 3 | $ | 306 | $ | — | ||||||||
The accompanying notes to the consolidated financial statements are an integral part of these statements.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Note 1 Segmented Financial Information
Upstream | Midstream | ||||||||||||||||||||||||||||||||||||
Infrastructure | |||||||||||||||||||||||||||||||||||||
Upgrading | and Marketing | ||||||||||||||||||||||||||||||||||||
2003 | 2002 | 2001 | 2003 | 2002 | 2001 | 2003 | 2002 | 2001 | |||||||||||||||||||||||||||||
Year ended December 31 | |||||||||||||||||||||||||||||||||||||
Sales and operating revenues, net of royalties | $ | 3,186 | $ | 2,665 | $ | 2,165 | $ | 1,013 | $ | 909 | $ | 886 | $ | 4,946 | $ | 4,230 | $ | 4,380 | |||||||||||||||||||
Costs and expenses | |||||||||||||||||||||||||||||||||||||
Operating, cost of sales, selling and general | 855 | 729 | 648 | 901 | 811 | 638 | 4,747 | 4,038 | 4,193 | ||||||||||||||||||||||||||||
Depletion, depreciation and amortization | 958 | 851 | 728 | 20 | 18 | 17 | 21 | 20 | 17 | ||||||||||||||||||||||||||||
Interest — net | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||
Foreign exchange | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||
1,813 | 1,580 | 1,376 | 921 | 829 | 655 | 4,768 | 4,058 | 4,210 | |||||||||||||||||||||||||||||
Earnings (loss) before income taxes | 1,373 | 1,085 | 789 | 92 | 80 | 231 | 178 | 172 | 170 | ||||||||||||||||||||||||||||
Current income taxes | 95 | 55 | 17 | 1 | 1 | 1 | 27 | 6 | 1 | ||||||||||||||||||||||||||||
Future income taxes | 230 | 342 | 290 | 20 | 25 | 72 | 37 | 59 | 71 | ||||||||||||||||||||||||||||
Net earnings (loss) | $ | 1,048 | $ | 688 | $ | 482 | $ | 71 | $ | 54 | $ | 158 | $ | 114 | $ | 107 | $ | 98 | |||||||||||||||||||
Capital employed — As at December 31 | $ | 6,652 | $ | 6,040 | $ | 5,715 | $ | 456 | $ | 319 | $ | 320 | $ | 350 | $ | 431 | $ | 395 | |||||||||||||||||||
Property, plant and equipment — As at December 31 | |||||||||||||||||||||||||||||||||||||
Cost | |||||||||||||||||||||||||||||||||||||
Canada | $ | 13,601 | $ | 11,525 | $ | 10,353 | $ | 1,022 | $ | 998 | $ | 958 | $ | 615 | $ | 591 | $ | 575 | |||||||||||||||||||
International | 496 | 469 | 394 | — | — | — | — | — | — | ||||||||||||||||||||||||||||
$ | 14,097 | $ | 11,994 | $ | 10,747 | $ | 1,022 | $ | 998 | $ | 958 | $ | 615 | $ | 591 | $ | 575 | ||||||||||||||||||||
Accumulated depletion, depreciation and amortization | |||||||||||||||||||||||||||||||||||||
Canada | $ | 4,633 | $ | 3,894 | $ | 3,272 | $ | 391 | $ | 372 | $ | 354 | $ | 203 | $ | 184 | $ | 165 | |||||||||||||||||||
International | 250 | 185 | 147 | — | — | — | — | — | — | ||||||||||||||||||||||||||||
$ | 4,883 | $ | 4,079 | $ | 3,419 | $ | 391 | $ | 372 | $ | 354 | $ | 203 | $ | 184 | $ | 165 | ||||||||||||||||||||
Net | |||||||||||||||||||||||||||||||||||||
Canada | $ | 8,968 | $ | 7,631 | $ | 7,081 | $ | 631 | $ | 626 | $ | 604 | $ | 412 | $ | 407 | $ | 410 | |||||||||||||||||||
International | 246 | 284 | 247 | — | — | — | — | — | — | ||||||||||||||||||||||||||||
$ | 9,214 | $ | 7,915 | $ | 7,328 | $ | 631 | $ | 626 | $ | 604 | $ | 412 | $ | 407 | $ | 410 | ||||||||||||||||||||
Capital expenditures — Year ended December 31 (2) | $ | 1,781 | $ | 1,567 | $ | 1,317 | $ | 25 | $ | 41 | $ | 47 | $ | 18 | $ | 17 | $ | 58 | |||||||||||||||||||
Total assets — As at December 31 (3) | |||||||||||||||||||||||||||||||||||||
Canada | $ | 9,547 | $ | 7,883 | $ | 7,160 | $ | 649 | $ | 658 | $ | 644 | $ | 701 | $ | 850 | $ | 862 | |||||||||||||||||||
International | 259 | 337 | 247 | — | — | — | — | — | — | ||||||||||||||||||||||||||||
$ | 9,806 | $ | 8,220 | $ | 7,407 | $ | 649 | $ | 658 | $ | 644 | $ | 701 | $ | 850 | $ | 862 | ||||||||||||||||||||
(1) | Eliminations relate to sales and operating revenues between segments recorded at transfer prices based on current market prices, and to unrealized intersegment profits in inventories. |
(2) | Includes site restoration expenditures. See note 12, Other Long-term Liabilities. |
(3) | 2003 includes goodwill on Marathon Canada Limited acquisition related to Upstream. |
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Corporate and | |||||||||||||||||||||||||||||||||||||
Refined Products | Eliminations (1) | Total | |||||||||||||||||||||||||||||||||||
2003 | 2002 | 2001 | 2003 | 2002 | 2001 | 2003 | 2002 | 2001 | |||||||||||||||||||||||||||||
Year ended December 31 | |||||||||||||||||||||||||||||||||||||
Sales and operating revenues, net of royalties | $ | 1,502 | $ | 1,310 | $ | 1,349 | $ | (2,989 | ) | $ | (2,730 | ) | $ | (2,184 | ) | $ | 7,658 | $ | 6,384 | $ | 6,596 | ||||||||||||||||
Costs and expenses | |||||||||||||||||||||||||||||||||||||
Operating, cost of sales, selling and general | 1,422 | 1,222 | 1,206 | (2,978 | ) | (2,696 | ) | (2,165 | ) | 4,947 | 4,104 | 4,520 | |||||||||||||||||||||||||
Depletion, depreciation and amortization | 34 | 34 | 31 | 25 | 16 | 14 | 1,058 | 939 | 807 | ||||||||||||||||||||||||||||
Interest — net | — | — | — | 73 | 104 | 101 | 73 | 104 | 101 | ||||||||||||||||||||||||||||
Foreign exchange | — | — | — | (215 | ) | 13 | 94 | (215 | ) | 13 | 94 | ||||||||||||||||||||||||||
1,456 | 1,256 | 1,237 | (3,095 | ) | (2,563 | ) | (1,956 | ) | 5,863 | 5,160 | 5,522 | ||||||||||||||||||||||||||
Earnings (loss) before income taxes | 46 | 54 | 112 | 106 | (167 | ) | (228 | ) | 1,795 | 1,224 | 1,074 | ||||||||||||||||||||||||||
Current income taxes | 9 | 4 | 1 | 15 | — | — | 147 | 66 | 20 | ||||||||||||||||||||||||||||
Future income taxes | 9 | 18 | 48 | 31 | (90 | ) | (81 | ) | 327 | 354 | 400 | ||||||||||||||||||||||||||
Net earnings (loss) | $ | 28 | $ | 32 | $ | 63 | $ | 60 | $ | (77 | ) | $ | (147 | ) | $ | 1,321 | $ | 804 | $ | 654 | |||||||||||||||||
Capital employed — As at December 31 | $ | 320 | $ | 338 | $ | 329 | $ | (120 | ) | $ | 384 | $ | (81 | ) | $ | 7,658 | $ | 7,512 | $ | 6,678 | |||||||||||||||||
Property, plant and equipment — As at December 31 | |||||||||||||||||||||||||||||||||||||
Cost | |||||||||||||||||||||||||||||||||||||
Canada | $ | 757 | $ | 702 | $ | 655 | $ | 188 | $ | 165 | $ | 143 | $ | 16,183 | $ | 13,981 | $ | 12,684 | |||||||||||||||||||
International | — | — | — | — | — | — | 496 | 469 | 394 | ||||||||||||||||||||||||||||
$ | 757 | $ | 702 | $ | 655 | $ | 188 | $ | 165 | $ | 143 | $ | 16,679 | $ | 14,450 | $ | 13,078 | ||||||||||||||||||||
Accumulated depletion, depreciation and amortization | |||||||||||||||||||||||||||||||||||||
Canada | $ | 391 | $ | 360 | $ | 330 | $ | 126 | $ | 108 | $ | 95 | $ | 5,744 | $ | 4,918 | $ | 4,216 | |||||||||||||||||||
International | — | — | — | — | — | — | 250 | 185 | 147 | ||||||||||||||||||||||||||||
$ | 391 | $ | 360 | $ | 330 | $ | 126 | $ | 108 | $ | 95 | $ | 5,994 | $ | 5,103 | $ | 4,363 | ||||||||||||||||||||
Net | |||||||||||||||||||||||||||||||||||||
Canada | $ | 366 | $ | 342 | $ | 325 | $ | 62 | $ | 57 | $ | 48 | $ | 10,439 | $ | 9,063 | $ | 8,468 | |||||||||||||||||||
International | — | — | — | — | — | — | 246 | 284 | 247 | ||||||||||||||||||||||||||||
$ | 366 | $ | 342 | $ | 325 | $ | 62 | $ | 57 | $ | 48 | $ | 10,685 | $ | 9,347 | $ | 8,715 | ||||||||||||||||||||
Capital expenditures — Year ended December 31 (2) | $ | 58 | $ | 44 | $ | 29 | $ | 23 | $ | 23 | $ | 22 | $ | 1,905 | $ | 1,692 | $ | 1,473 | |||||||||||||||||||
Total assets — As at December 31 (3) | |||||||||||||||||||||||||||||||||||||
Canada | $ | 525 | $ | 534 | $ | 428 | $ | 101 | $ | 313 | $ | 29 | $ | 11,523 | $ | 10,238 | $ | 9,123 | |||||||||||||||||||
International | — | — | — | — | — | — | 259 | 337 | 247 | ||||||||||||||||||||||||||||
$ | 525 | $ | 534 | $ | 428 | $ | 101 | $ | 313 | $ | 29 | $ | 11,782 | $ | 10,575 | $ | 9,370 | ||||||||||||||||||||
Note 2 Nature of Operations and Organization
Husky Energy Inc. (“Husky” or “the Company”) is a publicly traded, integrated energy and energy-related company headquartered in Calgary, Alberta, Canada.
Management has segmented the Company’s business based on differences in products and services and management strategy and responsibility. The Company’s business is conducted predominantly through three major business segments — upstream, midstream and refined products.
Upstream includes exploration for, development and production of crude oil, natural gas and natural gas liquids. The Company’s upstream operations are located primarily in Western Canada, offshore Eastern Canada (East Coast), South China Sea (Wenchang), with some other interests outside Canada (International).
Midstream includes upgrading of heavy crude oil feedstock into synthetic crude oil (Upgrading); marketing of the Company’s and other producers’ crude oil, natural gas, natural gas liquids, sulphur and petroleum coke; and pipeline transportation and processing of heavy crude oil, storage of crude oil, diluent and natural gas and cogeneration of electrical and thermal energy (Infrastructure and marketing).
Refined products includes refining of crude oil and marketing of refined petroleum products including gasoline, alternative fuels and asphalt.
Note 3 Significant Accounting Policies
a) Principles of Consolidation and the Preparation of Financial Statements |
These financial statements are prepared in accordance with Canadian generally accepted accounting principles (“GAAP”) which, in the case of the Company, differ in certain respects from those in the United States. These differences are described in note 20, Reconciliation to Accounting Principles Generally Accepted in the United States.
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The preparation of financial statements in conformity with Canadian GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. Actual results could differ from these estimates.
The consolidated financial statements include the accounts of the Company and its subsidiaries.
Substantially all of the Company’s upstream activities are conducted jointly with third parties and accordingly the accounts reflect the Company’s proportionate share of the assets, liabilities, revenues, expenses and cash flow from these activities.
b) Cash and Cash Equivalents |
Cash and cash equivalents consist of cash on hand and deposits with a maturity of less than three months.
c) Inventory Valuation |
Crude oil, natural gas, refined petroleum products and purchased sulphur inventories are valued at the lower of cost, on a first-in, first-out basis, or net realizable value. Materials and supplies are stated at average cost. Cost consists of raw material, labour, direct overhead and transportation. Intersegment profits are eliminated.
d) Property, Plant and Equipment |
i) Oil and Gas |
The Company employs the full cost method of accounting for oil and gas interests whereby all costs of acquisition, exploration for and development of oil and gas reserves are capitalized and accumulated within cost centres on a country-by-country basis. Such costs include land acquisition, geological and geophysical activity, drilling of productive and non-productive wells, carrying costs directly related to unproved properties and administrative costs directly related to exploration and development activities. Interest is capitalized on certain major capital projects based on the Company’s long-term cost of borrowing.
The provision for depletion of oil and gas properties and depreciation of associated production facilities is calculated using the unit of production method, based on gross proved oil and gas reserves as estimated by the Company’s engineers, for each cost centre. Depreciation of gas plants and certain other oil and gas facilities is provided using the straight-line method based on their estimated useful lives. In the normal course of operations, retirements of oil and gas interests are accounted for by charging the asset cost, net of any proceeds, to accumulated depletion or depreciation. Gains or losses on the disposition of oil and gas properties are not recognized unless the gain or loss changes the depletion rate by 20 percent or more.
Costs of acquiring and evaluating significant unproved oil and gas interests are excluded from costs subject to depletion and depreciation until it is determined that proved oil and gas reserves are attributable to such interests or until impairment occurs. Costs of major development projects are excluded from costs subject to depletion and depreciation until the earliest of when a portion of the property becomes capable of production, or when development activity ceases, or when impairment occurs.
The aggregate carrying values of oil and gas interests are subject to cost recovery ceiling tests. Net capitalized costs in each cost centre are limited to the estimated future net revenues from proved oil and gas reserves, at prices and costs in effect at year-end, plus the cost of unproved properties and major development projects, less impairment. In addition, the net capitalized costs of all cost centres, less the related future income tax liability and site restoration liability, are limited to the estimated future net revenues from all cost centres plus the net cost of major development projects and unproved properties less future removal and site restoration costs, administration expenses, financing costs and income taxes. Any amounts in excess of these limits are charged to earnings.
In September 2003, the Accounting Standards Board (“AcSB”) of the Canadian Institute of Chartered Accountants (“CICA”) issued Accounting Guideline 16, “Oil and Gas Accounting — Full Cost” (“AcG-16”), which replaces Accounting Guideline 5, “Full Cost Accounting in the Oil and Gas Industry” (“AcG-5”). AcG-16 will be effective January 1, 2004. AcG-16 modifies the ceiling test in AcG-5 to be consistent with CICA section 3063, “Impairment of Long-lived Assets”, which requires the impairment test to be performed by comparing the carrying amount of a cost centre to its fair value. For full cost oil and gas companies an impairment loss is to be recognized when the carrying amount is not recoverable and exceeds its fair value. The carrying amount is not considered recoverable if the carrying amount exceeds the sum of the undiscounted cash flows expected from the cost centre’s use and eventual disposition. Fair value is estimated using the expected present value approach which incorporates risks and uncertainties in the expected future cash flows which are discounted using a risk free rate. AcG-16 is consistent with CICA section 3475, “Disposal of Long-lived Assets and Discontinued Operations”. For full cost oil and gas companies, discontinued operations presentation is only used when a cost centre has been disposed of.
ii) Other Plant and Equipment |
Depreciation for substantially all other plant and equipment, except upgrading assets, is provided using the straight-line method based on estimated useful lives of assets which range from five to 20 years. Depreciation for upgrading assets is provided using the unit of production method, based on the plant’s estimated productive life. When the net carrying amount of other plant and equipment, less related accumulated provisions for future removal and site restoration costs and future income taxes, exceeds the net recoverable amount, the excess is charged to earnings. Repairs and maintenance costs, other than major turnaround costs, are charged to earnings as incurred. Major turnaround costs are deferred when incurred and amortized over the estimated period of time to the next scheduled turnaround. At the time of disposition of plant and equipment, accounts are relieved of the asset values and accumulated depreciation and any resulting gain or loss is reflected in earnings.
8
iii) Future Removal and Site Restoration Costs |
Future removal and site restoration costs, where they are probable and can be reasonably estimated, are provided for using the method of depletion or depreciation related to the asset. Costs are estimated by the Company’s engineers based on current regulations, costs, technology and industry standards. The annual charge is included in the provision for depletion, depreciation and amortization. Removal and site restoration expenditures are charged to the accumulated provision as incurred.
In March 2003, the AcSB issued CICA section 3110, “Asset Retirement Obligations”, that addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the related asset retirement costs. The new recommendations will be effective January 1, 2004 and are substantially similar to the U.S. Financial Accounting Standards Board (“FASB”) Statement No. 143, “Accounting for Asset Retirement Obligations” (“FAS 143”). Note 20 presents the recognition, measurement and disclosure required by FAS 143 in the financial statements.
e) Impairment or Disposal of Long-lived Assets |
In December 2002, the AcSB issued CICA section 3063, “Impairment of Long-lived Assets”, and section 3475, “Disposal of Long-lived Assets and Discontinued Operations”, that address the accounting and reporting for the impairment and disposal of long-lived assets and are substantially similar to FASB Statement No. 144, “Accounting for the Impairment and Disposal of Long-lived Assets”. Section 3063 will be effective January 1, 2004. Section 3475 was in effect for 2003. An impairment loss is recognized when the carrying value of a long-lived asset is not recoverable and exceeds its fair value. Testing for recoverability uses the undiscounted cash flows expected from the asset’s use and disposition. To test for and measure impairment, long-lived assets are grouped at the lowest level for which identifiable cash flows are largely independent.
A long-lived asset that meets the conditions as held for sale is measured at the lower of its carrying amount or fair value less costs to sell. Such assets are not amortized while they are classified as held for sale. The results of operations of a component of an entity that has been disposed of, or is classified as held for sale, are reported in discontinued operations if: i) the operations and cash flows of the component have been or will be eliminated as a result of the disposal transaction; and, ii) the entity will not have a significant continuing involvement in the operations of the component after the disposal transaction.
A component of an entity comprises operations and cash flows that can be clearly distinguished operationally and for financial reporting purposes from the rest of the enterprise. A component may be a reportable segment or an operating segment, a reporting unit, a subsidiary or an asset group.
f) Goodwill |
Goodwill is the excess of the purchase price paid over the fair value of net assets acquired. Goodwill is subject to impairment tests on an annual basis unless three conditions are met: i) the assets and liabilities that make up the reporting unit have not changed significantly since the most recent fair value determination; ii) the most recent fair value determination resulted in an amount that exceeded the carrying amount of the reporting unit by a substantial margin; and, iii) based on an analysis of events that have occurred and circumstances that have changed since the most recent fair value determination, the likelihood that a current fair value determination would be less than the current carrying amount of the reporting unit is remote. The two-step impairment test begins with comparing the fair value of the reporting unit with its carrying amount. If any potential impairment is indicated, then it is quantified by comparing the carrying value of goodwill to its fair value, based on the fair value of the assets and liabilities of the reporting unit. Impairment losses would be recognized in current period earnings. Refer to note 7, Acquisition of Marathon Canada.
g) Derivative Financial Instruments |
Derivative financial instruments are utilized by the Company to manage market risk against the volatility in commodity prices, foreign exchange rates and interest rate exposures. The Company’s policy is not to utilize derivative financial instruments for speculative purposes.
When applicable, the Company formally documents all relationships between hedged items and hedging items, the risk management objectives and strategy for undertaking various hedge transactions. This process includes linking all derivatives to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions. The Company also formally assesses, both at the inception of the hedge and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair values or cash flows of hedged items.
The Company may enter into commodity price contracts to hedge anticipated sales of oil and natural gas production to manage its exposure to price fluctuations. The Company’s production is expected to be sufficient to deliver all required volumes. Gains and losses from these contracts are recognized in upstream oil and gas revenues as the related sales occur.
The Company may enter into commodity price contracts to offset fixed price contracts entered into with customers and suppliers in order to retain market prices while meeting customer or supplier pricing requirements. The Company’s production is expected to be sufficient to deliver all required volumes. Gains and losses from these contracts are recognized in midstream revenues or cost of sales as the related sales or purchases occur.
The Company may enter into interest rate swap agreements to manage its fixed and floating interest rate mix on long-term debt. These swaps are designated as hedges of the underlying debt. These agreements require the periodic exchange of payments without the exchange of the notional principal amount upon which the payments are based and are recorded as an adjustment to the interest expense on the hedged debt instrument. The related amount payable or receivable from the counterparties is recorded as an adjustment to accrued interest.
9
The Company may enter into foreign exchange contracts to hedge its foreign currency exposures on U.S. dollar denominated long-term debt. Gains and losses on these instruments are accrued under other current, or non-current, assets or liabilities on the balance sheet and recognized in foreign exchange in the period to which they relate, offsetting the respective foreign exchange gains and losses recognized on the underlying foreign currency long-term debt. The forward premium or discount on the forward foreign exchange option contract is amortized as an adjustment to interest expense over the term of the contract.
The Company may enter into foreign exchange forwards and foreign exchange collars to hedge anticipated U.S. dollar denominated sales. Gains and losses on these instruments are recognized as an adjustment to upstream oil and gas revenues when the sale is recorded.
Realized and unrealized gains or losses associated with derivative financial instruments which have been terminated or cease to be effective prior to maturity are deferred under current or non-current assets or liabilities on the balance sheet and recognized into income in the period in which the underlying hedged transaction is recognized. In the event that a designated hedged item is sold, extinguishes or matures prior to the termination of the related derivative financial instrument, any realized or unrealized gain or loss is recognized into earnings.
In December 2001, the AcSB issued Accounting Guideline 13, “Hedging Relationships”, that establishes standards for the documentation and effectiveness of hedging activities that are substantially similar to the corresponding documentation requirements in FASB Statement No. 133 “Accounting for Derivative Instruments and Hedging Activities” (“FAS 133”). The new recommendations will be effective January 1, 2004. Note 20 discloses the impact of FAS 133 on the financial statements for 2003.
h) Employee Future Benefits |
The Company provides a defined contribution pension plan and a post-retirement health and dental care plan to qualified employees. The Company also maintains a defined benefit pension plan for a small number of employees who did not choose to join the defined contribution pension plan in 1991. The cost of the pension benefits earned by employees in the defined contribution pension plan is paid and expensed when incurred. The cost of the benefits earned by employees in the post-retirement health and dental care plan and defined benefit pension plan is charged to earnings as services are rendered using the projected benefit method prorated on service. The cost of the post-retirement health and dental care plan and defined benefit pension plan reflects a number of assumptions that affect the expected future benefit payments. These assumptions include, but are not limited to, attrition, mortality, the rate of return on pension plan assets and salary escalations for the defined benefit pension plan and expected health care cost trends for the post-retirement health and dental care plan. The plan assets are valued at fair value for the purposes of calculating the expected return on plan assets.
Adjustments arising out of plan amendments, changes in assumptions and experience gains and losses are normally amortized over the expected remaining average service life of the employee group.
i) Revenue Recognition |
Revenues from the sale of crude oil, natural gas, natural gas liquids, synthetic crude oil, purchased commodities and refined petroleum products are recorded on a gross basis when title passes to an external party. Sales between the business segments of the Company are eliminated from sales and operating revenues and cost of sales. Revenues associated with the sale of transportation, processing and natural gas storage services are recognized when the services are provided.
j) Foreign Currency Translation |
Results of foreign operations, all of which are considered financially and operationally integrated, are translated to Canadian dollars at the monthly average exchange rates for revenue and expenses, except for depreciation and depletion which are translated at the rate of exchange applicable to the related assets. Monetary assets and liabilities are translated at current exchange rates and non-monetary assets and liabilities are translated using historical rates of exchange. Gains or losses resulting from these translation adjustments are included in earnings. Capital securities are adjusted to the current rate of exchange and included in retained earnings.
k) Stock-based Compensation |
In accordance with the Company’s stock option plan, common share options may be granted to directors, officers and certain other employees. The Company does not recognize compensation expense on the issuance of common share options under this plan because the exercise price of the options is equal to the market value of the common shares when the options are granted. In accordance with CICA section 3870, “Stock-based Compensation and Other Stock-based Payments”, note 16 discloses the impact on the financial statements for options granted after January 1, 2002. The recommendations are substantially similar to those in FASB Statement No. 123, “Accounting for Stock-based Compensation” (“FAS 123”). Note 20 presents the disclosures required by FAS 123 in the financial statements.
In September 2003, the AcSB amended the recommendations on stock-based compensation. The new recommendations will be effective January 1, 2004 and will require that all stock-based compensation be measured and recognized based on the fair value of the instruments and will result in an expense that is recognized in the financial statements. The Company intends to adopt the changes retroactively in 2004 without restatement of prior periods. Retained earnings for 2004 will be decreased by $44 million with an increase to contributed surplus of $21 million and an increase to share capital of $23 million.
l) Earnings Per Share |
Basic common shares outstanding are the weighted average number of common shares outstanding for each period. Diluted common shares outstanding are calculated using the treasury stock method, which assumes that any proceeds received from in-the-money options would be used to buy back common shares at the average market price for the period. In addition, diluted common shares also include the effect of the potential exercise of any outstanding warrants.
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m) Reclassification |
Certain prior years’ amounts have been reclassified to conform with current presentation.
Note 4 Accounts Receivable
2003 | 2002 | 2001 | ||||||||||
Trade receivables | $ | 568 | $ | 530 | $ | 379 | ||||||
Investment tax credit | 48 | 45 | — | |||||||||
Allowance for doubtful accounts | (12 | ) | (11 | ) | (8 | ) | ||||||
Other | 14 | 8 | 5 | |||||||||
$ | 618 | $ | 572 | $ | 376 | |||||||
Sale of Accounts Receivable |
In November 2003, the Company established a securitization program to sell, on a revolving basis, up to $250 million of accounts receivable to a third party. As at December 31, 2003, $250 million in outstanding accounts receivable had been sold under the program. The agreement includes a program fee based on Canadian commercial paper rates.
In 2002 and 2001, the Company had an agreement to sell up to $200 million of net trade receivables on a continual basis. The agreement called for purchase discounts which were based on Canadian commercial paper rates. The average effective rate for 2002 and 2001 was approximately 2.8 percent and 4.7 percent, respectively.
Note 5 | Inventories |
2003 | 2002 | 2001 | ||||||||||
Crude oil and refined petroleum products | $ | 121 | $ | 166 | $ | 140 | ||||||
Natural gas | 69 | 50 | 69 | |||||||||
Materials, supplies and other | 21 | 27 | 17 | |||||||||
$ | 211 | $ | 243 | $ | 226 | |||||||
Note 6 | Property, Plant and Equipment |
Refer to note 1, Segmented Financial Information, which presents the Company’s property, plant and equipment by segment.
Costs of oil and gas properties, including major development projects, excluded from costs subject to depletion and depreciation at December 31 were as follows:
2003 | 2002 | 2001 | ||||||||||
Canada | $ | 1,814 | $ | 1,318 | $ | 1,226 | ||||||
International | 54 | 37 | 235 | |||||||||
$ | 1,868 | $ | 1,355 | $ | 1,461 | |||||||
Note 7 | Acquisition of Marathon Canada |
Effective October 1, 2003 the Company acquired all of the issued and outstanding shares of Marathon Canada Limited and the Western Canadian assets of Marathon International Petroleum Canada, Ltd. (“Marathon Canada”) for cash consideration of U.S. $611 million (Cdn. $831 million). The results of Marathon Canada are included in the consolidated financial statements of the Company from the date of acquisition.
The allocation of the aggregate purchase price based on the estimated fair values of Marathon Canada’s net assets acquired at October 1, 2003 was as follows:
Allocation | |||||
Net assets acquired | |||||
Working capital (1) | $ | 5 | |||
Property, plant and equipment | 1,008 | ||||
Goodwill (2) | 120 | ||||
Site restoration | (38 | ) | |||
Future income taxes | (264 | ) | |||
$ | 831 | ||||
(1) | Working capital acquired includes cash of $22 million. |
(2) | Allocated to the Company’s upstream segment and not deductible for income tax purposes. Refer to note 1, Segmented Financial Information. |
In conjunction with the above acquisition of Marathon Canada, the Company sold certain of the Marathon Canada oil and gas properties to a third party for cash consideration of U.S. $320 million (Cdn. $431 million).
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Note 8 | Cash Flows — Change in Non-cash Working Capital |
a) Change in non-cash working capital was as follows: |
2003 | 2002 | 2001 | |||||||||||
Decrease (increase) in non-cash working capital | |||||||||||||
Accounts receivable | $ | (7 | ) | $ | (153 | ) | $ | 361 | |||||
Inventories | 31 | (17 | ) | (40 | ) | ||||||||
Prepaid expenses | (10 | ) | 1 | 3 | |||||||||
Accounts payable and accrued liabilities | 270 | (11 | ) | (280 | ) | ||||||||
Change in non-cash working capital | 284 | (180 | ) | 44 | |||||||||
Relating to: | |||||||||||||
Financing activities | 48 | (9 | ) | 42 | |||||||||
Investing activities | 123 | 33 | 18 | ||||||||||
Operating activities | $ | 113 | $ | (204 | ) | $ | (16 | ) | |||||
b) Other cash flow information: |
2003 | 2002 | 2001 | ||||||||||
Cash taxes paid | $ | 69 | $ | 20 | $ | 13 | ||||||
Cash interest paid | $ | 134 | $ | 139 | $ | 145 | ||||||
Note 9 | Bank Operating Loans |
At December 31, 2003 the Company had short-term borrowing lines of credit with banks totalling $195 million (2002 and 2001 — $195 million). As at December 31, 2003, $71 million (2002 — nil; 2001 — $100 million) had been used for bank operating loans and $18 million (2002 — $12 million; 2001 — $2 million) had been used for letters of credit. Interest payable is based on Bankers’ Acceptance, money market, or prime rates. During 2003, the weighted average interest rate on short-term borrowings was approximately 3.7 percent (2002 — 2.9 percent; 2001 — 4.6 percent).
Note 10 | Accounts Payable and Accrued Liabilities |
2003 | 2002 | 2001 | ||||||||||
Trade payables | $ | 58 | $ | 87 | $ | 58 | ||||||
Accrued liabilities | 794 | 562 | 547 | |||||||||
Dividend payable | 42 | 38 | 38 | |||||||||
Current income taxes | 117 | 51 | 7 | |||||||||
Other | 115 | 56 | 155 | |||||||||
$ | 1,126 | $ | 794 | $ | 805 | |||||||
Note 11 | Long-term Debt |
Cdn. $ Amount | U.S. $ Amount | ||||||||||||||||||||||||||
Maturity | 2003 | 2002 | 2001 | 2003 | 2002 | 2001 | |||||||||||||||||||||
Long-term debt | |||||||||||||||||||||||||||
Revolving syndicated credit facility | $ | — | $ | — | $ | 185 | $ | — | $ | — | $ | 116 | |||||||||||||||
6.25% notes | 2012 | 517 | 632 | — | 400 | 400 | — | ||||||||||||||||||||
6.875% notes | — | 237 | 239 | — | 150 | 150 | |||||||||||||||||||||
7.125% notes | 2006 | 194 | 237 | 239 | 150 | 150 | 150 | ||||||||||||||||||||
7.55% debentures | 2016 | 258 | 316 | 318 | 200 | 200 | 200 | ||||||||||||||||||||
8.45% senior secured bonds | 2004-12 | 188 | 256 | 276 | 145 | 162 | 173 | ||||||||||||||||||||
Private placement notes | 2004-5 | 41 | 107 | 135 | 32 | 68 | 85 | ||||||||||||||||||||
Medium-term notes | 2004-9 | 500 | 600 | 700 | — | — | — | ||||||||||||||||||||
Total long-term debt | 1,698 | 2,385 | 2,092 | $ | 927 | $ | 1,130 | $ | 874 | ||||||||||||||||||
Amount due within one year | (259 | ) | (421 | ) | (144 | ) | |||||||||||||||||||||
$ | 1,439 | $ | 1,964 | $ | 1,948 | ||||||||||||||||||||||
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Interest — net for the years ended December 31 was as follows:
2003 | 2002 | 2001 | ||||||||||
Long-term debt | $ | 129 | $ | 128 | $ | 148 | ||||||
Short-term debt | 2 | 3 | 5 | |||||||||
131 | 131 | 153 | ||||||||||
Amount capitalized | (52 | ) | (26 | ) | (51 | ) | ||||||
79 | 105 | 102 | ||||||||||
Interest income | (6 | ) | (1 | ) | (1 | ) | ||||||
$ | 73 | $ | 104 | $ | 101 | |||||||
Foreign exchange for the years ended December 31 was as follows:
2003 | 2002 | 2001 | ||||||||||
(Gain) loss on translation of U.S. dollar denominated long-term debt | $ | (315 | ) | $ | — | $ | 82 | |||||
Cross currency swaps | 73 | — | — | |||||||||
Other losses | 27 | 13 | 12 | |||||||||
$ | (215 | ) | $ | 13 | $ | 94 | ||||||
As at December 31, 2003, other assets included $19 million (2002 — $23 million; 2001 — $17 million) of deferred debt issue costs.
The revolving syndicated credit facility allows the Company to borrow up to $830 million in either Canadian or U.S. currency from a group of banks on an unsecured basis. The facility is structured as a one-year committed revolving credit facility, extendible annually. In the event that the lenders do not consent to such extension, the revolving credit facility will convert to a three-year non-revolving amortizing term loan. Interest rates vary based on Canadian prime, Bankers’ Acceptance, U.S. LIBOR or U.S. base rate, depending on the borrowing option selected, credit ratings assigned by certain credit rating agencies to the Company’s rated senior unsecured debt and whether the Company borrows under the revolving or non-revolving condition.
The Company’s $100 million credit facility has substantially the same terms as the syndicated credit facility.
The 6.25 percent notes were issued June 14, 2002 and rank on equal footing with other unsecured indebtedness of the Company. The notes mature June 15, 2012 and are redeemable at the option of the Company at any time. Interest is payable semi-annually. The notes were issued under a base shelf prospectus dated June 6, 2002 filed with securities regulatory authorities in Canada and the United States. The prospectus permits Husky to offer for sale, from time to time, up to U.S. $1 billion of debt securities during the 25 months from June 6, 2002.
The 7.125 percent notes and the 7.55 percent debentures represent unsecured securities issued under a trust indenture dated October 31, 1996. These securities mature in 2006 and 2016, respectively. The 7.125 percent notes are not redeemable prior to maturity. The 7.55 percent debentures are redeemable, at the option of the Company, at any time and at a price determinable at the time of redemption. Interest is payable semi-annually.
The 8.45 percent senior secured bonds represent securities issued by a subsidiary under a trust indenture dated July 20, 1999. These securities amortize semi-annually with final maturity in 2012 and are redeemable prior to maturity under certain circumstances. Such securities were issued in connection with the financing of the Company’s share of the costs for the exploration and development of the Terra Nova oil field located off the East Coast of Canada. Interest is payable semi-annually. Although the Company commenced principal payments on August 1, 2001 ($8 million) it has the option of subsequently delaying the repayment schedule by one year. The Company, through a wholly owned partnership, owns 12.51 percent of the Terra Nova oil field and associated facilities. The repayment of the securities is contracted to be made solely from revenue from the Terra Nova oil field. There is also a charge created by the partnership on its interest in the assets of the Terra Nova oil field and associated facilities in favour of the security holders. In addition, certain financial obligations require letters of credit or cash equivalents as collateral.
The private placement notes were issued under two separate note agreements dated January 31, 2001 and have a weighted average interest rate of 6.86 percent. The notes are unsecured and redeemable at any time by the Company at a price determinable at the time of redemption. Interest is payable semi-annually or quarterly, depending on the particular note.
The medium-term notes Series B represent unsecured securities issued under a trust indenture dated February 3, 1997 and the Series D and E notes represent unsecured securities issued under a trust indenture dated May 4, 1999. The amounts, rates and maturities are as follows:
Issue | Amount | Interest Rate | Maturity Date | |||||||||
Series B | $ | 100 | 6.85 | % | February 2007 | |||||||
Series D | 200 | 6.30 | % | June 2004 | ||||||||
Series E | 200 | 6.95 | % | July 2009 | ||||||||
$ | 500 | |||||||||||
Interest is payable semi-annually on all series. The Series B and E notes are redeemable at any time at the option of the Company, at a price determinable at the time of redemption.
Aggregate maturities of long-term debt for the next five years are: 2004 — $259 million; 2005 — $60 million; 2006 — $226 million; 2007 — $126 million; and, 2008 — $20 million.
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Note 12 | Other Long-term Liabilities |
2003 | 2002 | 2001 | ||||||||||
Site restoration | $ | 303 | $ | 248 | $ | 211 | ||||||
Cross currency swaps | 41 | — | — | |||||||||
Interest rate swaps | 26 | — | — | |||||||||
Employee future benefits | 20 | 17 | 16 | |||||||||
Other | — | 1 | 1 | |||||||||
$ | 390 | $ | 266 | $ | 228 | |||||||
The Company has estimated future removal and site restoration costs of $851 million at December 31, 2003 (2002 — $703 million; 2001 — $653 million). During 2003 actual removal and site restoration expenditures amounted to $35 million (2002 — $17 million; 2001 — $18 million) and were included in capital expenditures.
Note 13 Income Taxes
The combined provision for income taxes in the Consolidated Statements of Earnings and Retained Earnings reflects an effective tax rate which differs from the expected statutory tax rate. Differences for the years ended December 31 were accounted for as follows:
2003 | 2002 | 2001 | |||||||||||
Earnings before income taxes | |||||||||||||
Canadian | $ | 1,572 | $ | 1,070 | $ | 1,067 | |||||||
Foreign jurisdictions | 223 | 154 | 7 | ||||||||||
1,795 | 1,224 | 1,074 | |||||||||||
Statutory income tax rate(percent) | 40.2 | 41.6 | 43.7 | ||||||||||
Expected income tax | 722 | 509 | 469 | ||||||||||
Effect on income tax of: | |||||||||||||
Change in statutory tax rate | (161 | ) | (31 | ) | (52 | ) | |||||||
Return on capital securities | 2 | (11 | ) | (18 | ) | ||||||||
Royalties, lease rentals and mineral taxes payable to the crown | 175 | 159 | 184 | ||||||||||
Resource allowance on Canadian production income | (183 | ) | (212 | ) | (219 | ) | |||||||
Non-deductible capital taxes | 22 | 18 | 20 | ||||||||||
Gains and losses on foreign exchange | (45 | ) | — | 20 | |||||||||
Rate benefit on timing of partnership earnings | (23 | ) | — | — | |||||||||
Foreign jurisdictions | (16 | ) | (13 | ) | — | ||||||||
Other — net | (17 | ) | (10 | ) | (2 | ) | |||||||
$ | 476 | $ | 409 | $ | 402 | ||||||||
Charged (credited) to: | |||||||||||||
Income tax expense | $ | 474 | $ | 420 | $ | 420 | |||||||
Retained earnings | 2 | (11 | ) | (18 | ) | ||||||||
$ | 476 | $ | 409 | $ | 402 | ||||||||
The future income tax liability at December 31 comprised the tax effect of temporary differences as follows:
2003 | 2002 | 2001 | |||||||||||
Future tax liabilities | |||||||||||||
Property, plant and equipment | $ | 2,261 | $ | 2,014 | $ | 1,882 | |||||||
Foreign exchange gains taxable on realization | 32 | — | — | ||||||||||
Timing of partnership items | 504 | 185 | — | ||||||||||
Other temporary differences | 2 | 30 | 7 | ||||||||||
2,799 | 2,229 | 1,889 | |||||||||||
Future tax assets | |||||||||||||
Loss carryforwards | 2 | 7 | 28 | ||||||||||
Foreign exchange losses deductible on realization | — | 28 | 26 | ||||||||||
Site restoration and other deferred credits | 112 | 105 | 93 | ||||||||||
Provincial royalty rebates | 52 | 48 | 46 | ||||||||||
Other temporary differences | 25 | 38 | 37 | ||||||||||
191 | 226 | 230 | |||||||||||
$ | 2,608 | $ | 2,003 | $ | 1,659 | ||||||||
Note 14 Commitments and Contingencies
Certain former owners of interests in the upgrading assets retained a 20-year upside financial interest expiring in 2014 which requires payments to them when the average differential between heavy crude oil feedstock and synthetic crude oil exceeds $6.50 per barrel. The calculation is based on
14
The Company has firm commitments for transportation services that require the payment of tariffs. The Company has sufficient production to utilize these transmission services.
At December 31, 2003, the Company had commitments for non-cancellable operating leases and other long-term agreements that require the following minimum future payments:
After | ||||||||||||||||||||||||||||
2004 | 2005 | 2006 | 2007 | 2008 | 2008 | Total | ||||||||||||||||||||||
Operating leases | $ | 50 | $ | 68 | $ | 76 | $ | 75 | $ | 70 | $ | 175 | $ | 514 | ||||||||||||||
Firm transportation agreements | 236 | 219 | 224 | 199 | 170 | 740 | 1,788 | |||||||||||||||||||||
Unconditional purchase obligations | 332 | 234 | 210 | 118 | 6 | 15 | 915 | |||||||||||||||||||||
Exploration lease agreements | 47 | 47 | 73 | 51 | 46 | 233 | 497 | |||||||||||||||||||||
Engineering and construction commitments | 391 | 206 | — | — | — | — | 597 | |||||||||||||||||||||
$ | 1,056 | $ | 774 | $ | 583 | $ | 443 | $ | 292 | $ | 1,163 | $ | 4,311 | |||||||||||||||
The Company is involved in various claims and litigation arising in the normal course of business. While the outcome of these matters is uncertain and there can be no assurance that such matters will be resolved in the Company’s favour, the Company does not currently believe that the outcome of adverse decisions in any pending or threatened proceedings related to these and other matters or any amount which it may be required to pay by reason thereof would have a material adverse impact on its financial position, results of operations or liquidity.
The Company has income tax filings that are subject to audit and potential reassessment. The findings may impact the tax liability of the Company. The final results are not reasonably determinable at this time and management believes that it has adequately provided for current and future income taxes.
Note 15 Capital Securities
The Company issued U.S. $225 million unsecured capital securities under an indenture dated August 10, 1998. Such securities rank junior to all senior debt and other financial debt of the Company. They yield an annual return of 8.9 percent, payable semi-annually until August 15, 2008 and mature in 2028. The capital securities are redeemable, in whole or in part, by the Company at any time prior to August 15, 2008 at a price determinable at the time of redemption. They are redeemable at par, in whole but not in part, by the Company on or after August 15, 2008. If not redeemed in whole, commencing on August 15, 2008, the annual return changes to a floating rate equal to U.S. LIBOR plus 5.50 percent payable semi-annually. The Company has the right at any time prior to maturity to defer payment of the return on the securities. Since the Company also has the unrestricted ability to settle its deferred return, principal and redemption obligations through the issuance of common or preferred shares, the principal amount of the capital securities, net of issue costs, has been classified as equity. The return amount, net of income taxes, is classified as a distribution of equity. Return on capital securities comprises the return and foreign exchange on the capital securities.
The amounts disclosed as capital securities and accrued return in shareholders’ equity at December 31 were as follows:
2003 | 2002 | 2001 | ||||||||||
Capital securities — U.S. $225 | $ | 291 | $ | 355 | $ | 358 | ||||||
Unamortized costs of issue | (3 | ) | (3 | ) | (3 | ) | ||||||
Accrued return | 10 | 12 | 12 | |||||||||
$ | 298 | $ | 364 | $ | 367 | |||||||
In November 2003 the AcSB revised recommendations in CICA section 3860, “Financial Instruments — Disclosure and Presentation”, on the classification of obligations that must or could be settled with an entity’s own equity instruments. The new recommendations will be effective January 1, 2005 and will result in the Company’s capital securities being classified as liabilities instead of equity. The accrued return on the capital securities and the issue costs would be classified outside of shareholders’ equity. The return on the capital securities would be a charge to earnings. The revision will be applied retroactively in 2005.
15
Note 16 Share Capital
The Company’s authorized share capital is as follows:
Common shares — an unlimited number of no par value.
Preferred shares — an unlimited number of no par value, none outstanding.
Changes to issued share capital were as follows:
Common Shares |
Number of Shares | Amount | |||||||
January 1, 2001 | 415,803,083 | $ | 3,388 | |||||
Options and warrants exercised | 1,075,010 | 9 | ||||||
December 31, 2001 | 416,878,093 | 3,397 | ||||||
Options and warrants exercised | 995,508 | 9 | ||||||
December 31, 2002 | 417,873,601 | 3,406 | ||||||
Options and warrants exercised | 4,302,141 | 51 | ||||||
December 31, 2003 | 422,175,742 | $ | 3,457 | |||||
Stock Options |
At December 31, 2003, 25.7 million common shares were reserved for issuance under the Company stock option plan. The exercise price of the option is equal to the average market price of the Company’s common shares during the five trading days prior to the date of the award. A downward adjustment of $0.82 to the exercise price of all outstanding stock options effective September 3, 2003 was made pursuant to the terms of the stock option plan under which the options were issued as a result of the special $1.00 per share dividend that was declared on July 23, 2003. Under the stock option plan the options awarded have a maximum term of five years and vest over three years on the basis of one-third per year.
The following options to purchase common shares have been awarded to directors, officers and certain other employees:
Weighted | ||||||||||||||||
Weighted | Average | |||||||||||||||
Number of | Average | Contractual | Options | |||||||||||||
Shares | Exercise Prices | Life | Exercisable | |||||||||||||
(thousands) | (years) | (thousands) | ||||||||||||||
January 1, 2001 | 9,761 | $ | 13.91 | 4 | 1,372 | |||||||||||
Granted | 664 | $ | 15.60 | 4 | ||||||||||||
Exercised | (656 | ) | $ | 13.99 | 3 | |||||||||||
Forfeited | (1,167 | ) | $ | 15.81 | 2 | |||||||||||
December 31, 2001 | 8,602 | $ | 13.78 | 4 | 2,853 | |||||||||||
Granted | 568 | $ | 16.11 | 5 | ||||||||||||
Exercised | (608 | ) | $ | 13.63 | 2 | |||||||||||
Forfeited | (642 | ) | $ | 14.37 | 3 | |||||||||||
December 31, 2002 | 7,920 | $ | 13.91 | 3 | 4,822 | |||||||||||
Granted | 591 | $ | 19.17 | 5 | ||||||||||||
Exercised | (3,789 | ) | $ | 13.45 | 2 | |||||||||||
Forfeited | (125 | ) | $ | 14.71 | 2 | |||||||||||
December 31, 2003 | 4,597 | $ | 13.88 | 2 | 3,564 | |||||||||||
At December 31, 2003, the options outstanding had exercise prices ranging from $10.34 to $22.01.
Warrants |
In 2000, the Company granted 1.4 million Renaissance Energy Ltd. (“Renaissance”) replacement options to purchase common shares of Husky in exchange for certain share purchase options to purchase common shares of Renaissance previously held by employees of Renaissance. The former shareholders of Husky Oil Limited were also granted warrants to acquire, for no additional consideration, 1.86 common shares of the Company for each common share issued on the exercise of a Renaissance replacement option. The warrants are exercisable only if and when the Renaissance replacement options are exercised and provide for the issue of a maximum of 2.5 million common shares. During 2003, 276,500 warrants were exercised (2002 — 208,500; 2001 — 226,000). As at December 31, 2003, there were 295,820 common shares remaining which could potentially be issued as a result of the exercise of these warrants. The Renaissance replacement options had a weighted average contractual life of 0.6 years.
16
Stock-based Compensation |
The fair values of all common share options granted are estimated on the date of grant using the Black-Scholes option-pricing model. The weighted average fair market value of options granted during the year and the assumptions used in their determination are as noted below:
2003 | 2002 | 2001 | ||||||||||
Weighted average fair market value per option | $ | 4.00 | $ | 5.19 | $ | 5.70 | ||||||
Risk-free interest rate(percent) | 3.9 | 3.6 | 3.5 | |||||||||
Volatility(percent) | 23 | 43 | 45 | |||||||||
Expected life(years) | 5 | 5 | 5 | |||||||||
Expected annual dividend per share | $ | 0.36 | $ | 0.36 | $ | 0.36 |
The fair values of all common share options granted prior to September 3, 2003 were revalued at the modification date using the Black-Scholes option-pricing model. The weighted average fair market value of outstanding stock options as at September 3, 2003 and the assumptions used in their determination are as noted below:
Weighted average fair market value per option | $ | 7.14 | ||
Risk-free interest rate(percent) | 2.8 | |||
Volatility(percent) | 20 | |||
Expected life(years) | 2.3 | |||
Expected annual divided per share | $ | 0.40 |
The Company follows the intrinsic value method of accounting for stock-based compensation for its stock option plan, under which compensation cost is not recognized. If the Company applied the fair value method, additional compensation cost of $3.9 million for all options granted would be recognized over the vesting period due to the modification of all options outstanding. For the year ended December 31, 2003, additional compensation cost of $3.6 million would be recognized.
If the Company applied the fair value method at the grant dates for options granted after January 1, 2002 and also to all options granted, the Company’s net earnings and earnings per share would have been as follows:
2003 | 2002 | 2001 | |||||||||||
Compensation cost — options granted after January 1, 2002(1) | $ | 5 | $ | — | $ | — | |||||||
Compensation cost — all options granted(1) | $ | 14 | $ | 13 | $ | 13 | |||||||
Net earnings available to common shareholders | |||||||||||||
As reported | $ | 1,357 | $ | 787 | $ | 620 | |||||||
Options granted after January 1, 2002 | $ | 1,352 | $ | 787 | $ | 620 | |||||||
All options granted | $ | 1,343 | $ | 774 | $ | 607 | |||||||
Weighted average number of common shares outstanding(millions) | |||||||||||||
Basic | 419.5 | 417.4 | 416.1 | ||||||||||
Diluted | 421.5 | 419.3 | 418.6 | ||||||||||
Basic earnings per share | |||||||||||||
As reported | $ | 3.23 | $ | 1.88 | $ | 1.49 | |||||||
Options granted after January 1, 2002 | $ | 3.22 | $ | 1.88 | $ | 1.49 | |||||||
All options granted | $ | 3.20 | $ | 1.86 | $ | 1.46 | |||||||
Diluted earnings per share | |||||||||||||
As reported | $ | 3.22 | $ | 1.88 | $ | 1.48 | |||||||
Options granted after January 1, 2002 | $ | 3.21 | $ | 1.88 | $ | 1.48 | |||||||
All options granted | $ | 3.18 | $ | 1.85 | $ | 1.45 |
(1) | Includes options modified. |
Effective January 1, 2004 the Company is required to measure stock-based compensation and recognize an expense in the financial statements. The Company will be adopting the change in 2004 on a retroactive basis without restatement of prior periods for all options granted. Retained earnings will be decreased by $44 million, which includes a cost of $4 million for the year ended December 31, 2000.
Earnings Per Share Amounts |
The calculation of basic earnings per common share is based on net earnings after deducting return on capital securities, net of applicable income taxes, divided by the weighted average number of common shares outstanding.
Diluted earnings per common share includes the dilutive impact of options and warrants outstanding under the Company stock option plan calculated using the treasury stock method. Shares potentially issuable on the settlement of the capital securities have not been included in the determination of diluted earnings per common share, as the Company has neither the obligation nor intention to settle amounts due through the issuance of shares.
During 2003 the Company declared dividends of $1.38 per common share (2002 and 2001 — $0.36 per common share), including a special dividend of $1.00 per common share.
17
Note 17 Employee Future Benefits
The Company currently provides a defined contribution pension plan for all qualified employees. The Company also maintains a defined benefit pension plan, which is closed to new entrants, and all current participants are vested. The Company also provides certain health and dental coverage to its retirees which is accrued over the expected average remaining service life of the employees.
Weighted average long-term assumptions used for the defined benefit pension plan and the post-retirement health and dental care plan were as follows:
2003 | 2002 | 2001 | ||||||||||
(percent) | ||||||||||||
Discount rate | 6.0 | 6.3 | 7.3 | |||||||||
Long-term rate of increase in compensation levels(percent) | 5.0 | 5.0 | 5.0 | |||||||||
Long-term rate of return on plan assets(percent) | 8.0 | 8.0 | 8.0 |
The average health care cost trend used was eight percent, which is reduced by 0.50 percent until 2009. The average dental care cost trend used was four percent, which remains constant.
Defined Benefit Pension Plan |
The status of the defined benefit pension plan at December 31 was as follows:
Benefit Obligation | 2003 | 2002 | 2001 | |||||||||
Benefit obligation, beginning of year | $ | 108 | $ | 95 | $ | 93 | ||||||
Current service cost | 2 | 2 | 1 | |||||||||
Interest cost | 7 | 7 | 6 | |||||||||
Benefits paid | (6 | ) | (6 | ) | (5 | ) | ||||||
Actuarial losses | 7 | 10 | — | |||||||||
Benefit obligation, end of year | $ | 118 | $ | 108 | $ | 95 | ||||||
Fair Value of Plan Assets | 2003 | 2002 | 2001 | |||||||||
Fair value of plan assets, beginning of year | $ | 77 | $ | 85 | $ | 90 | ||||||
Contributions | 8 | 2 | 2 | |||||||||
Benefits paid | (6 | ) | (6 | ) | (5 | ) | ||||||
Return on plan assets | 6 | 7 | 6 | |||||||||
Gain (loss) on plan assets | 2 | (11 | ) | (8 | ) | |||||||
Foreign exchange losses | (2 | ) | — | — | ||||||||
Fair value of plan assets, end of year | $ | 85 | $ | 77 | $ | 85 | ||||||
Funded Status of Plan | 2003 | 2002 | 2001 | |||||||||
Fair value of plan assets | $ | 85 | $ | 77 | $ | 85 | ||||||
Benefit obligation | (118 | ) | (108 | ) | (95 | ) | ||||||
Excess assets (obligation) | (33 | ) | (31 | ) | (10 | ) | ||||||
Unrecognized past service costs | 1 | 1 | — | |||||||||
Unrecognized losses | 32 | 27 | 6 | |||||||||
Accrued benefit liability | $ | — | $ | (3 | ) | $ | (4 | ) | ||||
The composition of the defined benefit pension plan’s assets at year-end 2003 was U.S. common equities 15 percent, Canadian common equities 27 percent, Canadian mutual funds 12 percent, Canadian government bonds 33 percent and Canadian corporate bonds 13 percent.
During 2003 Husky contributed $8 million to the defined benefit pension plan’s assets, $6 million of which was in respect of additional contributions as a result of the plan’s deficiency. Husky currently plans to contribute a similar amount in 2004.
18
Post-retirement Health and Dental Care Plan |
The status of the post-retirement health and dental care plan at December 31 was as follows:
Benefit Obligation | 2003 | 2002 | 2001 | |||||||||
Benefit obligation, beginning of year | $ | 21 | $ | 16 | $ | 14 | ||||||
Current service cost | 2 | 1 | 1 | |||||||||
Interest cost | 1 | 1 | 1 | |||||||||
Benefits paid | (1 | ) | — | — | ||||||||
Actuarial losses | — | 3 | — | |||||||||
Benefit obligation, end of year | $ | 23 | $ | 21 | $ | 16 | ||||||
Funded Status of Plan | 2003 | 2002 | 2001 | |||||||||
Benefit obligation | $ | (23 | ) | $ | (21 | ) | $ | (16 | ) | |||
Unrecognized losses | 3 | 4 | — | |||||||||
Accrued benefit liability | $ | (20 | ) | $ | (17 | ) | $ | (16 | ) | |||
The assumed health care cost trend can have a significant effect on the amounts reported for Husky’s post-retirement health and dental care plan. A one percent increase and decrease in the assumed trend rate would have the following effect:
1% Increase | 1% Decrease | |||||||
Effect on total service and interest cost components | $ | 1 | $ | — | ||||
Effect on post-retirement benefit obligation | $ | 4 | $ | (3 | ) |
Pension Expense and Post-retirement Health and Dental Care Expense |
The expenses for the years ended December 31 were as follows:
Pension Expense | 2003 | 2002 | 2001 | ||||||||||
Defined benefit pension plan | |||||||||||||
Employer current service cost | $ | 2 | $ | 2 | $ | 1 | |||||||
Interest cost | 7 | 7 | 6 | ||||||||||
Expected return on plan assets | (6 | ) | (7 | ) | (6 | ) | |||||||
Amortization of net actuarial losses | 2 | — | — | ||||||||||
5 | 2 | 1 | |||||||||||
Defined contribution pension plan | 11 | 10 | 8 | ||||||||||
Total expense | $ | 16 | $ | 12 | $ | 9 | |||||||
Post-retirement Health and Dental Care Expense | 2003 | 2002 | 2001 | |||||||||
Employer current service cost | $ | 2 | $ | 1 | $ | 1 | ||||||
Interest cost | 1 | 1 | 1 | |||||||||
Total expense | $ | 3 | $ | 2 | $ | 2 | ||||||
Note 18 Related Party Transactions
Husky, in the ordinary course of business, entered into a lease for an eight-year term effective September 1, 2000 with Western Canadian Place Ltd. The terms of the lease provide for the lease of office space, management services and operating costs at commercial rates. Western Canadian Place Ltd. is indirectly controlled by Husky’s principal shareholders. During 2003 Husky paid approximately $17 million for office space in Western Canadian Place.
Husky did not have any customers that constituted more than five percent of total sales and operating revenues during 2003.
Note 19 Financial Instruments and Risk Management
Carrying Values and Estimated Fair Values of Financial Assets and Liabilities |
The carrying value of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximates their fair value due to the short-term maturity of these instruments. The estimated fair value of the long-term debt at December 31 was as follows:
2003 | 2002 | 2001 | ||||||||||||||||||||||
Carrying | Fair | Carrying | Fair | Carrying | Fair | |||||||||||||||||||
Value | Value | Value | Value | Value | Value | |||||||||||||||||||
Long-term debt | $ | 1,698 | $ | 1,869 | $ | 2,385 | $ | 2,579 | $ | 2,092 | $ | 2,143 |
19
The fair value of the long-term debt is the present value of future cash flows associated with the debt. Market information such as treasury rates and credit spreads is used to determine the appropriate discount rates.
Unrecognized Gains (Losses) on Derivative Instruments |
2003 | 2002 | 2001 | |||||||||||
Commodity price risk management | |||||||||||||
Natural gas | $ | (8 | ) | $ | (4 | ) | $ | 15 | |||||
Crude oil | (109 | ) | 6 | — | |||||||||
Power consumption | 2 | — | — | ||||||||||
Interest rate risk management | |||||||||||||
Interest rate swaps | 31 | 86 | 4 | ||||||||||
Foreign currency risk management | |||||||||||||
Foreign exchange contracts | (19 | ) | (7 | ) | (29 | ) | |||||||
Foreign exchange forwards | 15 | (5 | ) | — |
Commodity Price Risk Management |
Natural Gas |
At December 31, 2003 the Company had hedged 70 mmcf of natural gas per day at NYMEX for February and March 2004 at an average price of U.S. $6.69 per mmbtu and 20 mmcf of natural gas per day at NYMEX for April 2004 at an average price of U.S. $6.38 per mmbtu. During 2003 the impact of the 2003 hedge program was a gain of $24 million.
At December 31, 2003 the Company had also hedged 7.5 mmcf of natural gas per day at NYMEX for the years 2004 and 2005 at an average price of U.S. $1.92 per mcf. During 2003 the impact was a loss of $8 million (2002 and 2001 — insignificant).
Crude Oil |
At December 31, 2003 the Company had hedged crude oil averaging 85,000 bbls per day from January to December 2004 at an average fixed WTI price of U.S. $27.46 per bbl. The impact of the hedge program for 2003 was a loss of $36 million (2002 — gain of $5 million).
Power Consumption |
In 2003 the Company hedged power consumption of 329,400 MWh from January to December 2004 at an average fixed price of $46.72 per MWh.
Natural Gas Contracts |
The Company has a portfolio of fixed and basis price offsetting physical forward purchase and sale natural gas contracts. The objective of these contracts is to “lock in” a positive spread between the physical purchase and sale contract prices. At December 31, 2003 the Company had the following offsetting physical purchase and sale contracts:
Volumes | Unrecognized | |||||||
(mmcf) | Gain (Loss) | |||||||
Physical purchase contracts | 16,971 | $ | — | |||||
Physical sale contracts | (16,971 | ) | $ | 2 |
Interest Rate Risk Management |
The majority of the Company’s long-term debt has fixed interest rates and various maturities. The Company periodically uses interest rate swaps to manage its financing costs. At December 31, 2003 the Company had entered into interest rate swap arrangements whereby the fixed interest rate coupon on certain debt was swapped to floating rates with the following terms:
Debt | Amount | Swap Maturity | Swap Rate | |||||
(percent) | ||||||||
6.95% medium-term notes | $200 | July 14, 2009 | CDOR + 175 bps | |||||
7.55% debentures | U.S. $200 | November 15, 2011 | U.S. LIBOR + 194 bps |
During 2003 the Company realized a gain of $17 million (2002 — gain of $29 million; 2001 — gain of $2 million) from interest rate risk management activities.
In 2003, the Company unwound three interest rate swaps. Proceeds of $44 million have been deferred and are being amortized to income over the remaining term of the debt.
Foreign Currency Risk Management |
The Company manages its exposure to foreign exchange rate fluctuations by balancing the U.S. dollar denominated cash flows from operations with U.S. dollar denominated borrowings and other financial instruments. Husky utilizes spot and forward sales to convert cash flows to or from U.S. or Canadian currency.
20
At December 31, 2003 the Company had the following cross currency debt swaps:
Canadian | ||||||||||||||
Debt | Swap Amount | Equivalent | Swap Maturity | Interest Rate | ||||||||||
(percent) | ||||||||||||||
7.125% notes | U.S. $ | 150 | $ | 218 | November 15, 2006 | 8.74 | ||||||||
6.25% notes | U.S. $ | 150 | $ | 212 | June 15, 2012 | 7.41 |
The Company hedged U.S. dollar revenues for various amounts and maturities through 2005 through the use of foreign exchange forwards. The total amount hedged using long-dated forwards at December 31, 2003 was U.S. $52 million at an average forward rate of $1.5625. The total amount hedged using short-dated forwards at December 31, 2003 was U.S. $70 million at an average forward rate of $1.3166.
During 2003 the Company realized a loss of $56 million (2002 — loss of $11 million; 2001 — loss of $4 million) from foreign currency risk management activities.
Credit Risk |
Accounts receivable are predominantly with customers in the energy industry and are subject to normal industry credit risks. In addition, the Company is exposed to credit related losses in the event of non-performance by counterparties to its financial instruments. The Company primarily deals with major financial institutions and investment grade rated entities to mitigate these risks.
Note 20 | Reconciliation to Accounting Principles Generally Accepted in the United States |
The Company’s consolidated financial statements have been prepared in accordance with GAAP in Canada, which differ in some respects from those in the United States. Any differences in accounting principles as they pertain to the accompanying consolidated financial statements were insignificant except as described below:
Consolidated Statements of Earnings
2003 | 2002 | 2001 | |||||||||||
Net earnings | $ | 1,321 | $ | 804 | $ | 654 | |||||||
Adjustments: | |||||||||||||
Full cost accounting(a) | 80 | 88 | (544 | ) | |||||||||
Related income taxes | (30 | ) | (37 | ) | 235 | ||||||||
Foreign currency translation on capital securities(b) | 67 | 3 | (20 | ) | |||||||||
Related income taxes | (12 | ) | (1 | ) | 5 | ||||||||
Return on capital securities(b) | (29 | ) | (32 | ) | (33 | ) | |||||||
Related income taxes | 11 | 11 | 14 | ||||||||||
Derivatives and hedging(c) | (1 | ) | 22 | (30 | ) | ||||||||
Related income taxes | 1 | (9 | ) | 12 | |||||||||
Gain (loss) on energy trading contracts(c) | (15 | ) | (2 | ) | 20 | ||||||||
Related income taxes | 6 | 1 | (8 | ) | |||||||||
Asset retirement obligations(d) | 15 | — | — | ||||||||||
Related income taxes | (2 | ) | — | — | |||||||||
Stock-based compensation(e) | (46 | ) | — | — | |||||||||
Accounting for income taxes(f) | — | (37 | ) | (14 | ) | ||||||||
Earnings before cumulative effect of change in accounting principle under U.S. GAAP | 1,366 | 811 | 291 | ||||||||||
Cumulative effect of change in accounting principle, net of tax(c)(d) | 9 | — | 6 | ||||||||||
Net earnings under U.S. GAAP | $ | 1,375 | $ | 811 | $ | 297 | |||||||
Weighted average number of common shares outstanding under U.S. GAAP(millions) | |||||||||||||
Basic | 419.5 | 417.4 | 416.1 | ||||||||||
Diluted | 421.5 | 419.3 | 418.6 | ||||||||||
Earnings per share before cumulative effect of change in accounting principle under U.S. GAAP | |||||||||||||
Basic | $ | 3.26 | $ | 1.94 | $ | 0.70 | |||||||
Diluted | $ | 3.24 | $ | 1.93 | $ | 0.70 | |||||||
Earnings per share under U.S. GAAP | |||||||||||||
Basic | $ | 3.28 | $ | 1.94 | $ | 0.71 | |||||||
Diluted | $ | 3.26 | $ | 1.93 | $ | 0.71 |
21
Condensed Consolidated Balance Sheets
2003 | 2002 | 2001 | |||||||||||||||||||||||
Canadian | U.S. | Canadian | U.S. | Canadian | U.S. | ||||||||||||||||||||
GAAP | GAAP | GAAP | GAAP | GAAP | GAAP | ||||||||||||||||||||
Current assets(c) | $ | 865 | $ | 924 | $ | 1,144 | $ | 1,292 | $ | 626 | $ | 756 | |||||||||||||
Property, plant and equipment, net(a)(d) | 10,685 | 10,251 | 9,347 | 8,670 | 8,715 | 7,950 | |||||||||||||||||||
Other assets(c)(j) | 232 | 236 | 84 | 89 | 29 | 33 | |||||||||||||||||||
$ | 11,782 | $ | 11,411 | $ | 10,575 | $ | 10,051 | $ | 9,370 | $ | 8,739 | ||||||||||||||
Current liabilities(b)(c)(j) | $ | 1,456 | $ | 1,635 | $ | 1,215 | $ | 1,301 | $ | 1,049 | $ | 1,187 | |||||||||||||
Long-term debt(b)(c) | 1,439 | 1,761 | 1,964 | 2,406 | 1,948 | 2,306 | |||||||||||||||||||
Other long-term liabilities(d) | 390 | 519 | 266 | 266 | 228 | 228 | |||||||||||||||||||
Future income taxes(a)(b)(c)(d)(f)(j) | 2,608 | 2,372 | 2,003 | 1,772 | 1,659 | 1,361 | |||||||||||||||||||
Capital securities and accrued return(b) | 298 | — | 364 | — | 367 | — | |||||||||||||||||||
Share capital and contributed surplus(g)(h) | 3,457 | 3,737 | 3,406 | 3,640 | 3,397 | 3,631 | |||||||||||||||||||
Retained earnings | 2,134 | 1,478 | 1,357 | 683 | 722 | 23 | |||||||||||||||||||
Accumulated other comprehensive income | |||||||||||||||||||||||||
Cash flow hedges, net of tax(c) | — | (76 | ) | — | (7 | ) | — | 3 | |||||||||||||||||
Minimum pension liability, net of tax(j) | — | (15 | ) | — | (10 | ) | — | — | |||||||||||||||||
$ | 11,782 | $ | 11,411 | $ | 10,575 | $ | 10,051 | $ | 9,370 | $ | 8,739 | ||||||||||||||
Condensed Consolidated Statements of Retained Earnings (Deficit) and
2003 | 2002 | 2001 | ||||||||||||||||||||||
Canadian | U.S. | Canadian | U.S. | Canadian | U.S. | |||||||||||||||||||
GAAP | GAAP | GAAP | GAAP | GAAP | GAAP | |||||||||||||||||||
Retained earnings (deficit), beginning of year | $ | 1,357 | $ | 683 | $ | 722 | $ | 23 | $ | 253 | $ | (124 | ) | |||||||||||
Net earnings | 1,321 | 1,375 | 804 | 811 | 654 | 297 | ||||||||||||||||||
Dividends on common shares | (580 | ) | (580 | ) | (151 | ) | (151 | ) | (150 | ) | (150 | ) | ||||||||||||
Capital securities, net of tax and foreign exchange(b) | 36 | — | (18 | ) | — | (35 | ) | — | ||||||||||||||||
Retained earnings, end of year | $ | 2,134 | $ | 1,478 | $ | 1,357 | $ | 683 | $ | 722 | $ | 23 | ||||||||||||
Accumulated other comprehensive income, beginning of year | $ | — | $ | (17 | ) | $ | — | $ | 3 | $ | — | $ | — | |||||||||||
Cumulative effect of change in accounting, net of tax(c) | — | — | — | — | — | (10 | ) | |||||||||||||||||
Cash flow hedges, net of tax(c) | — | (69 | ) | — | (10 | ) | — | 13 | ||||||||||||||||
Minimum pension liability, net of tax(j) | — | (5 | ) | — | (10 | ) | — | — | ||||||||||||||||
Accumulated other comprehensive income, end of year | $ | — | $ | (91 | ) | $ | — | $ | (17 | ) | $ | — | $ | 3 | ||||||||||
Condensed Consolidated Statements of Earnings and Comprehensive Income
2003 | 2002 | 2001 | ||||||||||||||||||||||
Canadian | U.S. | Canadian | U.S. | Canadian | U.S. | |||||||||||||||||||
GAAP | GAAP | GAAP | GAAP | GAAP | GAAP | |||||||||||||||||||
Sales and operating revenues(c)(i) | $ | 7,658 | $ | 6,943 | $ | 6,384 | $ | 5,778 | $ | 6,596 | $ | 5,606 | ||||||||||||
Costs and expenses(b)(c)(e)(i) | 4,732 | 4,012 | 4,117 | 3,488 | 4,614 | 3,654 | ||||||||||||||||||
Accretion expense(d) | — | 22 | — | — | — | — | ||||||||||||||||||
Depletion, depreciation and amortization(a)(d) | 1,058 | 941 | 939 | 851 | 807 | 1,351 | ||||||||||||||||||
Interest — net(b) | 73 | 102 | 104 | 136 | 101 | 134 | ||||||||||||||||||
Earnings before income taxes | 1,795 | 1,866 | 1,224 | 1,303 | 1,074 | 467 | ||||||||||||||||||
Income taxes(a)(b)(c)(d)(f) | 474 | 500 | 420 | 492 | 420 | 176 | ||||||||||||||||||
Earnings before cumulative effect of change in accounting principle | 1,321 | 1,366 | 804 | 811 | 654 | 291 | ||||||||||||||||||
Cumulative effect of change in accounting principle, net of tax(c)(d) | — | 9 | — | — | — | 6 | ||||||||||||||||||
Net earnings | 1,321 | 1,375 | 804 | 811 | 654 | 297 | ||||||||||||||||||
Other comprehensive income(c)(j) | — | 74 | — | 20 | — | (3 | ) | |||||||||||||||||
Comprehensive income | $ | 1,321 | $ | 1,449 | $ | 804 | $ | 831 | $ | 654 | $ | 294 | ||||||||||||
22
Condensed Consolidated Statements of Cash Flows
2003 | 2002 | 2001 | |||||||||||
Cash flow — operating activities — Canadian GAAP | $ | 2,572 | $ | 1,892 | $ | 1,930 | |||||||
Adjustments | |||||||||||||
Return on capital securities payment | (29 | ) | (31 | ) | (30 | ) | |||||||
Settlement of asset retirement liabilities | (34 | ) | — | — | |||||||||
Cash flow — operating activities — U.S. GAAP | 2,509 | 1,861 | 1,900 | ||||||||||
Cash flow — financing activities — Canadian GAAP | (800 | ) | 3 | (423 | ) | ||||||||
Adjustments | |||||||||||||
Return on capital securities payment | 29 | 31 | 30 | ||||||||||
Cash flow — financing activities — U.S. GAAP | (771 | ) | 34 | (393 | ) | ||||||||
Cash flow — investing activities — Canadian GAAP | (2,075 | ) | (1,589 | ) | (1,507 | ) | |||||||
Adjustments | |||||||||||||
Settlement of asset retirement liabilities | 34 | — | — | ||||||||||
Cash flow — investing activities — U.S. GAAP | (2,041 | ) | (1,589 | ) | (1,507 | ) | |||||||
Change in cash and cash equivalents | $ | (303 | ) | $ | 306 | $ | — | ||||||
The increases or decreases noted above refer to the following differences between U.S. GAAP and Canadian GAAP:
(a) | The Company performs a cost recovery ceiling test for each cost centre which limits net capitalized costs to the undiscounted estimated future net revenue from proved oil and gas reserves plus the cost of unproved properties and major development projects less impairment, using year-end prices or average prices in that year if appropriate. In addition, the aggregate value of all cost centres is further limited by including financing costs, administration expenses, future removal and site restoration costs and income taxes. Under U.S. GAAP, companies using the full cost method of accounting for oil and gas producing activities perform a ceiling test on each cost centre using discounted estimated future net revenue from proved oil and gas reserves using a discount factor of 10 percent. Prices used in the U.S. GAAP ceiling tests performed for this reconciliation were those in effect at the applicable year-end. Financing and administration costs are excluded from the calculation under U.S. GAAP. At December 31, 2001 the Company recognized a U.S. GAAP ceiling test write down of $334 million after tax. | |
(b) | The Company records the capital securities as a component of equity and the return and foreign exchange gains or losses thereon as a charge to retained earnings. Under U.S. GAAP, the capital securities, the accrued return thereon and costs of issue would be classified outside of shareholders’ equity and the related return and foreign exchange gains or losses would be charged to earnings. See note 15, Capital Securities. | |
(c) | Effective January 1, 2001, the Company adopted the provisions of FAS 133, “Accounting for Derivative Instruments and Hedging Activities”. On initial adoption of FAS 133, the Company recorded additional assets and liabilities of $20 million and $10 million, respectively, and recorded a resulting cumulative effect of change in accounting principle to increase earnings by $6 million, net of tax, for the fair value of derivatives which did not qualify as hedges on January 1, 2001. The Company also recorded assets and liabilities of $4 million and $23 million, respectively, and a resulting reduction of other comprehensive income within shareholders’ equity of $10 million, net of tax, for the fair value of derivatives designated as hedges against variability in future cash flows from the sale of natural gas. An additional asset of $7 million for the fair value of derivatives designated as hedges against changes in the fair value of certain firm commitments and an offsetting liability for the difference between carrying and fair values of the hedged items was also recorded. The cumulative effect of change in accounting principle increased earnings per share under U.S. GAAP by $0.01 (basic and diluted). |
At December 31, 2003 the Company recorded additional assets and liabilities for U.S. GAAP purposes of $52 million (2002 — $111 million; 2001 — $22 million) and $172 million (2002 — $122 million; 2001 — $38 million), respectively, for the fair values of derivative financial instruments. During 2003, a gain of $1 million, net of tax (2002 — gain of $11 million; 2001 — insignificant), was included in income for U.S. GAAP purposes for unrealized gains on foreign currency derivatives and natural gas basis swaps that did not qualify for hedge accounting under FAS 133. The Company also recorded a loss of $2 million, net of tax (2002 and 2001 — gain of $1 million), in revenue for U.S. GAAP purposes with respect to derivatives designated as hedges of change in the fair value of certain fixed price commodity contracts and offsetting changes in the fair value of those contracts. In addition, the amount included in other comprehensive income was adjusted by a $69 million loss, net of tax (2002 — gain of $10 million; 2001 — loss of $13 million), for changes in the fair values of the derivatives designated as hedges of cash flows relating to commodity price risk, foreign exchange derivatives and the transfer to income of amounts applicable to cash flows occurring in 2003.
Under U.S. GAAP, energy trading contracts entered into and physical energy trading inventories purchased on or before October 26, 2002 have been recorded at fair value. These contracts include derivatives as well as energy trading contracts that do not meet the definition of derivatives. Effective October 26, 2002, non-derivative energy trading contracts and inventories purchased after the effective date are no longer recorded at fair value in accordance with Emerging Issues Task Force 02-03 “Issues Involved in Accounting for Derivative Contracts held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities”. Under Canadian GAAP, the impact of energy trading contracts is recorded as they settle. Under U.S. GAAP, at December 31, 2003 the Company recorded additional assets and liabilities of $7 million (2002 — $37 million; 2001 — $114 million) and $5 million (2002 — $19 million; 2001 — $88 million), respectively, and included the resulting unrealized loss, net of tax, in earnings for the year of $9 million (2002 — loss of $1 million; 2001 — gain of $11 million).
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Under U.S. GAAP, gains and losses on energy trading contracts have been netted against sales and operating revenues.
(d) | In 2003, the Company adopted FAS 143, “Accounting for Asset Retirement Obligations”, which requires the fair value of a liability for an asset retirement obligation to be recorded in the period in which it is incurred and a corresponding increase in the carrying amount of the related tangible long-lived asset. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and normal use of the asset. The liability is accreted at the end of each period through charges to accretion expense. The change was effective January 1, 2003, and the related cumulative effect of change in accounting principle to net earnings to December 31, 2002 was an increase of $9 million ($20 million before income taxes) or $0.02 per share (diluted). At January 1, 2003, the change resulted in an increase to net property, plant and equipment of $58 million, an increase in the asset retirement obligations which are included in other long-term liabilities of $38 million, an increase to the future income tax liability of $11 million and an increase to retained earnings of $9 million. The application of FAS 143 did not have a material impact on the Company’s depreciation, depletion and amortization rate. There was no impact on the Company’s cash flow as a result of adopting FAS 143. |
The following table provides changes to asset retirement obligations for the year ended December 31, 2003:
Asset retirement obligations, January 1, 2003 | $ | 286 | ||
Liabilities incurred during year | 17 | |||
Acquisition of Marathon Canada | 38 | |||
Divestitures | (5 | ) | ||
Revision of previous estimate | 108 | |||
Liabilities settled during year | (34 | ) | ||
Accretion expense | 22 | |||
Asset retirement obligations, December 31, 2003 | $ | 432 | ||
The following table shows the effect on the Company’s net earnings and earnings per share as if FAS 143 had been in effect in prior years. There was a $10 million increase to net earnings for each of the years ended December 31, 2002 and 2001.
As at and for | ||||||||||
the years ended | ||||||||||
December 31 | ||||||||||
2002 | 2001 | |||||||||
As reported | ||||||||||
Net earnings under U.S. GAAP | $ | 811 | $ | 297 | ||||||
Earnings per share under U.S. GAAP | ||||||||||
Basic | $ | 1.94 | $ | 0.71 | ||||||
Diluted | $ | 1.93 | $ | 0.71 | ||||||
Pro forma | ||||||||||
Net earnings under U.S. GAAP | $ | 821 | $ | 307 | ||||||
Earnings per share under U.S. GAAP | ||||||||||
Basic | $ | 1.97 | $ | 0.74 | ||||||
Diluted | $ | 1.96 | $ | 0.73 | ||||||
Asset retirement obligations | ||||||||||
Beginning of year | $ | 269 | $ | 255 | ||||||
End of year | $ | 286 | $ | 269 |
(e) | On September 3, 2003 the Company modified the exercise price of all outstanding options. Under U.S. GAAP these options must be accounted for using variable accounting where the in-the-money portion of the vested stock options outstanding is required to be adjusted through the statement of earnings as compensation expense over the remaining vesting period. The amount of stock-based compensation expense charged to earnings for the year ended December 31, 2003 was $46 million. The compensation expense will be revalued at each reporting date based on the share price and the number of vested stock options outstanding. |
(f) | The liability method under Canadian GAAP requires the measurement of future income tax liabilities and assets using income tax rates that reflect enacted income tax rate reductions provided it is more likely than not that the Company will be eligible for such rate reductions in the period of reversal. U.S. GAAP allows recording of such rate reductions only when claimed. |
(g) | As a result of the reorganization of the capital structure which occurred in 2000, the deficit of Husky Oil Limited of $160 million was eliminated. Elimination of the deficit would not be permitted under U.S. GAAP. | |
(h) | The Company recorded interest waived on subordinated shareholders’ loans and dividends waived on Class C shares as a reduction of ownership charges. Under U.S. GAAP, waived interest and dividends in those years would be recorded as interest on subordinated shareholders’ loans and dividends on Class C shares and as capital contributions. |
(i) | Under U.S. GAAP, transportation costs are included in cost of sales rather than netted against sales and operating revenues. Transportation costs for 2003 were $232 million (2002 — $256 million; 2001 — $272 million). | |
(j) | The Company amortizes the portion of the unrecognized gains or losses that exceed 10 percent of the greater of the projected benefit obligation or the market-related value of pension plan assets. The market-related value of the pension plan assets is either the fair value or a calculated value that recognizes changes in fair value over not more than five years. Under U.S. GAAP, an additional minimum liability |
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is recognized if the unfunded accumulated benefit obligation exceeds the unfunded pension cost already recognized. If an additional minimum liability is recognized, an amount equal to the unrecognized prior service cost is recognized as an intangible asset and any excess is reported in other comprehensive income. At December 31, 2003 the additional minimum liability was increased by $6 million (2002 — $19 million) with a decrease to other comprehensive income of $5 million (2002 — decrease of $10 million), net of tax. |
Additional U.S. GAAP Disclosures
Acquisition of Marathon Canada |
As described in note 7, Acquisition of Marathon Canada, the Company purchased all of the outstanding shares of Marathon Canada Limited and the Western Canadian assets of Marathon International Petroleum Canada, Ltd. This transaction increased the reserve base and created cost efficiencies, increasing shareholder value.
FAS 133 |
Effective January 1, 2001, the Company adopted the provisions of FAS 133, which require that all derivatives be recognized as assets and liabilities on the balance sheet and measured at fair value. Gains or losses, including unrealized amounts, on derivatives that have not been designated as hedges, or were not effective as hedges, are included in earnings as they arise.
For derivatives designated as fair value hedges, changes in the fair value are recognized in earnings together with equal or lesser amounts of changes in the fair value of the hedged item. During 2003, no amount of the gains or losses on these derivatives was excluded from the assessment of hedge effectiveness in these hedging relationships.
For derivatives designated as cash flow hedges, changes in the fair value of the derivatives are recognized in other comprehensive income until the hedged items are recognized in earnings. Any portion of the change in the fair value of the derivatives that is not effective in hedging the changes in future cash flows is included in earnings. The amount related to the hedge of commodity price risk was included in other comprehensive income at December 31, 2003. During 2003, no amounts were excluded from the assessment of effectiveness of the cash flow hedges.
Stock Option Plan |
FAS 123, “Accounting for Stock-based Compensation”, establishes financial accounting and reporting standards for stock-based employee compensation plans as well as transactions in which an entity issues its equity instruments to acquire goods or services from non-employees. As permitted by FAS 123, Husky has elected to follow the intrinsic value method of accounting for stock-based compensation arrangements, as provided for in Accounting Principles Board Opinion 25. Since all options were granted with exercise prices equal to the market price, no compensation expense has been charged to income at the time of the option grants. On September 3, 2003 the Company modified the exercise price of all outstanding options, resulting in the use of variable accounting for these modified stock options. The compensation expense recorded under variable accounting has been removed from the pro forma amounts indicated below. Had compensation cost for Husky’s stock options been determined based on the fair market value at the grant dates of the awards, and amortized on a straight-line basis, consistent with methodology prescribed by FAS 123, Husky’s net earnings and earnings per share for the years ended December 31, 2003, 2002 and 2001 would have been the pro forma amounts indicated below:
2003 | 2002 | 2001 | |||||||||||||||||||||||
As | Pro | As | Pro | As | Pro | ||||||||||||||||||||
Reported | Forma | Reported | Forma | Reported | Forma | ||||||||||||||||||||
Net earnings | $ | 1,375 | $ | 1,407 | $ | 811 | $ | 798 | $ | 297 | $ | 284 | |||||||||||||
Earnings per share | |||||||||||||||||||||||||
— Basic | $ | 3.28 | $ | 3.35 | $ | 1.94 | $ | 1.91 | $ | 0.71 | $ | 0.68 | |||||||||||||
— Diluted | $ | 3.26 | $ | 3.34 | $ | 1.93 | $ | 1.90 | $ | 0.71 | $ | 0.68 |
The fair values of all common share options granted are estimated on the date of grant using the Black-Scholes option-pricing model. The weighted average fair market value of options granted during the year and the assumptions used in their determination are the same as described in note 16.
Depletion, Depreciation and Amortization |
Upstream depletion, depreciation and amortization, per gross equivalent barrel is calculated by converting natural gas volumes to a barrel of oil equivalent (“boe”) using the ratio of 6 mcf of natural gas to 1 barrel of crude oil (sulphur volumes have been excluded from the calculation). Depletion, depreciation and amortization per boe as calculated under U.S. GAAP for the years ended December 31 were as follows:
2003 | 2002 | 2001 | ||||||||||
Depletion, depreciation and amortization per boe(1) | $ | 7.57 | $ | 6.96 | $ | 6.88 |
(1) | Excludes the 2001 ceiling test write down. |
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Accounting for Variable Interest Entities |
In January 2003, the FASB issued Financial Interpretation 46 “Accounting for Variable Interest Entities” (“FIN 46”) that requires the consolidation of Variable Interest Entities (“VIEs”). VIEs are entities that have insufficient equity or their equity investors lack one or more of the specified elements that a controlling entity would have. The VIEs are controlled through financial interests that indicate control (referred to as “variable interests”). Variable interests are the rights or obligations that expose the holder of the variable interest to expected losses or expected residual gains of the entity. The holder of the majority of an entity’s variable interests is considered the primary beneficiary of the VIE and is required to consolidate the VIE. In December 2003 the FASB issued FIN 46R which superceded FIN 46 and restricts the scope of the definition of entities that would be considered VIEs that require consolidation. The Company does not believe FIN 46R results in the consolidation of any additional entities that existed at December 31, 2003.
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