Exhibit 2
HUSKY ENERGY INC.
CONSOLIDATED FINANCIAL
STATEMENTS
For the Year Ended December 31, 2002
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, the independent auditors, in accordance with generally accepted auditing standards on behalf of the shareholders. KPMG have full and free access to the Audit Committee.
John C.S. Lau President & Chief Executive Officer | Neil McGee Vice President & Chief Financial Officer | |
Calgary, Alberta, Canada | ||
February 5, 2003 |
AUDITORS’ REPORT TO THE SHAREHOLDERS
We have audited the consolidated balance sheets of Husky Energy Inc., as at December 31, 2002, 2001 and 2000 and the consolidated statements of earnings, retained earnings (deficit), and cash flows for each of the years in the three-year period ended December 31, 2002. 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, 2002, 2001 and 2000 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2002 in accordance with Canadian generally accepted accounting principles.
Calgary, Alberta, Canada Chartered Accountants |
February 5, 2003 |
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CONSOLIDATED BALANCE SHEETS
As at December 31 (millions of dollars) | 2002 | 2001 | 2000 | ||||||||||
Assets | |||||||||||||
Current assets | |||||||||||||
Cash and cash equivalents | $ | 306 | $ | — | $ | — | |||||||
Accounts receivable | 572 | 376 | 715 | ||||||||||
Inventories (note 4) | 243 | 226 | 186 | ||||||||||
Prepaid expenses | 23 | 24 | 27 | ||||||||||
1,144 | 626 | 928 | |||||||||||
Property, plant and equipment, net (notes 1, 5) (full cost accounting) | 9,347 | 8,715 | 7,841 | ||||||||||
Other assets (note 9) | 84 | 29 | 60 | ||||||||||
$ | 10,575 | $ | 9,370 | $ | 8,829 | ||||||||
Liabilities and Shareholders’ Equity | |||||||||||||
Current liabilities | |||||||||||||
Bank operating loans (note 8) | $ | — | $ | 100 | $ | 34 | |||||||
Accounts payable and accrued liabilities | 811 | 821 | 1,076 | ||||||||||
Long-term debt due within one year (note 9) | 421 | 144 | 33 | ||||||||||
1,232 | 1,065 | 1,143 | |||||||||||
Long-term debt (note 9) | 1,964 | 1,948 | 2,311 | ||||||||||
Site restoration provision (note 5) | 249 | 212 | 178 | ||||||||||
Future income taxes (note 10) | 2,003 | 1,659 | 1,212 | ||||||||||
Shareholders’ equity | |||||||||||||
Capital securities and accrued return (note 12) | 364 | 367 | 344 | ||||||||||
Common shares (note 11) | 3,406 | 3,397 | 3,388 | ||||||||||
Retained earnings | 1,357 | 722 | 253 | ||||||||||
5,127 | 4,486 | 3,985 | |||||||||||
Commitments and contingencies (note 14) | $ | 10,575 | $ | 9,370 | $ | 8,829 | |||||||
The accompanying notes to the consolidated financial statements are an integral part of these statements. 2001 and 2000 amounts as restated (note 3).
On behalf of the Board:
John C.S. Lau Director | Martin J.G. Glynn Director |
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CONSOLIDATED STATEMENTS OF EARNINGS
Year ended December 31 (millions of dollars, except per share amounts) | 2002 | 2001 | 2000 | ||||||||||
Sales and operating revenues, net of royalties | $ | 6,384 | $ | 6,596 | $ | 5,066 | |||||||
Costs and expenses | |||||||||||||
Cost of sales and operating expenses | 4,009 | 4,425 | 3,492 | ||||||||||
Selling and administration expenses | 94 | 88 | 67 | ||||||||||
Depletion, depreciation and amortization (notes 1,5) | 939 | 807 | 481 | ||||||||||
Interest — net (note 9) | 104 | 101 | 101 | ||||||||||
Foreign exchange | 13 | 94 | 39 | ||||||||||
Other — net | 1 | 7 | 85 | ||||||||||
5,160 | 5,522 | 4,265 | |||||||||||
Earnings before income taxes | 1,224 | 1,074 | 801 | ||||||||||
Income taxes (note 10) | |||||||||||||
Current | 66 | 20 | 12 | ||||||||||
Future | 354 | 400 | 351 | ||||||||||
420 | 420 | 363 | |||||||||||
Net earnings | $ | 804 | $ | 654 | $ | 438 | |||||||
Earnings per share (note 11) | |||||||||||||
Basic | $ | 1.88 | $ | 1.49 | $ | 1.28 | |||||||
Diluted | $ | 1.88 | $ | 1.48 | $ | 1.28 | |||||||
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (DEFICIT)
Year ended December 31 (millions of dollars) | 2002 | 2001 | 2000 | ||||||||||
Beginning of year | $ | 722 | $ | 253 | $ | (295 | ) | ||||||
Net earnings | 804 | 654 | 438 | ||||||||||
Dividends on common shares | (151 | ) | (150 | ) | — | ||||||||
Return on capital securities (note 12) | (29 | ) | (53 | ) | (43 | ) | |||||||
Related future income taxes (note 10) | 11 | 18 | 16 | ||||||||||
Reduction of stated capital | — | — | 160 | ||||||||||
Foreign exchange (retroactive adjustment)(note 3) | — | — | (15 | ) | |||||||||
Employee future benefits (note 13) | -- | -- | (8 | ) | |||||||||
End of year | $ | 1,357 | $ | 722 | $ | 253 | |||||||
The accompanying notes to the consolidated financial statements are an integral part of these statements. 2001 and 2000 amounts as restated (note 3).
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CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended December 31 (millions of dollars, except per share amounts) | 2002 | 2001 | 2000 | ||||||||||
Operating activities | |||||||||||||
Net earnings | $ | 804 | $ | 654 | $ | 438 | |||||||
Items not affecting cash | |||||||||||||
Depletion, depreciation and amortization | 939 | 807 | 481 | ||||||||||
Future income taxes | 354 | 400 | 351 | ||||||||||
Foreign exchange — non-cash (note 3) | — | 82 | 44 | ||||||||||
Other | (1 | ) | 3 | 85 | |||||||||
Cash flow from operations | 2,096 | 1,946 | 1,399 | ||||||||||
Change in non-cash working capital (note 7) | (204 | ) | (16 | ) | (190 | ) | |||||||
1,892 | 1,930 | 1,209 | |||||||||||
Financing activities | |||||||||||||
Bank operating loans financing — net | (100 | ) | 66 | 3 | |||||||||
Long-term debt issue | 972 | — | 535 | ||||||||||
Long-term debt repayment | (678 | ) | (356 | ) | (800 | ) | |||||||
Redemption of preferred shares | — | — | (364 | ) | |||||||||
Return on capital securities payment | (31 | ) | (30 | ) | (30 | ) | |||||||
Debt issue costs | (9 | ) | — | — | |||||||||
Deferred credits | — | (4 | ) | (4 | ) | ||||||||
Proceeds from exercise of stock options | 9 | 9 | — | ||||||||||
Dividends on common shares | (151 | ) | (150 | ) | — | ||||||||
Change in non-cash working capital (note 7) | (9 | ) | 42 | 102 | |||||||||
3 | (423 | ) | (558 | ) | |||||||||
Available for investing | 1,895 | 1,507 | 651 | ||||||||||
Investing activities | |||||||||||||
Capital expenditures | (1,692 | ) | (1,473 | ) | (803 | ) | |||||||
Corporate acquisitions | (3 | ) | (125 | ) | (38 | ) | |||||||
Asset sales | 93 | 67 | 2 | ||||||||||
Other | (20 | ) | 6 | 80 | |||||||||
Change in non-cash working capital (note 7) | 33 | 18 | 108 | ||||||||||
(1,589 | ) | (1,507 | ) | (651 | ) | ||||||||
Increase in cash and cash equivalents | 306 | — | — | ||||||||||
Cash and cash equivalents at beginning of year | — | — | — | ||||||||||
Cash and cash equivalents at end of year | $ | 306 | $ | — | $ | — | |||||||
Cash flow from operations per share (note 11) | |||||||||||||
Basic | $ | 4.94 | $ | 4.60 | $ | 4.26 | |||||||
Diluted | $ | 4.92 | $ | 4.57 | $ | 4.26 | |||||||
The accompanying notes to the consolidated financial statements are an integral part of these statements. 2001 and 2000 amounts as restated (note 3).
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Except where indicated and per share amounts, all dollar amounts are in millions of Canadian dollars.
Note 1
Segmented Financial Information
Upstream | Midstream | ||||||||||||||||||||||||||||||||||||
Upgrading | Infrastructure and Marketing | ||||||||||||||||||||||||||||||||||||
2002 | 2001 | 2000 | 2002 | 2001 | 2000 | 2002 | 2001 | 2000 | |||||||||||||||||||||||||||||
Year ended December 31 | |||||||||||||||||||||||||||||||||||||
Sales and operating revenues, net of royalties | $ | 2,665 | $ | 2,165 | $ | 1,549 | $ | 909 | $ | 886 | $ | 1,006 | $ | 4,230 | $ | 4,380 | $ | 2,309 | |||||||||||||||||||
Costs and expenses | |||||||||||||||||||||||||||||||||||||
Operating, cost of sales, selling and general | 729 | 648 | 375 | 811 | 638 | 848 | 4,038 | 4,193 | 2,193 | ||||||||||||||||||||||||||||
Depletion, depreciation and amortization | 851 | 728 | 407 | 18 | 17 | 16 | 20 | 17 | 15 | ||||||||||||||||||||||||||||
Interest — net | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||
Foreign exchange | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||
1,580 | 1,376 | 782 | 829 | 655 | 864 | 4,058 | 4,210 | 2,208 | |||||||||||||||||||||||||||||
Earnings (loss) before income taxes | 1,085 | 789 | 767 | 80 | 231 | 142 | 172 | 170 | 101 | ||||||||||||||||||||||||||||
Current income taxes | 55 | 17 | 10 | 1 | 1 | 1 | 6 | 1 | — | ||||||||||||||||||||||||||||
Future income taxes | 342 | 290 | 305 | 25 | 72 | 53 | 59 | 71 | 45 | ||||||||||||||||||||||||||||
Net earnings (loss) | $ | 688 | $ | 482 | $ | 452 | $ | 54 | $ | 158 | $ | 88 | $ | 107 | $ | 98 | $ | 56 | |||||||||||||||||||
Capital employed — As at December 31(2) | $ | 6,040 | $ | 5,715 | $ | 5,398 | $ | 319 | $ | 320 | $ | 352 | $ | 431 | $ | 395 | $ | 312 | |||||||||||||||||||
Property, plant and equipment — As at December 31 | |||||||||||||||||||||||||||||||||||||
Cost | |||||||||||||||||||||||||||||||||||||
Canada | $ | 11,525 | $ | 10,353 | $ | 9,023 | $ | 998 | $ | 958 | $ | 912 | $ | 591 | $ | 575 | $ | 510 | |||||||||||||||||||
International | 469 | 394 | 290 | — | — | — | — | — | — | ||||||||||||||||||||||||||||
$ | 11,994 | $ | 10,747 | $ | 9,313 | $ | 998 | $ | 958 | $ | 912 | $ | 591 | $ | 575 | $ | 510 | ||||||||||||||||||||
Accumulated depletion, depreciation and amortization | |||||||||||||||||||||||||||||||||||||
Canada | $ | 3,894 | $ | 3,272 | $ | 2,622 | $ | 372 | $ | 354 | $ | 337 | $ | 184 | $ | 165 | $ | 148 | |||||||||||||||||||
International | 185 | 147 | 139 | — | — | — | — | — | — | ||||||||||||||||||||||||||||
$ | 4,079 | $ | 3,419 | $ | 2,761 | $ | 372 | $ | 354 | $ | 337 | $ | 184 | $ | 165 | $ | 148 | ||||||||||||||||||||
Net | |||||||||||||||||||||||||||||||||||||
Canada | $ | 7,631 | $ | 7,081 | $ | 6,401 | $ | 626 | $ | 604 | $ | 575 | $ | 407 | $ | 410 | $ | 362 | |||||||||||||||||||
International | 284 | 247 | 151 | — | — | — | — | — | — | ||||||||||||||||||||||||||||
$ | 7,915 | $ | 7,328 | $ | 6,552 | $ | 626 | $ | 604 | $ | 575 | $ | 407 | $ | 410 | $ | 362 | ||||||||||||||||||||
Total assets — As at December 31 | |||||||||||||||||||||||||||||||||||||
Canada | $ | 7,883 | $ | 7,160 | $ | 6,584 | $ | 658 | $ | 644 | $ | 613 | $ | 850 | $ | 862 | $ | 1,000 | |||||||||||||||||||
International | 337 | 247 | 151 | — | — | — | — | — | — | ||||||||||||||||||||||||||||
$ | 8,220 | $ | 7,407 | $ | 6,735 | $ | 658 | $ | 644 | $ | 613 | $ | 850 | $ | 862 | $ | 1,000 | ||||||||||||||||||||
(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) | Capital employed is defined as short- and long-term debt and shareholders’ equity. | |
Comparative figures have been restated to conform with current year’s classification. | ||
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Refined Products | Corporate and Eliminations(1) | Total | |||||||||||||||||||||||||||||||||||
2002 | 2001 | 2000 | 2002 | 2001 | 2000 | 2002 | 2001 | 2000 | |||||||||||||||||||||||||||||
Year ended December 31 | |||||||||||||||||||||||||||||||||||||
Sales and operating revenues, net of royalties | $ | 1,310 | $ | 1,349 | $ | 1,347 | $ | (2,730 | ) | $ | (2,184 | ) | $ | (1,145 | ) | $ | 6,384 | $ | 6,596 | $ | 5,066 | ||||||||||||||||
Costs and expenses | |||||||||||||||||||||||||||||||||||||
Operating, cost of sales, selling and general | 1,222 | 1,206 | 1,288 | (2,696 | ) | (2,165 | ) | (1,060 | ) | 4,104 | 4,520 | 3,644 | |||||||||||||||||||||||||
Depletion, depreciation and amortization | 34 | 31 | 28 | 16 | 14 | 15 | 939 | 807 | 481 | ||||||||||||||||||||||||||||
Interest — net | — | — | — | 104 | 101 | 101 | 104 | 101 | 101 | ||||||||||||||||||||||||||||
Foreign exchange | — | — | — | 13 | 94 | 39 | 13 | 94 | 39 | ||||||||||||||||||||||||||||
1,256 | 1,237 | 1,316 | (2,563 | ) | (1,956 | ) | (905 | ) | 5,160 | 5,522 | 4,265 | ||||||||||||||||||||||||||
Earnings (loss) before income taxes | 54 | 112 | 31 | (167 | ) | (228 | ) | (240 | ) | 1,224 | 1,074 | 801 | |||||||||||||||||||||||||
Current income taxes | 4 | 1 | 1 | — | — | — | 66 | 20 | 12 | ||||||||||||||||||||||||||||
Future income taxes | 18 | 48 | 14 | (90 | ) | (81 | ) | (66 | ) | 354 | 400 | 351 | |||||||||||||||||||||||||
Net earnings (loss) | $ | 32 | $ | 63 | $ | 16 | $ | (77 | ) | $ | (147 | ) | $ | (174 | ) | $ | 804 | $ | 654 | $ | 438 | ||||||||||||||||
Capital employed — As at December 31(2) | $ | 338 | $ | 329 | $ | 351 | $ | 384 | $ | (81 | ) | $ | (50 | ) | $ | 7,512 | $ | 6,678 | $ | 6,363 | |||||||||||||||||
Property, plant and equipment — As at December 31 | |||||||||||||||||||||||||||||||||||||
Cost | |||||||||||||||||||||||||||||||||||||
Canada | $ | 702 | $ | 655 | $ | 628 | $ | 165 | $ | 143 | $ | 108 | $ | 13,981 | $ | 12,684 | $ | 11,181 | |||||||||||||||||||
International | — | — | — | — | — | — | 469 | 394 | 290 | ||||||||||||||||||||||||||||
$ | 702 | $ | 655 | $ | 628 | $ | 165 | $ | 143 | $ | 108 | $ | 14,450 | $ | 13,078 | $ | 11,471 | ||||||||||||||||||||
Accumulated depletion, depreciation and amortization | |||||||||||||||||||||||||||||||||||||
Canada | $ | 360 | $ | 330 | $ | 302 | $ | 108 | $ | 95 | $ | 82 | $ | 4,918 | $ | 4,216 | $ | 3,491 | |||||||||||||||||||
International | — | — | — | — | — | — | 185 | 147 | 139 | ||||||||||||||||||||||||||||
$ | 360 | $ | 330 | $ | 302 | $ | 108 | $ | 95 | $ | 82 | $ | 5,103 | $ | 4,363 | $ | 3,630 | ||||||||||||||||||||
Net | |||||||||||||||||||||||||||||||||||||
Canada | $ | 342 | $ | 325 | $ | 326 | $ | 57 | $ | 48 | $ | 26 | $ | 9,063 | $ | 8,468 | $ | 7,690 | |||||||||||||||||||
International | — | — | — | — | — | — | 284 | 247 | 151 | ||||||||||||||||||||||||||||
$ | 342 | $ | 325 | $ | 326 | $ | 57 | $ | 48 | $ | 26 | $ | 9,347 | $ | 8,715 | $ | 7,841 | ||||||||||||||||||||
Total assets — As at December 31 | |||||||||||||||||||||||||||||||||||||
Canada | $ | 534 | $ | 428 | $ | 487 | $ | 313 | $ | 29 | $ | (6 | ) | $ | 10,238 | $ | 9,123 | $ | 8,678 | ||||||||||||||||||
International | — | — | — | — | — | — | 337 | 247 | 151 | ||||||||||||||||||||||||||||
$ | 534 | $ | 428 | $ | 487 | $ | 313 | $ | 29 | $ | (6 | ) | $ | 10,575 | $ | 9,370 | $ | 8,829 | |||||||||||||||||||
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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.
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 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
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 16, Reconciliation to Accounting Principles Generally Accepted in the United States.
The preparation of financial statements in conformity with 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.
A significant part of the Company’s activities is conducted jointly with third parties and accordingly the accounts reflect the Company’s proportionate interest in these activities.
Certain prior years’ amounts have been reclassified to conform with current presentation.
In 2001 and previously, the Company presented certain crown charges as a component of operating expenses. These charges have been reclassified as royalties for 2002 and for all comparative periods presented in these financial statements. There is no impact on the net earnings or cash flow of the Company as a result of this change.
a) | Cash and Cash Equivalents | |
Cash and cash equivalents consist of cash on hand and deposits with a maturity of less than three months. | ||
b) | 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. |
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c) | 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, 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 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. | |||
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 related future income taxes, 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, administrative expenses, financing costs and income taxes. Any amounts in excess of these limits are charged to earnings. | |||
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. 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. |
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iii) | Future Removal and Site Restoration Costs | ||
Future removal and site restoration costs net of expected recoveries, 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. |
d) | Financial Instruments | |
Gains and losses related to financial instruments designated as hedges are deferred and recognized in the period and in the same financial statement category in which the revenues or expenses associated with the hedged transactions are recognized. | ||
In November 2001, the Accounting Standards Board (“AcSB”) of the Canadian Institute of Chartered Accountants (“CICA”) issued an Accounting Guideline “Hedging Relationships” that establishes standards for the documentation and effectiveness of hedging activities that are substantially similar to the corresponding requirements in Financial Accounting Standards Board (“FASB”) Statement No. 133 “Accounting for Derivative Instruments and Hedging Activities” (“FAS 133”). The new recommendations will be effective January 1, 2004. Note 16 discloses the impact of FAS 133 on the financial statements for 2002. | ||
e) | 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. | ||
f) | Foreign Currency Translation | |
Results of foreign operations, all of which are considered financially and operationally integrated, are translated to Canadian dollars using average rates for the year for revenue and expenses, except depreciation and depletion which are translated at the rate of exchange applicable to the related assets. Monetary assets are translated at current exchange rates and non-monetary assets 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. | ||
Effective January 1, 2002, the Company retroactively adopted the revised recommendations of the CICA on Foreign Currency Translation. The new recommendations eliminated the deferral and amortization of foreign exchange gains and losses on long-term monetary items. This change resulted in a reduction of retained earnings at January 1, 2000 of $15 million and a reduction of earnings after tax of $47 million and $26 million for the years ended December 31, 2001 and 2000, respectively. This change also resulted in a reduction to other assets of $133 million, a reduction to the future income tax liability of $36 million and an increase to capital securities of $17 million as at December 31, 2001. | ||
g) | Stock-based Compensation Plans | |
In accordance with the Company’s stock option plan, common share options are 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 share options is equal to the market value of the common shares when |
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they are granted. In accordance with CICA section 3870 “Stock-based Compensation and Other Stock-based Payments”, note 11 discloses the impact on the financial statements for options granted after January 1, 2002. The standards are substantially similar to those in FASB Statement No. 123 “Accounting for Stock-based Compensation” (“FAS 123”). Note 16 presents the disclosures required by FAS 123 in the financial statements. | ||
h) | 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. | ||
i) | Impairment or Disposal of Long-term Assets | |
In December 2002, the AcSB of the CICA approved new standards for the impairment and disposal of long-lived assets that are substantially equivalent to those in FASB Statement No. 144 “Accounting for the Impairment or Disposal of Long-term Assets” (“FAS 144”). Note 16 presents the disclosures required by FAS 144 in the financial statements. |
Note 4
Inventories
2002 | 2001 | 2000 | ||||||||||
Crude oil and refined petroleum products | $ | 166 | $ | 140 | $ | 132 | ||||||
Natural gas | 50 | 69 | 41 | |||||||||
Materials, supplies and other | 27 | 17 | 13 | |||||||||
$ | 243 | $ | 226 | $ | 186 | |||||||
Note 5
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:
2002 | 2001 | 2000 | ||||||||||
Canada | $ | 1,318 | $ | 1,226 | $ | 1,073 | ||||||
International | 37 | 235 | 137 | |||||||||
$ | 1,355 | $ | 1,461 | $ | 1,210 | |||||||
The Company has estimated future removal and site restoration costs of $703 million at December 31, 2002 (2001 — $653 million; 2000 — $619 million). During 2002 actual removal and site restoration expenditures amounted to $17 million (2001 — $18 million; 2000 — $10 million).
Note 6
Plan of Arrangement
On June 18, 2000 Husky Oil Limited and Renaissance Energy Ltd. (“Renaissance”) agreed to a Plan of Arrangement whereby Husky Oil Limited and its principal subsidiary, Husky Oil Operations Limited (“HOOL”), would merge with Renaissance and continue as HOOL. The Plan of Arrangement also included the incorporation of a new company, Husky Energy Inc. Husky is the parent company of HOOL and is publicly traded. The transaction became effective August 25, 2000 and the results of Husky include those of Renaissance from that date forward.
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The allocation of the aggregate purchase price based on the estimated fair values of the Renaissance net assets at August 25, 2000 were as follows:
Allocation | |||||
Net assets acquired | |||||
Working capital | $ | 84 | |||
Property, plant and equipment | 3,514 | ||||
Marketing and transportation | (131 | ) | |||
Other assets | 23 | ||||
Acquisition costs | (51 | ) | |||
Site restoration provision | (70 | ) | |||
Future income taxes | (60 | ) | |||
Long-term debt | (1,211 | ) | |||
$ | 2,098 | ||||
Consideration | |||||
Common shares exchanged | $ | 1,734 | |||
Preferred shares issued | 364 | ||||
$ | 2,098 | ||||
Note 7
Cash Flows — Change in Non-cash Working Capital
a) | Changes in non-cash working capital were as follows: |
2002 | 2001 | 2000 | |||||||||||
Decrease (increase) in non-cash working capital | |||||||||||||
Accounts receivable | $ | (153 | ) | $ | 361 | $ | (254 | ) | |||||
Inventories | (17 | ) | (40 | ) | (38 | ) | |||||||
Prepaid expenses | 1 | 3 | 2 | ||||||||||
Accounts payable and accrued liabilities | (11 | ) | (280 | ) | 310 | ||||||||
Change in non-cash working capital | (180 | ) | 44 | 20 | |||||||||
Relating to: | |||||||||||||
Financing activities | (9 | ) | 42 | 102 | |||||||||
Investing activities | 33 | 18 | 108 | ||||||||||
Operating activities | $ | (204 | ) | $ | (16 | ) | $ | (190 | ) | ||||
b) | Other cash flow information: |
2002 | 2001 | 2000 | ||||||||||
Cash taxes paid | $ | 20 | $ | 13 | $ | 9 | ||||||
Cash interest paid | $ | 139 | $ | 145 | $ | 138 | ||||||
Note 8
Bank Operating Loans
At December 31, 2002 the Company had short-term borrowing lines of credit with banks totalling $195 million; (2001 — $195 million; 2000 — $234 million), of which $12 million (2001 — $102 million; 2000 — $84 million) had been used for bank operating loans and letters of credit. Interest payable is based on Bankers’ Acceptance, money market, or prime rates. During 2002, the weighted average interest rate on short-term borrowings was approximately 2.9 percent.
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Note 9
Long-term Debt
Maturity | 2002 | 2001 | 2000 | ||||||||||||||
Long-term debt | |||||||||||||||||
Revolving syndicated credit facility | |||||||||||||||||
-2001 U.S. $116 | $ | — | $ | 185 | $ | 174 | |||||||||||
Non-revolving syndicated credit facility | — | — | 300 | ||||||||||||||
6.25% notes | -U.S. $400 | 2012 | 632 | — | — | ||||||||||||
6.875% notes | -U.S. $150 | 2003 | 237 | 239 | 225 | ||||||||||||
7.125% notes | -U.S. $150 | 2006 | 237 | 239 | 225 | ||||||||||||
7.55% debentures | -U.S. $200 | 2016 | 316 | 318 | 300 | ||||||||||||
8.45% senior secured bonds | -2002 U.S. $162 | 2003-12 | 256 | 276 | 268 | ||||||||||||
-2001 U.S. $173 | |||||||||||||||||
-2000 U.S. $179 | |||||||||||||||||
Private placement notes | -2002 U.S. $68 | 2003-5 | 107 | 135 | 152 | ||||||||||||
-2001 U.S. $85 | |||||||||||||||||
-2000 U.S. $101 | |||||||||||||||||
Medium-term notes | 2003-9 | 600 | 700 | 700 | |||||||||||||
Total long-term debt | 2,385 | 2,092 | 2,344 | ||||||||||||||
Amount due within one year | (421 | ) | (144 | ) | (33 | ) | |||||||||||
$ | 1,964 | $ | 1,948 | $ | 2,311 | ||||||||||||
Interest — net for the years ended December 31 were as follows:
2002 | 2001 | 2000 | ||||||||||
Long-term debt | $ | 128 | $ | 148 | $ | 144 | ||||||
Short-term debt | 3 | 5 | 4 | |||||||||
131 | 153 | 148 | ||||||||||
Amount capitalized | (26 | ) | (51 | ) | (43 | ) | ||||||
105 | 102 | 105 | ||||||||||
Interest income | (1 | ) | (1 | ) | (4 | ) | ||||||
$ | 104 | $ | 101 | $ | 101 | |||||||
As at December 31, 2002, other assets included $23 million (2001 — $17 million; 2000 — $20 million) of deferred debt issue costs.
The revolving syndicated credit facility allows the Company to borrow up to $940 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 four-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.
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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 6.875 percent notes, the 7.125 percent notes and the 7.55 percent debentures represent unsecured securities issued under a trust indenture dated October 31, 1996. Such securities mature in 2003, 2006 and 2016, respectively. The 6.875 percent and 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 oil field and associated facilities. The repayment of the securities is contracted to be made solely from revenue from the oil field. There is also a charge created by the partnership on its interest in the assets of the 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 are issued under two separate note agreements dated January 31, 2001. 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 and C 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 C | 100 | 5.75 | % | February 2003 | ||||||||
Series D | 200 | 6.30 | % | June 2004 | ||||||||
Series E | 200 | 6.95 | % | July 2009 | ||||||||
$ | 600 | |||||||||||
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: 2003 — $421 million; 2004 — $272 million; 2005 — $74 million; 2006 — $276 million; and 2007 — $132 million.
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Note 10
Income Taxes
The combined provisions for income taxes in the Consolidated Statements of Earnings and Retained Earnings (Deficit) 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:
2002 | 2001 | 2000 | |||||||||||
Earnings before taxes | $ | 1,224 | $ | 1,074 | $ | 801 | |||||||
Statutory income tax rate (percent) | 41.6 | 43.7 | 44.7 | ||||||||||
Expected income tax | 509 | 469 | 358 | ||||||||||
Effect on income tax of: | |||||||||||||
Change in statutory tax rate | (31 | ) | (52 | ) | — | ||||||||
Ownership charges | — | — | 15 | ||||||||||
Return on capital securities | (11 | ) | (18 | ) | (16 | ) | |||||||
Royalties, lease rentals and mineral taxes payable to the crown | 159 | 184 | 141 | ||||||||||
Resource allowance on Canadian production income | (212 | ) | (219 | ) | (175 | ) | |||||||
Non-deductible capital taxes | 18 | 20 | 12 | ||||||||||
Gains and losses on foreign exchange | — | 20 | 9 | ||||||||||
Other — net | (23 | ) | (2 | ) | 3 | ||||||||
$ | 409 | $ | 402 | $ | 347 | ||||||||
Charged (credited) to: | |||||||||||||
Income tax expense | $ | 420 | $ | 420 | $ | 363 | |||||||
Retained earnings | (11 | ) | (18 | ) | (16 | ) | |||||||
$ | 409 | $ | 402 | $ | 347 | ||||||||
The future income taxes liability at December 31 comprised the tax effect of temporary differences as follows:
2002 | 2001 | 2000 | |||||||||||
Future tax liabilities | |||||||||||||
Property, plant and equipment | $ | 2,199 | $ | 1,882 | $ | 1,467 | |||||||
Other temporary differences | 30 | 7 | 2 | ||||||||||
2,229 | 1,889 | 1,469 | |||||||||||
Future tax assets | |||||||||||||
Loss carryforwards | 7 | 28 | 103 | ||||||||||
Foreign exchange losses deductible on realization | 28 | 26 | 7 | ||||||||||
Site restoration and other deferred credits | 105 | 93 | 81 | ||||||||||
Provincial royalty rebates | 48 | 46 | 45 | ||||||||||
Other temporary differences | 38 | 37 | 21 | ||||||||||
226 | 230 | 257 | |||||||||||
$ | 2,003 | $ | 1,659 | $ | 1,212 | ||||||||
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Note 11
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.
Changes to issued share capital were as follows:
Common Shares
Number of Shares | Dollars | |||||||
January 1, 2000 | — | $ | — | |||||
Issued for Renaissance shares | 145,530,429 | 1,734 | ||||||
Issued for Husky Oil Limited shares | 270,272,654 | 1,654 | ||||||
December 31, 2000 | 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 | |||||
Preferred Shares
In 2000, the Company issued 145.5 million preferred shares to former shareholders of Renaissance. These shares were subsequently redeemed for total proceeds of $364 million. At December 31, 2002, 2001 and 2000, there were no outstanding preferred shares.
Restructuring
As part of the restructuring that occurred in 2000, all previously issued preferred shares of Husky Oil Limited were exchanged, redeemed or cancelled on the capitalization of Husky Energy Inc. All previously issued common and preferred shares were recorded at a value of $1 per share. In addition, the previously outstanding subordinated shareholders’ loans, which bore interest payable at 9.05 percent per annum, were converted to Class C preferred shares prior to their cancellation.
In August 2000, $150 million Class A preferred shares and $190 million Class B preferred shares were exchanged for $340 million of Husky Energy Inc. common shares. In addition, $1,306 million Class C preferred shares were cancelled on amalgamation for $1,306 million Husky Energy Inc. common shares. Husky Energy Inc. common shares issued for Husky Oil Limited shares as at December 31, 2000 were $1,654 million which included $8 million of paid in capital.
Stock Options
The following options to purchase common shares have been awarded to directors, officers and certain other employees. At December 31, 2002, 29.2 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. 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.
Page 39
Number of | Weighted | Weighted Average | Options | |||||||||||||
Shares | Average | Contractual | Exercisable | |||||||||||||
(thousands) | Exercise Prices | Life (years) | (thousands) | |||||||||||||
January 1, 2000 | — | $ | — | — | — | |||||||||||
Granted | 8,995 | $ | 13.61 | 5 | ||||||||||||
Assumed on Renaissance acquisition | 1,372 | $ | 15.77 | 2 | ||||||||||||
Forfeited | (606 | ) | $ | 13.61 | 5 | |||||||||||
December 31, 2000 | 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 | |||||||||||
At December 31, 2002, the options outstanding had exercise prices ranging from $11.16 to $19.76.
In 2000, the Company granted 1.4 million 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. As at December 31, 2002, there were 815 thousand common shares remaining which could potentially be issued as a result of the exercise of these warrants.
The fair values of all common share options granted are estimated on the date of grant using the Modified 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:
2002 | 2001 | 2000 | ||||||||||
Weighted average fair market value per option | $ | 5.19 | $ | 5.70 | $ | 5.03 | ||||||
Risk-free interest rate (percent) | 3.6 | 3.5 | 5.5 | |||||||||
Volatility (percent) | 43 | 45 | 30 | |||||||||
Expected life (years) | 5 | 5 | 5 | |||||||||
Expected annual dividend per share | $ | 0.36 | $ | 0.36 | $ | 0.36 | ||||||
The Company follows the intrinsic value method of accounting for stock-based compensation for its fixed stock option plan, under which compensation cost is not recognized. If the Company applied the fair value method at the grant dates for options granted in 2002 and also to all options granted, the Company’s net earnings and earnings per share would have been as follows:
Page 40
2002 | 2001 | 2000 | |||||||||||
Compensation cost — options granted in 2002 | $ | — | $ | — | $ | — | |||||||
Compensation cost — all options granted | $ | 13 | $ | 13 | $ | 4 | |||||||
Net earnings available to common shareholders | |||||||||||||
As reported | $ | 787 | $ | 620 | $ | 410 | |||||||
Options granted in 2002 | $ | 787 | $ | 620 | $ | 410 | |||||||
All options granted | $ | 774 | $ | 607 | $ | 406 | |||||||
Weighted average number of common shares outstanding(millions) | |||||||||||||
Basic | 417.4 | 416.1 | 321.2 | ||||||||||
Diluted | 419.3 | 418.6 | 321.2 | ||||||||||
Basic earnings per share | |||||||||||||
As reported | $ | 1.88 | $ | 1.49 | $ | 1.28 | |||||||
Options granted in 2002 | $ | 1.88 | $ | 1.49 | $ | 1.28 | |||||||
All options granted | $ | 1.86 | $ | 1.46 | $ | 1.26 | |||||||
Diluted earnings per share | |||||||||||||
As reported | $ | 1.88 | $ | 1.48 | $ | 1.28 | |||||||
Options granted in 2002 | $ | 1.88 | $ | 1.48 | $ | 1.28 | |||||||
All options granted | $ | 1.85 | $ | 1.45 | $ | 1.26 |
Per Share Amounts
The calculation of basic net earnings and cash flow from operations per common share is based on the net earnings and cash flow from operations after deducting return on capital securities, net of applicable income taxes, divided by the weighted average number of common shares outstanding.
Diluted net earnings and cash flow from operations per common share include the dilutive impact of options and warrants outstanding under the employee 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 and cash flow from operations per common share, as the Company has neither the obligation nor intention to settle amounts due through the issue of shares.
The number of antidilutive options and warrants at December 31, 2002, 2001 and 2000 were nil, nil and 11.7 million, respectively.
During 2002 the Company declared dividends of $0.36 per common share (2001 — $0.36 per common share).
Note 12
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 amounts, net of
Page 41
income taxes, are classified as distributions of equity. Return on capital securities comprises the return and foreign exchange on the capital securities.
The amounts disclosed as capital securities in shareholders’ equity at December 31 were as follows:
2002 | 2001 | 2000 | ||||||||||
Capital securities —U.S. $225 | $ | 355 | $ | 358 | $ | 338 | ||||||
Unamortized costs of issue | (3 | ) | (3 | ) | (5 | ) | ||||||
Accrued return | 12 | 12 | 11 | |||||||||
$ | 364 | $ | 367 | $ | 344 | |||||||
Note 13
Pension Plans and Other Post-retirement 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 medical and dental coverage to its retirees which are accrued over the working lives of the employees.
Weighted average long-term assumptions used for the defined benefit pension plan and other post-retirement benefits were as follows:
2002 | 2001 | 2000 | ||||||||||
Discount rate(percent) | 6.3 | 7.3 | 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 status of the defined benefit plan and accrued benefit liability at December 31 were as follows:
2002 | 2001 | 2000 | ||||||||||
Plan assets at fair market value, principally marketable debt and equity securities and cash equivalents | $ | 77 | $ | 85 | $ | 90 | ||||||
Projected benefit obligation | (108 | ) | (95 | ) | (93 | ) | ||||||
Excess assets (excess obligation) | (31 | ) | (10 | ) | (3 | ) | ||||||
Unrecognized past service cost | 1 | — | — | |||||||||
Unrecognized (gains) losses | 27 | 6 | (2 | ) | ||||||||
Accrued benefit liability | $ | (3 | ) | $ | (4 | ) | $ | (5 | ) | |||
The Company’s other post-retirement benefits program is not funded and at December 31, 2002, the obligation was $21 million, $17 million of which was accrued. The obligation and accrual at December 31, 2001 and 2000 was $16 million and $13 million, respectively. At December 31, 2002 the discount rate was changed to 6.3 percent from 7.3 percent.
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 would require payments to them, should certain product price conditions be met.
The Company has firm commitments for transportation services that require the payment of tariffs. The Company has sufficient production to utilize these transmission services.
The Company has awarded various contracts for the construction of the floating production, storage and offloading vessel and several other components of the White Rose development
Page 42
project with expected completion dates in 2005. The Company’s share of the total value of contractual obligations at December 31, 2002 was $1.1 billion. As at December 31, 2002 the Company had spent $322 million on these contracts.
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
Financial Instruments and Risk Management
The nature of the Company’s operations, including the issuance of long-term debt, exposes the Company to fluctuations in commodity prices, foreign currency exchange rates and interest rates. The Company monitors these risks and, when appropriate, utilizes derivative financial instruments to manage its exposure to these risks. These financial instruments are entered into solely for hedging purposes and are not used for trading or other speculative purposes.
Carrying Values and Estimated Fair Values of Financial Instruments
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 those instruments. The estimated fair values of other financial instruments at December 31 were as follows:
Assets (Liabilities)
2002 | 2001 | 2000 | ||||||||||||||||||||||
Carrying Value | Fair Value | Carrying Value | Fair Value | Carrying Value | Fair Value | |||||||||||||||||||
Long-term debt | $ | (2,385 | ) | $ | (2,579 | ) | $ | (2,092 | ) | $ | (2,143 | ) | $ | (2,344 | ) | $ | (2,348 | ) | ||||||
Foreign exchange contracts | — | (7 | ) | — | (29 | ) | — | (5 | ) | |||||||||||||||
Foreign exchange forwards | — | (5 | ) | — | — | — | — | |||||||||||||||||
Interest rate swaps | — | 86 | — | 4 | — | 5 | ||||||||||||||||||
Natural gas contracts | — | (4 | ) | — | 15 | — | 5 | |||||||||||||||||
Crude oil contracts | — | 6 | — | — | — | — | ||||||||||||||||||
Fixed physical sales contracts | — | 111 | — | 114 | — | — | ||||||||||||||||||
Fixed physical purchase contracts | — | (122 | ) | — | (88 | ) | — | — |
Upstream Commodity Price Risk
The Company, from time to time, employs financial and physical arrangements intended to manage its exposure to price fluctuations. The Company may use physical fixed price product arrangements, futures contracts, swaps, collars and put options to hedge its commodity prices. A portion of the upstream segment price risk may be managed through the forward selling of oil and gas production combined with the forward selling of U.S. dollars.
At December 31, 2002 the Company had hedged 7.5 mmcf of natural gas per day at NYMEX for the years 2003-2005 at an average price of U.S. $1.92 per mcf.
During 2002 the impact was insignificant (2001 — insignificant; 2000 — loss of $150 million) from upstream hedges.
Commodity Marketing Activities
The Company also uses commodity derivatives to manage price risk associated with marketing activities. Derivative instruments provide methods to meet customer pricing requirements while achieving a price structure consistent with the Company’s overall pricing strategy. Under this
Page 43
“brokering” strategy substantially all derivative transactions are concurrently offset by a physical purchase or sale arrangement that matches the volume, duration and sales point at which the transactions are priced. In this manner the Company is able either to fix a spread between the price paid to the third party producer and the price received from the financial counterparty or convert a fixed price to floating.
During 2002, the Company entered into variable price physical forward sales with respect to crude oil of 20,000 bbls per day for October and November 2002. The physical sales were hedged by a number of financial transactions in which Husky pays the same variable pricing but receives fixed pricing. The average fixed price that Husky received under financial transactions for October and November production was U.S. $30.51 per bbl and U.S. $30.18 per bbl, respectively. A gain of $5 million was recognized in 2002.
In December 2002 and January 2003 the Company entered into variable price physical forward sales with respect to crude oil of 20,000 bbls per day for January 2003, 30,000 bbls per day for February to May 2003 and 20,000 bbls per day for June 2003. The average fixed price Husky receives under the financial transactions for January is U.S. $30.41 per bbl, February and March U.S. $30.45 per bbl, April and May U.S. $30.38 per bbl and for June U.S. $30.30 per bbl. Also, the Company hedged 30 mmcf per day of natural gas for April to October 2003 at an average price of U.S. $5.04.
In addition, the Company has a portfolio of fixed 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 sales contract prices. At December 31, 2002 the Company had entered into offsetting fixed price physical arrangements to concurrently sell and purchase natural gas for 12 mmcf per day for 2003 through October 2004 to receive an average fixed margin of $0.24 per mcf. In addition, the Company had entered into fixed price physical forward sales with respect to natural gas inventory held in storage for 26 mmcf per day through April 2004 to receive an average fixed margin of $0.92 per mcf.
At December 31, 2002 the Company had also entered into a number of arrangements, consistent with the strategies described above, the impact of which is insignificant to the Company’s operations.
Foreign Currency Rate Risk
The Company manages its exposure to exchange rate fluctuations by balancing the U.S. denominated cash flows from operations with U.S. denominated borrowings and other financial instruments. Husky utilizes spot and forward sales to convert cash flows to or from U.S. or Canadian currency. In addition, Husky has hedged a percentage of its exposure to fluctuations in the U.S. dollar with collar arrangements.
At December 31, 2002 the Company had hedged the exchange rate on U.S. dollars through currency collars up to U.S. $20 million per month at an average floor exchange rate of $1.49 and an average ceiling exchange rate of $1.54 for varying periods up to 2004.
During 2002 the Company realized a loss of $11 million (2001 — loss of $4 million; 2000 — loss of $5 million) from foreign currency risk management activities.
In January 2003, the Company used a currency swap to convert the 6.875 percent notes of U.S. $150 million due November 15, 2003 to Canadian $229 million. The exchange rate of the swap was $1.525 and will result in a foreign exchange gain of $8 million (before tax). The interest rate on the swap is 8.50 percent.
Foreign Exchange Forwards
The Company hedged U.S. dollar revenues for various amounts and maturities to 2005 through the use of foreign exchange forwards. The total amount hedged is U.S. $104 million at an average forward rate of $1.5576.
Interest Rate Risk
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, 2002 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:
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Debt | Amount | Swap Maturity | Swap Rate (percent) | |||||||||||||
6.875% notes | U.S. | $ | 35 | November 15, 2003 | U.S. LIBOR - 13 bps | |||||||||||
6.95% medium-term notes | $ | 200 | July 14, 2009 | CDOR + 175 bps | ||||||||||||
7.125% notes | U.S. | $ | 150 | November 15, 2006 | U.S. LIBOR + 235 bps | |||||||||||
7.55% debentures | U.S. | $ | 200 | November 15, 2011 | U.S. LIBOR + 194 bps | |||||||||||
6.25% senior notes | U.S. | $ | 150 | June 15, 2012 | U.S. LIBOR + 88 bps |
During 2002 the Company realized a gain of $29 million (2001 — gain of $2 million; 2000 — gain of $1 million) from interest rate risk management activities.
In January 2003, the Company unwound the interest rate swap on the 6.875 percent notes due November 15, 2003. The proceeds were U.S. $2 million and will be deferred and amortized into income during 2003.
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.
Sale of Accounts Receivable
The Company has an agreement to sell net trade receivables up to $200 million on a continual basis. The agreement calls for purchase discounts, based on Canadian commercial paper rates to be paid on an ongoing basis. The average effective rate for 2002 was approximately 2.8 percent (2001 — 4.7 percent; 2000 — 6.0 percent). The Company has potential exposure to an immaterial amount of credit loss under this agreement.
Note 16
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 to 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
2002 | 2001 | 2000 | ||||||||||||
Net earnings | $ | 804 | $ | 654 | $ | 438 | ||||||||
Adjustments | ||||||||||||||
Full cost accounting(a) | 88 | (544 | ) | 26 | ||||||||||
Related income taxes | (37 | ) | 235 | (12 | ) | |||||||||
Foreign currency translation on capital securities(b) | 3 | (20 | ) | (13 | ) | |||||||||
Related income taxes | (1 | ) | 5 | 4 | ||||||||||
Post-retirement benefits(c) | — | — | (4 | ) | ||||||||||
Related income taxes | — | — | 2 | |||||||||||
Return on capital securities(d) | (32 | ) | (33 | ) | (30 | ) | ||||||||
Related income taxes | 11 | 14 | 13 | |||||||||||
Gain (loss) on energy trading contracts(e) | (2 | ) | 20 | — | ||||||||||
Related income taxes | 1 | (8 | ) | — | ||||||||||
Derivatives and hedging(e) | 22 | (20 | ) | — | ||||||||||
Related income taxes | (9 | ) | 8 | — | ||||||||||
Accounting for income taxes(f) | (37 | ) | (14 | ) | 23 | |||||||||
Net earnings under U.S. GAAP | $ | 811 | $ | 297 | $ | 447 | ||||||||
Weighted average number of common shares outstanding under U.S. GAAP(millions) | ||||||||||||||
— Basic | 417.4 | 416.1 | 321.2 | |||||||||||
— Diluted | 419.3 | 418.6 | 321.2 | |||||||||||
Net earnings per share under U.S. GAAP | — Basic | $ | 1.94 | $ | 0.71 | $ | 1.39 | |||||||
— Diluted | $ | 1.93 | $ | 0.71 | $ | 1.39 |
2001 and 2000 amounts as restated (notes 3 and 16 (b)). |
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Condensed Consolidated Balance Sheets
2002 | 2001 | 2000 | ||||||||||||||||||||||
Canadian GAAP | U.S. GAAP | Canadian GAAP | U.S. GAAP | Canadian GAAP | U.S. GAAP | |||||||||||||||||||
Current assets(e) | $ | 1,144 | $ | 1,292 | $ | 626 | $ | 756 | $ | 928 | $ | 939 | ||||||||||||
Property, plant and equipment, net(a) | 9,347 | 8,670 | 8,715 | 7,950 | 7,841 | 7,620 | ||||||||||||||||||
Other assets(b)(d)(j) | 84 | 89 | 29 | 33 | 60 | 65 | ||||||||||||||||||
$ | 10,575 | $ | 10,051 | $ | 9,370 | $ | 8,739 | $ | 8,829 | $ | 8,624 | |||||||||||||
Current liabilities(c)(d)(e)(j) | $ | 1,232 | $ | 1,318 | $ | 1,065 | $ | 1,203 | $ | 1,143 | $ | 1,165 | ||||||||||||
Long-term debt(d)(e) | 1,964 | 2,406 | 1,948 | 2,306 | 2,311 | 2,648 | ||||||||||||||||||
Site restoration provision | 249 | 249 | 212 | 212 | 178 | 178 | ||||||||||||||||||
Future income taxes(a)(b)(c)(d)(e)(f)(j) | 2,003 | 1,772 | 1,659 | 1,361 | 1,212 | 1,135 | ||||||||||||||||||
Capital securities and accrued return(d) | 364 | — | 367 | — | 344 | — | ||||||||||||||||||
Share capital and contributed surplus(g)(h) | 3,406 | 3,640 | 3,397 | 3,631 | 3,388 | 3,622 | ||||||||||||||||||
Accumulated other comprehensive income(e)(j) | — | (17 | ) | — | 3 | — | — | |||||||||||||||||
Retained earnings (deficit) | 1,357 | 683 | 722 | 23 | 253 | (124 | ) | |||||||||||||||||
$ | 10,575 | $ | 10,051 | $ | 9,370 | $ | 8,739 | $ | 8,829 | $ | 8,624 | |||||||||||||
2001 and 2000 amounts as restated (notes 3 and 16 (b)). |
Condensed Consolidated Statements of Retained Earnings (Deficit) and Comprehensive Income
2002 | 2001 | 2000 | ||||||||||||||||||||||
Canadian GAAP | U.S. GAAP | Canadian GAAP | U.S. GAAP | Canadian GAAP | U.S. GAAP | |||||||||||||||||||
Retained earnings (deficit), beginning of year | $ | 722 | $ | 23 | $ | 253 | $ | (124 | ) | $ | (295 | ) | $ | (571 | ) | |||||||||
Net earnings | 804 | 811 | 654 | 297 | 438 | 447 | ||||||||||||||||||
Dividends on common shares and other | (151 | ) | (151 | ) | (150 | ) | (150 | ) | 152 | — | ||||||||||||||
Capital securities, net of tax and foreign exchange (d) | (18 | ) | — | (35 | ) | — | (27 | ) | — | |||||||||||||||
Foreign exchange(b) | — | — | — | — | (15 | ) | — | |||||||||||||||||
Retained earnings (deficit), end of year | $ | 1,357 | $ | 683 | $ | 722 | $ | 23 | $ | 253 | $ | (124 | ) | |||||||||||
Other comprehensive income, beginning of year | $ | — | $ | 3 | $ | — | $ | — | $ | — | $ | — | ||||||||||||
Cumulative effect of change in accounting, net of tax(e) | — | — | — | (10 | ) | — | — | |||||||||||||||||
Cash flow hedges, net of tax(e) | — | (10 | ) | — | 13 | — | — | |||||||||||||||||
Minimum pension liability, net of tax(j) | — | (10 | ) | — | — | — | — | |||||||||||||||||
Other comprehensive income, end of year | $ | — | $ | (17 | ) | $ | — | $ | 3 | $ | — | $ | — | |||||||||||
2001 and 2000 amounts as restated (notes 3 and 16 (b)). |
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Condensed Consolidated Statements of Earnings
2002 | 2001 | 2000 | ||||||||||||||||||||||
Canadian GAAP | U.S. GAAP | Canadian GAAP | U.S. GAAP | Canadian GAAP | U.S. GAAP | |||||||||||||||||||
Sales and operating revenues(e)(i) | $ | 6,384 | $ | 5,778 | $ | 6,596 | $ | 5,606 | $ | 5,066 | $ | 4,628 | ||||||||||||
Costs and expenses(b)(d)(e)(i) | 4,117 | 3,488 | 4,614 | 3,654 | 3,683 | 3,263 | ||||||||||||||||||
Depletion, depreciation and amortization(a) | 939 | 851 | 807 | 1,351 | 481 | 455 | ||||||||||||||||||
Interest, net(d) | 104 | 136 | 101 | 134 | 101 | 131 | ||||||||||||||||||
Earnings before income taxes | 1,224 | 1,303 | 1,074 | 467 | 801 | 779 | ||||||||||||||||||
Income taxes(a)(b)(c)(d)(e)(f) | 420 | 492 | 420 | 176 | 363 | 332 | ||||||||||||||||||
Net earnings, before cumulative effect of change in accounting | 804 | 811 | 654 | 291 | 438 | 447 | ||||||||||||||||||
Change in accounting, net of tax(e) | — | — | — | 6 | — | — | ||||||||||||||||||
Net earnings | $ | 804 | $ | 811 | $ | 654 | $ | 297 | $ | 438 | $ | 447 | ||||||||||||
2001 and 2000 amounts as restated (notes 3 and 16 (b)). |
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 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) | Effective January 1, 2002, the Company retroactively adopted the revised recommendations of the CICA on Foreign Currency Translation (note 3). The new recommendations eliminated the deferral and amortization of foreign exchange gains and losses on long-term monetary items. The Company records the gain or loss on the capital securities as a charge to retained earnings. Under U.S. GAAP, gains or losses on translation of foreign denominated long-term monetary items, including those on capital securities, are credited or charged to earnings immediately. | |
(c) | Prior to 2000 the Company expensed costs related to medical and dental post-retirement benefits as incurred. Effective January 1, 2000 the Company retroactively adopted, without restatement, the new recommendations issued by the CICA on accounting for employee future benefits which are consistent with those under U.S. GAAP, which requires use of the projected benefit method prorated based on service. | |
(d) | The Company records the capital securities as a component of equity and the return 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 would be charged to earnings. | |
(e) | 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 $20.3 million and $10.0 million, respectively, and a resulting cumulative catch-up adjustment to increase earnings by $5.7 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 $3.8 million and $23.0 million, respectively, and a resulting reduction of other comprehensive income within shareholders’ equity of $10.6 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 $7.4 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 |
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between carrying and fair values of the hedged items was also recorded. The effect of the cumulative catch-up adjustment was to increase net earnings per share under U.S. GAAP by $0.01 (basic and diluted). | ||
At December 31, 2002 the Company recorded additional assets and liabilities for U.S. GAAP purposes of $110.6 million and $122.1 million, respectively, for the fair values of derivative financial instruments. During 2002, a gain of $11.0 million, net of tax, 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 gain of $1.3 million, net of tax, 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 $10.1 million gain, net of tax, 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 2002. | ||
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 (“EITF”) 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, the Company recorded additional assets and liabilities of $37.0 million and $19.3 million, respectively, at December 31, 2002 and included the resulting unrealized gain in earnings for the year. | ||
Under U.S. GAAP, gains and losses on energy trading contracts have been netted against sales and operating revenues. All prior periods have been reclassified to conform with this change. | ||
(f) | The Canadian GAAP liability method of accounting for income taxes 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 on August 25, 2000, the deficit of Husky Oil Limited 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 2002 were $256 million (2001 — $272 million; 2000 — $159 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 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. |
Additional U.S. GAAP Disclosures
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.
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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 2002, 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, 2002. During 2002, 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 when the options were granted, no compensation expense has been charged to income at the time of the option grants. 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 net earnings per share for the years ended December 31, 2002, 2001 and 2000 would have been the pro forma amounts indicated below:
2002 | 2001 | 2000 | |||||||||||||||||||||||
As Reported | Pro Forma | As Reported | Pro Forma | As Reported | Pro Forma | ||||||||||||||||||||
Net earnings | $ | 811 | $ | 798 | $ | 297 | $ | 284 | $ | 447 | $ | 443 | |||||||||||||
Net earnings per share | — Basic | $ | 1.94 | $ | 1.91 | $ | 0.71 | $ | 0.68 | $ | 1.39 | $ | 1.38 | ||||||||||||
— Diluted | $ | 1.93 | $ | 1.90 | $ | 0.71 | $ | 0.68 | $ | 1.39 | $ | 1.38 |
The fair values of all common share options granted are estimated on the date of grant using the Modified 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 note 11.
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 for the years ended December 31 were as follows:
2002 | 2001 | 2000 | ||||||||||
Depletion, depreciation and amortization per boe(1) | $ | 6.96 | $ | 6.88 | $ | 5.88 |
(1) | Excludes the 2001 ceiling test write down. |
Impairment or Disposal of Long-term Assets
In August 2001, the FASB issued FAS 144 “Accounting for the Impairment or Disposal of Long-term Assets”, which addresses the financial accounting and reporting for the impairment or disposal of long-lived assets. FAS 144 supersedes but retains the basic principles of FASB Statement No. 121 for the impairment of assets to be held and used. A two-step process is used to determine the impairment of the Company’s long-term assets, other than assets covered by the full cost accounting policy, with the first step determining when impairment is recognized and the second step measuring the amount of the impairment. An impairment loss is recognized when the carrying amount of a long-lived asset exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. An impairment loss is measured as the amount by which the long-lived asset’s carrying value exceeds its fair value. 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
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results of operations of a component of an entity that has been disposed of, or is classified as held for sale, is reported in discontinued operations if:
(a) | The operations and cash flows of the component have been or will be eliminated as a result of the disposal transaction, and; | |
(b) | 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.
This standard was adopted prospectively on January 1, 2002. It did not result in any differences between Canadian and U.S. GAAP in 2002.
Accounting for Guarantees
In November 2002, the FASB issued Financial Interpretation 45 “Accounting for Guarantees” (“FIN 45”) that will require the recognition of a liability for the fair value of certain guarantees that require payments contingent on specified types of future events. The measurement standards of FIN 45 are applicable to guarantees entered into after January 1, 2003. For guarantees that existed as at December 31, 2002, FIN 45 requires additional disclosures which have been included in these financial statements to the extent applicable to the Company.
Accounting for Variable Interest Entities
In January 2003, the FASB issued Financial Interpretation 46 “Accounting for Variable Interest Entities” (“FIN 46”) that will require the consolidation of certain entities that are controlled through financial interests that indicate control (referred to as “variable interests”). Variable interests are the rights or obligations that convey economic gains or losses from changes in the values of the entity’s assets or liabilities. The holder of the majority of an entity’s variable interests will be required to consolidate the variable interest entity. The Company does not believe FIN 46 will result in the consolidation of any additional entities that existed at December 31, 2002.
Future Removal and Site Restoration
In June 2001, the FASB issued Statement No. 143 “Accounting for Asset Retirement Obligations” (“FAS 143”), which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the related asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and use of the asset. FAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset. The liability is accreted at the end of each period through charges to operating expenses. The Company is required and plans to adopt the provisions of FAS 143 for the quarter ending March 31, 2003. The change will result in an increase to net property, plant and equipment of $56 million, an increase in future removal and site restoration liability of $58 million, a decrease to the future tax liability of $1 million and a decrease to retained earnings of $1 million.
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SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION
Oil and Gas Producing Activities (unaudited)
The following disclosures have been prepared in accordance with FASB Statement No. 69 “Disclosures about Oil and Gas Producing Activities” (“FAS 69”):
Oil and Gas Reserves
Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Canadian provincial royalties are determined based on a graduated percentage scale which varies with prices and production volumes. Canadian reserves, as presented on a net basis, assume prices and royalty rates in existence at the time the estimates were made, and the Company’s estimate of future production volumes. Future fluctuations in prices, production rates, or changes in political or regulatory environments could cause the Company’s share of future production from Canadian reserves to be materially different from that presented.
Subsequent to December 31, 2002 no major discovery or other favourable or adverse event is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.
Results of Operations for Producing Activities
The following table sets forth revenue and direct cost information relating to the Company’s oil and gas producing activities for the years ended December 31:
Results of Operations
Canada(1) | International(1) | Total(1) | |||||||||||||||||||||||||||||||||||||||
($ millions) | 2002 | 2001 | 2000 | 2002 | 2001 | 2000 | 2002 | 2001 | 2000 | ||||||||||||||||||||||||||||||||
Revenue | |||||||||||||||||||||||||||||||||||||||||
Sales | $ | 1,738 | $ | 1,771 | $ | 1,158 | $ | 190 | $ | 4 | $ | 4 | $ | 1,928 | $ | 1,775 | $ | 1,162 | |||||||||||||||||||||||
Transfers | 737 | 390 | 387 | — | — | — | 737 | 390 | 387 | ||||||||||||||||||||||||||||||||
2,475 | 2,161 | 1,545 | 190 | 4 | 4 | 2,665 | 2,165 | 1,549 | |||||||||||||||||||||||||||||||||
Deduct | |||||||||||||||||||||||||||||||||||||||||
Production costs | 676 | 617 | 345 | 10 | — | 1 | 686 | 617 | 346 | ||||||||||||||||||||||||||||||||
Depletion, depreciation and amortization | 813 | 721 | 398 | 38 | 7 | 9 | 851 | 728 | 407 | ||||||||||||||||||||||||||||||||
Income taxes | 387 | 334 | 326 | 64 | (1 | ) | (3 | ) | 451 | 333 | 323 | ||||||||||||||||||||||||||||||
1,876 | 1,672 | 1,069 | 112 | 6 | 7 | 1,988 | 1,678 | 1,076 | |||||||||||||||||||||||||||||||||
Results of operations from producing activities | $ | 599 | $ | 489 | $ | 476 | $ | 78 | $ | (2 | ) | $ | (3 | ) | $ | 677 | $ | 487 | $ | 473 | |||||||||||||||||||||
Depletion, depreciation and amortization rates per gross equivalent barrel | $ | 7.74 | $ | 7.24 | $ | 6.15 | $ | 8.33 | $ | 80.61 | $ | 90.39 | $ | 7.76 | $ | 7.31 | $ | 6.28 | |||||||||||||||||||||||
(1) | The costs in this schedule exclude corporate overhead, interest expense and other operating costs which are not directly related to producing activities. |
Page 51
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
Capitalized costs incurred in oil and gas producing activities for the years ended December 31 were as follows:
Costs Incurred
($ millions) | 2002 | 2001 | 2000 | ||||||||||||
Property acquisition costs(1)(2)(3) | |||||||||||||||
Proved | — Canada | $ | 20 | $ | 366 | $ | 3,200 | ||||||||
Unproved | — Canada | 88 | 55 | 355 | |||||||||||
108 | 421 | 3,555 | |||||||||||||
Exploration costs | — Canada | 257 | 262 | 159 | |||||||||||
— Other | 9 | 5 | 3 | ||||||||||||
266 | 267 | 162 | |||||||||||||
Development costs | — Canada | 1,127 | 774 | 412 | |||||||||||
— China | 66 | 99 | 85 | ||||||||||||
1,193 | 873 | 497 | |||||||||||||
$ | 1,567 | $ | 1,561 | $ | 4,214 | ||||||||||
(1) | Property acquisition costs related to corporate acquisitions for proved properties in 2002 were nil; 2001 included $244 million. | |
(2) | Property acquisition costs in 2000 included $3,181 million for proved properties and $333 million for unproved properties related to the acquisition of Renaissance. | |
(3) | Property acquisition costs in 2000 excluded $135 million for proved properties and $19 million for unproved properties related to property exchanges. |
Acquisition costs include costs incurred to purchase, lease, or otherwise acquire oil and gas properties.
Exploration costs include the costs of geological and geophysical activity, retaining undeveloped properties and drilling and equipping exploration wells.
Development costs include the costs of drilling and equipping development wells and facilities to extract, treat and gather and store oil and gas.
Exploration and development costs include administrative costs and depreciation of support equipment directly associated with these activities.
The following table sets forth a summary of oil and gas property costs not being amortized at December 31:
Withheld Costs
($ millions) | Total | 2002 | 2001 | 2000 | Prior to 2000 | |||||||||||||||||||
Property acquisition | — Canada | $ | 414 | $ | 37 | $ | 17 | $ | 251 | $ | 109 | |||||||||||||
— International | 14 | — | — | — | 14 | |||||||||||||||||||
428 | 37 | 17 | 251 | 123 | ||||||||||||||||||||
Exploration | — Canada | 271 | 79 | 57 | 48 | 87 | ||||||||||||||||||
— International | 6 | 6 | — | — | — | |||||||||||||||||||
277 | 85 | 57 | 48 | 135 | ||||||||||||||||||||
Development | — Canada | 487 | 392 | 83 | 12 | — | ||||||||||||||||||
— International | 17 | 1 | — | — | 16 | |||||||||||||||||||
504 | 393 | 83 | 12 | 16 | ||||||||||||||||||||
Capitalized interest | — Canada | 146 | 26 | 51 | 43 | 26 | ||||||||||||||||||
$ | 1,355 | $ | 541 | $ | 208 | $ | 354 | $ | 252 | |||||||||||||||
Page 52
Capitalized Costs Relating to Oil and Gas Producing Activities
The capitalized costs and related accumulated depletion, depreciation and amortization, including impairments, relating to the Company’s oil and gas exploration, development and producing activities at December 31 consisted of:
Capitalized Costs
($ millions) | 2002 | 2001(1) | 2000(1) | |||||||||||||
Unproved oil and gas properties | — Canada | $ | 1,318 | $ | 1,052 | $ | 951 | |||||||||
— International | 37 | 235 | 137 | |||||||||||||
1,355 | 1,287 | 1,088 | ||||||||||||||
Proved oil and gas properties | — Canada | 10,207 | 9,301 | 8,072 | ||||||||||||
— International | 432 | 159 | 153 | |||||||||||||
10,639 | 9,460 | 8,225 | ||||||||||||||
11,994 | 10,747 | 9,313 | ||||||||||||||
Less accumulated depletion, depreciation and amortization | — Canada | 3,894 | 3,272 | 2,622 | ||||||||||||
— International | 185 | 147 | 139 | |||||||||||||
4,079 | 3,419 | 2,761 | ||||||||||||||
$ | 7,915 | $ | 7,328 | $ | 6,552 | |||||||||||
Net capitalized costs | — Canada | $ | 7,631 | $ | 7,081 | $ | 6,401 | |||||||||
— International | 284 | 247 | 151 | |||||||||||||
$ | 7,915 | $ | 7,328 | $ | 6,552 | |||||||||||
(1) | Capital related to 17 mmbbls of proved reserves at Terra Nova transferred to proved oil and gas properties. Terra Nova is a major development project off the East Coast of Canada. |
Page 53
Oil and Gas Reserve Information
In Canada, the Company’s proved crude oil, natural gas liquids, natural gas and sulphur reserves are located in the provinces of Alberta, Saskatchewan and British Columbia, and offshore the East Coast. The Company’s international proved reserves are located in Indonesia, China and Libya. The Company’s proved developed and undeveloped reserves after deductions of royalties are summarized below:
Reserves
Canada | International | Total | |||||||||||||||||||||||||||||||||||
Crude | Crude | Crude | |||||||||||||||||||||||||||||||||||
Oil & NGL | Natural Gas | Sulphur | Oil & NGL | Natural Gas | Oil & NGL | Natural Gas | Sulphur | ||||||||||||||||||||||||||||||
Net proved developed and undeveloped reserves, after royalties(1)(2)(3)(4) | (mmbbls) | (bcf) | (mmlt) | (mmbbls) | (bcf) | (mmbbls) | (bcf) | (mmlt) | |||||||||||||||||||||||||||||
End of year 1999 | 212.1 | 771.7 | 5.0 | 5.9 | 110.5 | 218.0 | 882.2 | 5.0 | |||||||||||||||||||||||||||||
Revisions | 12.9 | (59.1 | ) | — | (0.1 | ) | (0.4 | ) | 12.8 | (59.5 | ) | — | |||||||||||||||||||||||||
Purchases | 215.6 | 789.0 | — | — | — | 215.6 | 789.0 | — | |||||||||||||||||||||||||||||
Discoveries and extensions | 41.5 | 35.4 | — | 29.4 | — | 70.9 | 35.4 | — | |||||||||||||||||||||||||||||
Production | (36.6 | ) | (102.4 | ) | (0.3 | ) | (0.1 | ) | — | (36.7 | ) | (102.4 | ) | (0.3 | ) | ||||||||||||||||||||||
End of year 2000 | 445.5 | 1,434.6 | 4.7 | 35.1 | 110.1 | 480.6 | 1,544.7 | 4.7 | |||||||||||||||||||||||||||||
Revisions | 37.0 | 74.0 | 0.1 | 0.7 | 5.1 | 37.7 | 79.1 | 0.1 | |||||||||||||||||||||||||||||
Purchases | 33.6 | 20.4 | — | — | — | 33.6 | 20.4 | — | |||||||||||||||||||||||||||||
Sales | (1.6 | ) | (18.4 | ) | — | — | — | (1.6 | ) | (18.4 | ) | — | |||||||||||||||||||||||||
Discoveries and extensions | 44.8 | 200.1 | 0.1 | 1.1 | — | 45.9 | 200.1 | 0.1 | |||||||||||||||||||||||||||||
Production | (56.3 | ) | (152.1 | ) | (0.2 | ) | (0.1 | ) | — | (56.4 | ) | (152.1 | ) | (0.2 | ) | ||||||||||||||||||||||
End of year 2001 | 503.0 | 1,558.6 | 4.7 | 36.8 | 115.2 | 539.8 | 1,673.8 | 4.7 | |||||||||||||||||||||||||||||
Revisions | — | 14.7 | 0.3 | (0.8 | ) | (14.3 | ) | (0.8 | ) | 0.4 | 0.3 | ||||||||||||||||||||||||||
Purchases | 4.2 | 5.4 | — | — | — | 4.2 | 5.4 | — | |||||||||||||||||||||||||||||
Sales | (14.5 | ) | (16.6 | ) | — | — | — | (14.5 | ) | (16.6 | ) | — | |||||||||||||||||||||||||
Discoveries and extensions | 37.2 | 205.4 | — | 1.1 | — | 38.3 | 205.4 | — | |||||||||||||||||||||||||||||
Production | (61.8 | ) | (155.7 | ) | (0.4 | ) | (4.3 | ) | — | (66.1 | ) | (155.7 | ) | (0.4 | ) | ||||||||||||||||||||||
End of year 2002 | 468.1 | 1,611.8 | 4.6 | 32.8 | 100.9 | 500.9 | 1,712.7 | 4.6 | |||||||||||||||||||||||||||||
Net proved developed reserves, after royalties(1)(2)(3)(4) | |||||||||||||||||||||||||||||||||||||
End of year 1999 | 161.8 | 669.3 | 4.8 | 0.6 | — | 162.4 | 669.3 | 4.8 | |||||||||||||||||||||||||||||
End of year 2000 | 345.2 | 1,275.5 | 4.5 | 0.5 | — | 345.7 | 1,275.5 | 4.5 | |||||||||||||||||||||||||||||
End of year 2001 | 378.1 | 1,342.2 | 4.6 | 0.6 | — | 378.7 | 1,342.2 | 4.6 | |||||||||||||||||||||||||||||
End of year 2002 | 360.9 | 1,272.8 | 3.7 | 28.2 | — | 389.1 | 1,272.8 | 3.7 | |||||||||||||||||||||||||||||
(1) | Net reserves are the Company’s lessor royalty, overriding royalty and working interest share of the gross remaining reserves, after deduction of any crown, freehold and overriding royalties. Such royalties are subject to change by legislation or regulation and can also vary depending on production rates, selling prices and timing of initial production. | |
(2) | Reserves are the estimated quantities of crude oil, natural gas and related substances anticipated from geological and engineering data to be recoverable from known accumulations from a given date forward, by known technology, under existing operating conditions and prices in effect at year-end. | |
(3) | Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. | |
(4) | Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves that are expected to be recovered from known accumulations where a significant expenditure is required. |
Page 54
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following information has been developed utilizing procedures prescribed by FAS 69 and based on crude oil and natural gas reserve and production volumes estimated by the engineering staff of the Company. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of the Company’s reserves.
The future cash flows presented below are based on sales prices, cost rates, and statutory income tax rates in existence as of the date of the projections. It is expected that material revisions to some estimates of crude oil and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.
Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.
The computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2002 was based on the NYMEX year-end natural gas spot price of U.S. $4.60/mmbtu (2001 — U.S. $2.75/mmbtu; 2000 — U.S. $10.53/mmbtu) and on crude oil prices computed with reference to the year-end West Texas Intermediate price of U.S. $31.21/bbl (2001 — U.S. $19.96/bbl; 2000 — U.S. $26.72/bbl).
Page 55
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (continued)
The following table sets forth the standardized measure of discounted future net cash flows from projected production of the Company’s crude oil and natural gas reserves at December 31, for the years presented.
Standardized Measure
Canada(1) | International(1) | Total(1) | |||||||||||||||||||||||||||||||||||
($ millions) | 2002 | 2001 | 2000 | 2002 | 2001 | 2000 | 2002 | 2001 | 2000 | ||||||||||||||||||||||||||||
Future cash inflows | $ | 25,830 | $ | 14,102 | $ | 23,701 | $ | 2,719 | $ | 1,600 | $ | 1,787 | $ | 28,549 | $ | 15,702 | $ | 25,488 | |||||||||||||||||||
Future costs | |||||||||||||||||||||||||||||||||||||
Future production and development costs | 7,239 | 7,541 | 5,996 | 502 | 523 | 609 | 7,741 | 8,064 | 6,605 | ||||||||||||||||||||||||||||
Future income taxes | 7,278 | 2,540 | 7,384 | 860 | 310 | 402 | 8,138 | 2,850 | 7,786 | ||||||||||||||||||||||||||||
Future net cash flows | 11,313 | 4,021 | 10,321 | 1,357 | 767 | 776 | 12,670 | 4,788 | 11,097 | ||||||||||||||||||||||||||||
Deduct 10% annual discount factor | 4,966 | 1,667 | 4,859 | 518 | 329 | 404 | 5,484 | 1,996 | 5,263 | ||||||||||||||||||||||||||||
Standardized measure of discounted future net cash flows | $ | 6,347 | $ | 2,354 | $ | 5,462 | $ | 839 | $ | 438 | $ | 372 | $ | 7,186 | $ | 2,792 | $ | 5,834 | |||||||||||||||||||
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, for the years presented.
Changes in Standardized Measure
Canada(1) | International(1) | Total(1) | ||||||||||||||||||||||||||||||||||
($ millions) | 2002 | 2001 | 2000 | 2002 | 2001 | 2000 | 2002 | 2001 | 2000 | |||||||||||||||||||||||||||
Present value at January 1 | $ | 2,354 | $ | 5,462 | $ | 1,612 | $ | 438 | $ | 372 | $ | 72 | $ | 2,792 | $ | 5,834 | $ | 1,684 | ||||||||||||||||||
Sales and transfers, net of production costs | (1,802 | ) | (1,556 | ) | (1,204 | ) | (179 | ) | (2 | ) | (3 | ) | (1,981 | ) | (1,558 | ) | (1,207 | ) | ||||||||||||||||||
Net change in sales and transfer prices, net of development and production costs | 7,752 | (5,843 | ) | 2,159 | 732 | (48 | ) | 18 | 8,484 | (5,891 | ) | 2,177 | ||||||||||||||||||||||||
Extensions, discoveries and improved recovery, net of related costs | 676 | 356 | 460 | 40 | 17 | 410 | 716 | 373 | 870 | |||||||||||||||||||||||||||
Revisions of quantity estimates | (30 | ) | 237 | 46 | (28 | ) | 10 | (2 | ) | (58 | ) | 247 | 44 | |||||||||||||||||||||||
Accretion of discount | 390 | 949 | 279 | 59 | 55 | 13 | 449 | 1,004 | 292 | |||||||||||||||||||||||||||
Sale of reserves in place | (189 | ) | (6 | ) | (3 | ) | — | — | — | (189 | ) | (6 | ) | (3 | ) | |||||||||||||||||||||
Purchase of reserves in place | 45 | 174 | 5,681 | — | — | — | 45 | 174 | 5,681 | |||||||||||||||||||||||||||
Changes in timing of future net cash flows and other | (191 | ) | 95 | (717 | ) | 80 | 10 | 3 | (111 | ) | 105 | (714 | ) | |||||||||||||||||||||||
Net change in income taxes | (2,658 | ) | 2,486 | (2,851 | ) | (303 | ) | 24 | (139 | ) | (2,961 | ) | 2,510 | (2,990 | ) | |||||||||||||||||||||
Present value at December 31 | $ | 6,347 | $ | 2,354 | $ | 5,462 | $ | 839 | $ | 438 | $ | 372 | $ | 7,186 | $ | 2,792 | $ | 5,834 | ||||||||||||||||||
(1) | The schedules above are calculated using year-end prices, costs, statutory income tax rates and existing proved oil and gas reserves. The value of exploration properties and probable reserves, future exploration costs, future changes in oil and gas prices and in production and development costs are excluded. | |
Page 56
Reserve Information
Reserve Reconciliation
Canada | International | ||||||||||||||||||||||||||||||||
Western Canada | East Coast | Total | |||||||||||||||||||||||||||||||
Light/Med. | Lloydminster | Light | |||||||||||||||||||||||||||||||
Crude Oil | Heavy Crude | Natural | Light | Crude Oil | Natural | Crude Oil | Natural | ||||||||||||||||||||||||||
& NGL | Oil | Gas | Crude Oil | & NGL | Gas | & NGL | Gas | ||||||||||||||||||||||||||
Proved reserves, before royalties(1) | (mmbbls) | (mmbbls) | (bcf) | (mmbbls) | (mmbbls) | (bcf) | (mmbbls) | (bcf) | |||||||||||||||||||||||||
Proved reserves at December 31, 1999 | 138.3 | 105.0 | 933.9 | — | 7.0 | 142..9 | 250.3 | 1,076.8 | |||||||||||||||||||||||||
Revisions | 3.6 | 6.6 | (17.2 | ) | — | — | — | 10.2 | (17.2 | ) | |||||||||||||||||||||||
Purchases (includes Renaissance) | 258.5 | 0.3 | 933.4 | — | — | — | 258.8 | 933.4 | |||||||||||||||||||||||||
Discoveries, extensions and improved recovery | 12.7 | 21.4 | 47.0 | 11.3 | 32.2 | — | 77.6 | 47.0 | |||||||||||||||||||||||||
Production | (23.2 | ) | (19.6 | ) | (131.0 | ) | — | (0.1 | ) | — | (42.9 | ) | (131.0 | ) | |||||||||||||||||||
Proved reserves at December 31, 2000 | 389.9 | 113.7 | 1,766.1 | 11.3 | 39.1 | 142.9 | 554.0 | 1,909.0 | |||||||||||||||||||||||||
Revisions | 0.8 | 24.9 | 22.5 | 1.2 | 0.2 | — | 27.1 | 22.5 | |||||||||||||||||||||||||
Purchases | 11.9 | 23.7 | 23.7 | — | — | — | 35.6 | 23.7 | |||||||||||||||||||||||||
Sales | (1.8 | ) | — | (21.1 | ) | — | — | — | (1.8 | ) | (21.1 | ) | |||||||||||||||||||||
Discoveries, extensions and improved recovery | 13.3 | 30.0 | 240.7 | 4.8 | 1.2 | — | 49.3 | 240.7 | |||||||||||||||||||||||||
Production | (41.5 | ) | (23.2 | ) | (209.0 | ) | — | (0.1 | ) | — | (64.8 | ) | (209.0 | ) | |||||||||||||||||||
Proved reserves at December 31, 2001 | 372.6 | 169.1 | 1,822.9 | 17.3 | 40.4 | 142.9 | 599.4 | 1,965.8 | |||||||||||||||||||||||||
Revisions | (6.5 | ) | 18.4 | (37.2 | ) | — | — | — | 11.9 | (37.2 | ) | ||||||||||||||||||||||
Purchases | 0.5 | 4.4 | 6.2 | — | — | — | 4.9 | 6.2 | |||||||||||||||||||||||||
Sales | (16.4 | ) | — | (19.0 | ) | — | — | — | (16.4 | ) | (19.0 | ) | |||||||||||||||||||||
Discoveries, extensions and improved recovery | 6.9 | 17.8 | 386.5 | 18.5 | 1.2 | — | 44.4 | 386.5 | |||||||||||||||||||||||||
Production | (36.7 | ) | (29.0 | ) | (207.8 | ) | (4.8 | ) | (4.5 | ) | — | (75.0 | ) | (207.8 | ) | ||||||||||||||||||
Proved reserves at December 31, 2002 | 320.4 | 180.7 | 1,951.6 | 31.0 | 37.1 | 142.9 | 569.2 | 2,094.5 | |||||||||||||||||||||||||
Proved developed reserves, before royalties(2) | |||||||||||||||||||||||||||||||||
December 31, 1999 | 132.2 | 56.4 | 817.6 | — | 0.6 | — | 189.2 | 817.6 | |||||||||||||||||||||||||
December 31, 2000 | 337.8 | 64.8 | 1,579.9 | — | 0.5 | — | 403.1 | 1,579.9 | |||||||||||||||||||||||||
December 31, 2001 | 322.5 | 95.8 | 1,576.5 | 6.2 | 0.6 | — | 425.1 | 1,576.5 | |||||||||||||||||||||||||
December 31, 2002 | 284.5 | 116.3 | 1,546.5 | 7.4 | 30.7 | — | 438.9 | 1,546.5 | |||||||||||||||||||||||||
Probable reserves, before royalties(3) | |||||||||||||||||||||||||||||||||
December 31, 1999 | 64.6 | 78.0 | 235.9 | 256.3 | 0.9 | 18.9 | 399.8 | 254.8 | |||||||||||||||||||||||||
December 31, 2000 | 135.2 | 78.1 | 434.1 | 202.3 | 5.3 | 18.9 | 420.9 | 453.0 | |||||||||||||||||||||||||
December 31, 2001 | 131.8 | 81.2 | 405.6 | 213.3 | 4.2 | 18.9 | 430.5 | 424.5 | |||||||||||||||||||||||||
December 31, 2002 | 161.0 | 85.5 | 383.9 | 201.6 | 4.1 | 18.9 | 452.2 | 402.8 | |||||||||||||||||||||||||
(1) | Proved reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. | |
(2) | Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. | |
(3) | Probable reserves are considered to be those reserves which may be recoverable as a result of the beneficial effects which may be derived from the future institution of some form of pressure maintenance or other secondary recovery method, or as a result of a more favourable performance of the existing recovery mechanism than that which may reasonably be deemed proven at the present time, or those reserves which may reasonably be assumed to exist because of geophysical or geological indications and drilling done in regions which contain proved reserves. The risk associated with those reserves generally ranges from 40 to 80 percent. |
Page 57
Quarterly Financial and Operating Information
SEGMENTED OPERATIONAL INFORMATION
Upstream
2002 | 2001 | ||||||||||||||||||||||||||||||||||
Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | ||||||||||||||||||||||||||||
Daily production, before royalties | |||||||||||||||||||||||||||||||||||
Light/medium crude oil & NGL(mbbls/day) | 137.8 | 131.4 | 116.6 | 117.5 | 111.3 | 112.7 | 108.6 | 115.5 | |||||||||||||||||||||||||||
Lloydminster heavy crude oil(mbbls/day) | 83.9 | 80.0 | 76.9 | 76.9 | 75.0 | 69.1 | 60.3 | 56.9 | |||||||||||||||||||||||||||
221.7 | 211.4 | 193.5 | 194.4 | 186.3 | 181.8 | 168.9 | 172.4 | ||||||||||||||||||||||||||||
Natural gas(mmcf/day) | 577.4 | 561.6 | 571.8 | 566.0 | 568.7 | 567.1 | 570.8 | 584.0 | |||||||||||||||||||||||||||
Total production(mboe/day) | 317.9 | 305.1 | 288.9 | 288.7 | 281.1 | 276.3 | 264.0 | 269.7 | |||||||||||||||||||||||||||
Average realized sales prices | |||||||||||||||||||||||||||||||||||
Light/medium crude oil & NGL($/bbl) | $ | 36.64 | $ | 36.72 | $ | 32.42 | $ | 26.17 | $ | 19.44 | $ | 31.74 | $ | 28.86 | $ | 28.72 | |||||||||||||||||||
Lloydminster heavy crude oil($/bbl) | $ | 25.47 | $ | 30.94 | $ | 27.02 | $ | 20.68 | $ | 10.44 | $ | 23.65 | $ | 15.52 | $ | 13.81 | |||||||||||||||||||
Natural gas($/mcf) | $ | 4.76 | $ | 3.42 | $ | 3.98 | $ | 3.10 | $ | 3.01 | $ | 3.25 | $ | 6.57 | $ | 9.05 | |||||||||||||||||||
Operating costs($/boe) | $ | 6.66 | $ | 6.19 | $ | 6.19 | $ | 5.88 | $ | 6.54 | $ | 6.24 | $ | 6.19 | $ | 5.31 | |||||||||||||||||||
Operating netbacks(1) | |||||||||||||||||||||||||||||||||||
Light/medium crude oil & NGL($/boe) | $ | 24.29 | $ | 23.74 | $ | 20.40 | $ | 15.19 | $ | 7.43 | $ | 18.03 | $ | 17.01 | $ | 18.09 | |||||||||||||||||||
Lloydminster heavy crude oil($/boe) | $ | 13.22 | $ | 20.63 | $ | 17.81 | $ | 12.46 | $ | 3.29 | $ | 14.04 | $ | 6.08 | $ | 4.87 | |||||||||||||||||||
Natural gas($/mcfge) | $ | 3.18 | $ | 2.19 | $ | 2.39 | $ | 2.03 | $ | 1.74 | $ | 1.99 | $ | 4.28 | $ | 6.05 | |||||||||||||||||||
Total($/boe) | $ | 19.71 | $ | 19.67 | $ | 17.67 | $ | 13.47 | $ | 7.34 | $ | 14.88 | $ | 17.62 | $ | 21.97 | |||||||||||||||||||
Net wells drilled(2) | |||||||||||||||||||||||||||||||||||
Exploration | Oil | 3 | 6 | 6 | 5 | 8 | 8 | 15 | 45 | ||||||||||||||||||||||||||
Gas | 14 | 16 | 18 | 83 | 6 | 11 | 5 | 68 | |||||||||||||||||||||||||||
Dry | 2 | 2 | 1 | 9 | 4 | 2 | 3 | 25 | |||||||||||||||||||||||||||
19 | 24 | 25 | 97 | 18 | 21 | 23 | 138 | ||||||||||||||||||||||||||||
Development | Oil | 107 | 190 | 112 | 44 | 116 | 195 | 129 | 102 | ||||||||||||||||||||||||||
Gas | 160 | 67 | 10 | 216 | 53 | 57 | 17 | 94 | |||||||||||||||||||||||||||
Dry | 17 | 14 | 6 | 18 | 11 | 23 | 7 | 22 | |||||||||||||||||||||||||||
284 | 271 | 128 | 278 | 180 | 275 | 153 | 218 | ||||||||||||||||||||||||||||
303 | 295 | 153 | 375 | 198 | 296 | 176 | 356 | ||||||||||||||||||||||||||||
Success ratio(percent) | 94 | 95 | 95 | 93 | 92 | 92 | 95 | 87 | |||||||||||||||||||||||||||
Midstream
2002 | 2001 | |||||||||||||||||||||||||||||||
Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | |||||||||||||||||||||||||
Synthetic crude oil sales(mbbls/day) | 67.5 | 47.3 | 51.3 | 71.2 | 49.7 | 66.5 | 65.6 | 56.2 | ||||||||||||||||||||||||
Upgrading differential($/bbl) | $ | 13.06 | $ | 9.92 | $ | 10.43 | $ | 9.85 | $ | 16.85 | $ | 13.18 | $ | 19.56 | $ | 21.61 | ||||||||||||||||
Pipeline throughput(mbbls/day) | 476 | 436 | 448 | 469 | 518 | 498 | 583 | 550 |
Refined Products
2002 | 2001 | |||||||||||||||||||||||||||||||||
Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | |||||||||||||||||||||||||||
Refined product sales volumes | ||||||||||||||||||||||||||||||||||
Light oil products(million litres/day) | 7.9 | 8.2 | 7.4 | 7.2 | 7.5 | 8.2 | 7.3 | 7.4 | ||||||||||||||||||||||||||
Asphalt products(mbbls/day) | 14.2 | 30.6 | 20.5 | 17.7 | 19.9 | 29.9 | 20.6 | 15.0 | ||||||||||||||||||||||||||
Refinery throughput | ||||||||||||||||||||||||||||||||||
Lloydminster refinery(mbbls/day) | 17.8 | 25.2 | 19.9 | 25.2 | 25.8 | 26.1 | 20.5 | 22.2 | ||||||||||||||||||||||||||
Prince George refinery(mbbls/day) | 10.9 | 11.0 | 7.7 | 10.9 | 10.2 | 8.8 | 10.7 | 10.9 | ||||||||||||||||||||||||||
Refinery utilization(percent) | 82 | 103 | 79 | 103 | 103 | 100 | 89 | 95 |
(1) | Operating netbacks are Husky’s average realized prices less royalties, hedging (gains)/losses and operating costs on a per unit basis. | |
(2) | Western Canada. |
Page 58
Segmented Financial Information
($ millions)
Upstream | Midstream | ||||||||||||||||||||||||||||||||||||||||||||||||
Upgrading | Infrastructure and Marketing | ||||||||||||||||||||||||||||||||||||||||||||||||
2002 | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | |||||||||||||||||||||||||||||||||||||
Sales and operating revenues, net of royalties | $ | 781 | $ | 738 | $ | 635 | $ | 511 | $ | 301 | $ | 192 | $ | 195 | $ | 221 | $ | 1,367 | $ | 953 | $ | 958 | $ | 952 | |||||||||||||||||||||||||
Costs and expenses | |||||||||||||||||||||||||||||||||||||||||||||||||
Operating, cost of sales, selling and general | 206 | 189 | 171 | 163 | 265 | 183 | 182 | 181 | 1,321 | 905 | 916 | 896 | |||||||||||||||||||||||||||||||||||||
Depletion, depreciation and amortization | 231 | 218 | 202 | 200 | 5 | 4 | 4 | 5 | 6 | 5 | 5 | 4 | |||||||||||||||||||||||||||||||||||||
Interest — net | — | — | — | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||
Foreign exchange | — | — | — | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||
437 | 407 | 373 | 363 | 270 | 187 | 186 | 186 | 1,327 | 910 | 921 | 900 | ||||||||||||||||||||||||||||||||||||||
Earnings (loss) before income taxes | 344 | 331 | 262 | 148 | 31 | 5 | 9 | 35 | 40 | 43 | 37 | 52 | |||||||||||||||||||||||||||||||||||||
Current income taxes | 26 | 8 | 1 | 20 | — | 1 | — | — | (19 | ) | 13 | 4 | 8 | ||||||||||||||||||||||||||||||||||||
Future income taxes | 108 | 117 | 83 | 34 | 11 | 2 | 2 | 10 | 31 | 5 | 10 | 13 | |||||||||||||||||||||||||||||||||||||
Net earnings (loss) | $ | 210 | $ | 206 | $ | 178 | $ | 94 | $ | 20 | $ | 2 | $ | 7 | $ | 25 | $ | 28 | $ | 25 | $ | 23 | $ | 31 | |||||||||||||||||||||||||
Capital employed(2) | $ | 6,040 | $ | 6,027 | $ | 6,001 | $ | 5,919 | $ | 319 | $ | 343 | $ | 324 | $ | 306 | $ | 431 | $ | 428 | $ | 194 | $ | 268 | |||||||||||||||||||||||||
Total assets | $ | 8,220 | $ | 8,105 | $ | 7,860 | $ | 7,723 | $ | 658 | $ | 665 | $ | 657 | $ | 640 | $ | 850 | $ | 871 | $ | 736 | $ | 845 | |||||||||||||||||||||||||
Upstream | Midstream | ||||||||||||||||||||||||||||||||||||||||||||||||
Upgrading | Infrastructure and Marketing | ||||||||||||||||||||||||||||||||||||||||||||||||
2001 | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | |||||||||||||||||||||||||||||||||||||
Sales and operating revenues, net of royalties | $ | 367 | $ | 549 | $ | 578 | $ | 671 | $ | 147 | $ | 255 | $ | 259 | $ | 225 | $ | 1,153 | $ | 796 | $ | 839 | $ | 1,592 | |||||||||||||||||||||||||
Costs and expenses | |||||||||||||||||||||||||||||||||||||||||||||||||
Operating, cost of sales, selling and general | 182 | 171 | 160 | 135 | 81 | 215 | 176 | 166 | 1,111 | 758 | 785 | 1,539 | |||||||||||||||||||||||||||||||||||||
Depletion, depreciation and amortization | 193 | 185 | 176 | 174 | 4 | 5 | 5 | 3 | 4 | 5 | 4 | 4 | |||||||||||||||||||||||||||||||||||||
Interest — net | — | — | — | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||
Foreign exchange | — | — | — | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||
375 | 356 | 336 | 309 | 85 | 220 | 181 | 169 | 1,115 | 763 | 789 | 1,543 | ||||||||||||||||||||||||||||||||||||||
Earnings (loss) before income taxes | (8 | ) | 193 | 242 | 362 | 62 | 35 | 78 | 56 | 38 | 33 | 50 | 49 | ||||||||||||||||||||||||||||||||||||
Current income taxes | 3 | 5 | 5 | 4 | 1 | — | — | — | — | 1 | — | — | |||||||||||||||||||||||||||||||||||||
Future income taxes | 3 | 79 | 60 | 148 | 21 | 13 | 18 | 20 | 16 | 14 | 20 | 21 | |||||||||||||||||||||||||||||||||||||
Net earnings (loss) | $ | (14 | ) | $ | 109 | $ | 177 | $ | 210 | $ | 40 | $ | 22 | $ | 60 | $ | 36 | $ | 22 | $ | 18 | $ | 30 | $ | 28 | ||||||||||||||||||||||||
Capital employed(2) | $ | 5,715 | $ | 5,685 | $ | 5,633 | $ | 5,444 | $ | 320 | $ | 303 | $ | 313 | $ | 337 | $ | 395 | $ | 373 | $ | 275 | $ | 254 | |||||||||||||||||||||||||
Total assets | $ | 7,407 | $ | 7,298 | $ | 7,104 | $ | 7,051 | $ | 644 | $ | 610 | $ | 610 | $ | 620 | $ | 862 | $ | 853 | $ | 835 | $ | 822 | |||||||||||||||||||||||||
(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) | Capital employed is defined as short- and long-term debt and shareholders’ equity. |
Page 59
Segmented Financial Information
($ millions)
Refined Products | Corporate and Eliminations(1) | Total | |||||||||||||||||||||||||||||||||||||||||||||||
2002 | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | |||||||||||||||||||||||||||||||||||||
Sales and operating revenues, net of royalties | $ | 326 | $ | 431 | $ | 322 | $ | 231 | $ | (1,078 | ) | $ | (645 | ) | $ | (451 | ) | $ | (556 | ) | $ | 1,697 | $ | 1,669 | $ | 1,659 | $ | 1,359 | |||||||||||||||||||||
Costs and expenses | |||||||||||||||||||||||||||||||||||||||||||||||||
Operating, cost of sales, selling and general | 318 | 395 | 292 | 217 | (1,081 | ) | (642 | ) | (436 | ) | (537 | ) | 1,029 | 1,030 | 1,125 | 920 | |||||||||||||||||||||||||||||||||
Depletion, depreciation and amortization | 9 | 9 | 8 | 8 | 5 | 3 | 4 | 4 | 256 | 239 | 223 | 221 | |||||||||||||||||||||||||||||||||||||
Interest — net | — | — | — | — | 25 | 28 | 24 | 27 | 25 | 28 | 24 | 27 | |||||||||||||||||||||||||||||||||||||
Foreign exchange | — | — | — | — | (5 | ) | 75 | (65 | ) | 8 | (5 | ) | 75 | (65 | ) | 8 | |||||||||||||||||||||||||||||||||
327 | 404 | 300 | 225 | (1,056 | ) | (536 | ) | (473 | ) | (498 | ) | 1,305 | 1,372 | 1,307 | 1,176 | ||||||||||||||||||||||||||||||||||
Earnings (loss) before income taxes | (1 | ) | 27 | 22 | 6 | (22 | ) | (109 | ) | 22 | (58 | ) | 392 | 297 | 352 | 183 | |||||||||||||||||||||||||||||||||
Current income taxes | (1 | ) | 4 | 1 | — | — | — | — | — | 6 | 26 | 6 | 28 | ||||||||||||||||||||||||||||||||||||
Future income taxes | 1 | 7 | 8 | 2 | (7 | ) | (33 | ) | (20 | ) | (30 | ) | 144 | 98 | 83 | 29 | |||||||||||||||||||||||||||||||||
Net earnings (loss) | $ | (1 | ) | $ | 16 | $ | 13 | $ | 4 | $ | (15 | ) | $ | (76 | ) | $ | 42 | $ | (28 | ) | $ | 242 | $ | 173 | $ | 263 | $ | 126 | |||||||||||||||||||||
Capital employed(2) | $ | 338 | $ | 360 | $ | 383 | $ | 375 | $ | 384 | $ | 176 | $ | 233 | $ | (2 | ) | $ | 7,512 | $ | 7,334 | $ | 7,135 | $ | 6,866 | ||||||||||||||||||||||||
Total assets | $ | 534 | $ | 554 | $ | 523 | $ | 516 | $ | 313 | $ | 153 | $ | 189 | $ | 6 | $ | 10,575 | $ | 10,348 | $ | 9,965 | $ | 9,730 | |||||||||||||||||||||||||
Refined Products | Corporate and Eliminations(1) | Total | |||||||||||||||||||||||||||||||||||||||||||||||
2001 | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | |||||||||||||||||||||||||||||||||||||
Sales and operating revenues, net of royalties | $ | 274 | $ | 429 | $ | 345 | $ | 301 | $ | (326 | ) | $ | (559 | ) | $ | (290 | ) | $ | (1,009 | ) | $ | 1,615 | $ | 1,470 | $ | 1,731 | $ | 1,780 | |||||||||||||||||||||
Costs and expenses | |||||||||||||||||||||||||||||||||||||||||||||||||
Operating, cost of sales, selling and general | 254 | 371 | 296 | 285 | (330 | ) | (552 | ) | (283 | ) | (1,000 | ) | 1,298 | 963 | 1,134 | 1,125 | |||||||||||||||||||||||||||||||||
Depletion, depreciation and amortization | 9 | 7 | 7 | 8 | 4 | 3 | 4 | 3 | 214 | 205 | 196 | 192 | |||||||||||||||||||||||||||||||||||||
Interest — net | — | — | — | — | 23 | 24 | 26 | 28 | 23 | 24 | 26 | 28 | |||||||||||||||||||||||||||||||||||||
Foreign exchange | — | — | — | — | 15 | 56 | (50 | ) | 73 | 15 | 56 | (50 | ) | 73 | |||||||||||||||||||||||||||||||||||
263 | 378 | 303 | 293 | (288 | ) | (469 | ) | (303 | ) | (896 | ) | 1,550 | 1,248 | 1,306 | 1,418 | ||||||||||||||||||||||||||||||||||
Earnings (loss) before income taxes | 11 | 51 | 42 | 8 | (38 | ) | (90 | ) | 13 | (113 | ) | 65 | 222 | 425 | 362 | ||||||||||||||||||||||||||||||||||
Current income taxes | 1 | — | — | — | — | (1 | ) | — | 1 | 5 | 5 | 5 | 5 | ||||||||||||||||||||||||||||||||||||
Future income taxes | 7 | 21 | 16 | 4 | (32 | ) | (28 | ) | 7 | (28 | ) | 15 | 99 | 121 | 165 | ||||||||||||||||||||||||||||||||||
Net earnings (loss) | $ | 3 | $ | 30 | $ | 26 | $ | 4 | $ | (6 | ) | $ | (61 | ) | $ | 6 | $ | (86 | ) | $ | 45 | $ | 118 | $ | 299 | $ | 192 | ||||||||||||||||||||||
Capital employed(2) | $ | 329 | $ | 304 | $ | 342 | $ | 364 | $ | (81 | ) | $ | (78 | ) | $ | (103 | ) | $ | (96 | ) | $ | 6,678 | $ | 6,587 | $ | 6,460 | $ | 6,303 | |||||||||||||||||||||
Total assets | $ | 428 | $ | 491 | $ | 499 | $ | 498 | $ | 29 | $ | 10 | $ | (4 | ) | $ | — | $ | 9,370 | $ | 9,262 | $ | 9,044 | $ | 8,991 | ||||||||||||||||||||||||
Page 60
Segmented Financial Information
($ millions)
2002 | 2001 | ||||||||||||||||||||||||||||||||||
Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | ||||||||||||||||||||||||||||
Capital expenditures | |||||||||||||||||||||||||||||||||||
Upstream | — Western Canada | $ | 326 | $ | 207 | $ | 156 | $ | 345 | $ | 264 | $ | 323 | $ | 186 | $ | 249 | ||||||||||||||||||
— East Coast Canada | 97 | 169 | 154 | 38 | 54 | 43 | 54 | 40 | |||||||||||||||||||||||||||
— International | 8 | 25 | 22 | 20 | 35 | 21 | 18 | 30 | |||||||||||||||||||||||||||
431 | 401 | 332 | 403 | 353 | 387 | 258 | 319 | ||||||||||||||||||||||||||||
Midstream | — Upgrader | 11 | 9 | 12 | 9 | 37 | 5 | 3 | 2 | ||||||||||||||||||||||||||
— Infrastructure and marketing | 5 | 2 | 3 | 7 | 22 | 6 | 5 | 25 | |||||||||||||||||||||||||||
16 | 11 | 15 | 16 | 59 | 11 | 8 | 27 | ||||||||||||||||||||||||||||
Refined products | 22 | 9 | 9 | 4 | 12 | 7 | 5 | 5 | |||||||||||||||||||||||||||
Corporate | 10 | 5 | 5 | 3 | 11 | 9 | 2 | — | |||||||||||||||||||||||||||
$ | 479 | $ | 426 | $ | 361 | $ | 426 | $ | 435 | $ | 414 | $ | 273 | $ | 351 | ||||||||||||||||||||
Page 61
Five-Year Financial and Operating Summary
Segmented Financial Information
($ millions)
Upstream | |||||||||||||||||||||
2002 | 2001 | 2000 | 1999 | 1998 | |||||||||||||||||
Year ended December 31 | |||||||||||||||||||||
Sales and operating revenues, net of royalties | $ | 2,665 | $ | 2,165 | $ | 1,549 | $ | 595 | $ | 440 | |||||||||||
Costs and expenses | |||||||||||||||||||||
Operating, cost of sales, selling and general | 729 | 648 | 375 | 214 | 200 | ||||||||||||||||
Depletion, depreciation and amortization | 851 | 728 | 407 | 223 | 214 | ||||||||||||||||
Interest — net | — | — | — | — | — | ||||||||||||||||
Foreign exchange | — | — | — | — | — | ||||||||||||||||
1,580 | 1,376 | 782 | 437 | 414 | |||||||||||||||||
Earnings (loss) before income taxes | 1,085 | 789 | 767 | 158 | 26 | ||||||||||||||||
Current income taxes | 55 | 17 | 10 | 3 | 3 | ||||||||||||||||
Future income taxes | 342 | 290 | 305 | 50 | 20 | ||||||||||||||||
Net earnings (loss) | $ | 688 | $ | 482 | $ | 452 | $ | 105 | $ | 3 | |||||||||||
Capital employed — As at December 31(2) | $ | 6,040 | $ | 5,715 | $ | 5,398 | $ | 2,077 | $ | 1,653 | |||||||||||
Total assets — As at December 31 | $ | 8,220 | $ | 7,407 | $ | 6,735 | $ | 2,839 | $ | 2,375 | |||||||||||
[Additional columns below]
[Continued from above table, first column(s) repeated]
Midstream | |||||||||||||||||||||||||||||||||||||||||
Upgrading | Infrastructure and Marketing | ||||||||||||||||||||||||||||||||||||||||
2002 | 2001 | 2000 | 1999 | 1998 | 2002 | 2001 | 2000 | 1999 | 1998 | ||||||||||||||||||||||||||||||||
Year ended December 31 | |||||||||||||||||||||||||||||||||||||||||
Sales and operating revenues, net of royalties | $ | 909 | $ | 886 | $ | 1,006 | $ | 641 | $ | 412 | $ | 4,230 | $ | 4,380 | $ | 2,309 | $ | 1,284 | $ | 999 | |||||||||||||||||||||
Costs and expenses | |||||||||||||||||||||||||||||||||||||||||
Operating, cost of sales, selling and general | 811 | 638 | 848 | 581 | 346 | 4,038 | 4,193 | 2,193 | 1,190 | 909 | |||||||||||||||||||||||||||||||
Depletion, depreciation and amortization | 18 | 17 | 16 | 16 | 14 | 20 | 17 | 15 | 13 | 12 | |||||||||||||||||||||||||||||||
Interest — net | — | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||
Foreign exchange | — | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||
829 | 655 | 864 | 597 | 360 | 4,058 | 4,210 | 2,208 | 1,203 | 921 | ||||||||||||||||||||||||||||||||
Earnings (loss) before income taxes | 80 | 231 | 142 | 44 | 52 | 172 | 170 | 101 | 81 | 78 | |||||||||||||||||||||||||||||||
Current income taxes | 1 | 1 | 1 | 1 | 1 | 6 | 1 | — | — | — | |||||||||||||||||||||||||||||||
Future income taxes | 25 | 72 | 53 | 21 | 22 | 59 | 71 | 45 | 36 | 35 | |||||||||||||||||||||||||||||||
Net earnings (loss) | $ | 54 | $ | 158 | $ | 88 | $ | 22 | $ | 29 | $ | 107 | $ | 98 | $ | 56 | $ | 45 | $ | 43 | |||||||||||||||||||||
Capital employed — As at December 31(2) | $ | 319 | $ | 320 | $ | 352 | $ | 392 | $ | 418 | $ | 431 | $ | 395 | $ | 312 | $ | 353 | $ | 319 | |||||||||||||||||||||
Total assets — As at December 31 | $ | 658 | $ | 644 | $ | 613 | $ | 606 | $ | 605 | $ | 850 | $ | 862 | $ | 1,000 | $ | 652 | $ | 441 | |||||||||||||||||||||
(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) | Capital employed is defined as short- and long-term debt and shareholders’ equity. | |
Certain prior years’ amounts have been reclassified to conform with current presentation. |
Page 62
Segmented Financial Information
($ millions)
Refined Products | ||||||||||||||||||||||
2002 | 2001 | 2000 | 1999 | 1998 | ||||||||||||||||||
Year ended December 31 | ||||||||||||||||||||||
Sales and operating revenues, net of royalties | $ | 1,310 | $ | 1,349 | $ | 1,347 | $ | 904 | $ | 664 | ||||||||||||
Costs and expenses | ||||||||||||||||||||||
Operating, cost of sales, selling and general | 1,222 | 1,206 | 1,288 | 842 | 591 | |||||||||||||||||
Depletion, depreciation and amortization | 34 | 31 | 28 | 26 | 20 | |||||||||||||||||
Interest — net | — | — | — | — | — | |||||||||||||||||
Foreign exchange | — | — | — | — | — | |||||||||||||||||
1,256 | 1,237 | 1,316 | 868 | 611 | ||||||||||||||||||
Earnings (loss) before income taxes | 54 | 112 | 31 | 36 | 53 | |||||||||||||||||
Current income taxes | 4 | 1 | 1 | 1 | 1 | |||||||||||||||||
Future income taxes | 18 | 48 | 14 | 16 | 23 | |||||||||||||||||
Net earnings (loss) | $ | 32 | $ | 63 | $ | 16 | $ | 19 | $ | 29 | ||||||||||||
Capital employed — As at December 31(2) | $ | 338 | $ | 329 | $ | 351 | $ | 366 | $ | 381 | ||||||||||||
Total assets — As at December 31 | $ | 534 | $ | 428 | $ | 487 | $ | 476 | $ | 421 | ||||||||||||
[Additional columns below]
[Continued from above table, first column(s) repeated]
Corporate and Eliminations(1) | ||||||||||||||||||||||
2002 | 2001 | 2000 | 1999 | 1998 | ||||||||||||||||||
Year ended December 31 | ||||||||||||||||||||||
Sales and operating revenues, net of royalties | $ | (2,730 | ) | $ | (2,184 | ) | $ | (1,145 | ) | $ | (637 | ) | $ | (492 | ) | |||||||
Costs and expenses | ||||||||||||||||||||||
Operating, cost of sales, selling and general | (2,696 | ) | (2,165 | ) | (1,060 | ) | (514 | ) | (437 | ) | ||||||||||||
Depletion, depreciation and amortization | 16 | 14 | 15 | 15 | 13 | |||||||||||||||||
Interest — net | 104 | 101 | 101 | 62 | 70 | |||||||||||||||||
Foreign exchange | 13 | 94 | 39 | (55 | ) | 63 | ||||||||||||||||
(2,563 | ) | (1,956 | ) | (905 | ) | (492 | ) | (291 | ) | |||||||||||||
Earnings (loss) before income taxes | (167 | ) | (228 | ) | (240 | ) | (145 | ) | (201 | ) | ||||||||||||
Current income taxes | — | — | — | — | — | |||||||||||||||||
Future income taxes | (90 | ) | (81 | ) | (66 | ) | (50 | ) | (92 | ) | ||||||||||||
Net earnings (loss) | $ | (77 | ) | $ | (147 | ) | $ | (174 | ) | $ | (95 | ) | $ | (109 | ) | |||||||
Capital employed — As at December 31(2) | $ | 384 | $ | (81 | ) | $ | (50 | ) | $ | 158 | $ | 134 | ||||||||||
Total assets — As at December 31 | $ | 313 | $ | 29 | $ | (6 | ) | $ | 203 | $ | 233 | |||||||||||
[Additional columns below]
[Continued from above table, first column(s) repeated]
Total | ||||||||||||||||||||||
2002 | 2001 | 2000 | 1999 | 1998 | ||||||||||||||||||
Year ended December 31 | ||||||||||||||||||||||
Sales and operating revenues, net of royalties | $ | 6,384 | $ | 6,596 | $ | 5,066 | $ | 2,787 | $ | 2,023 | ||||||||||||
Costs and expenses | ||||||||||||||||||||||
Operating, cost of sales, selling and general | 4,104 | 4,520 | 3,644 | 2,313 | 1,609 | |||||||||||||||||
Depletion, depreciation and amortization | 939 | 807 | 481 | 293 | 273 | |||||||||||||||||
Interest — net | 104 | 101 | 101 | 62 | 70 | |||||||||||||||||
Foreign exchange | 13 | 94 | 39 | (55 | ) | 63 | ||||||||||||||||
5,160 | 5,522 | 4,265 | 2,613 | 2,015 | ||||||||||||||||||
Earnings (loss) before income taxes | 1,224 | 1,074 | 801 | 174 | 8 | |||||||||||||||||
Current income taxes | 66 | 20 | 12 | 5 | 5 | |||||||||||||||||
Future income taxes | 354 | 400 | 351 | 73 | 8 | |||||||||||||||||
Net earnings (loss) | $ | 804 | $ | 654 | $ | 438 | $ | 96 | $ | (5 | ) | |||||||||||
Capital employed — As at December 31(2) | $ | 7,512 | $ | 6,678 | $ | 6,363 | $ | 3,346 | $ | 2,905 | ||||||||||||
Total assets — As at December 31 | $ | 10,575 | $ | 9,370 | $ | 8,829 | $ | 4,776 | $ | 4,075 | ||||||||||||
Page 63
Segmented Financial Information
($ millions) | 2002 | 2001 | 2000 | 1999 | 1998 | ||||||||||||||||||||
Capital expenditures | |||||||||||||||||||||||||
Upstream | — Western Canada | $ | 1,034 | $ | 1,022 | $ | 419 | $ | 238 | $ | 233 | ||||||||||||||
— East Coast Canada | 458 | 191 | 194 | 309 | 191 | ||||||||||||||||||||
— International | 75 | 104 | 87 | 23 | 15 | ||||||||||||||||||||
1,567 | 1,317 | 700 | 570 | 439 | |||||||||||||||||||||
Midstream | — Upgrader | 41 | 47 | 12 | 15 | 283 | |||||||||||||||||||
— Infrastructure and marketing | 17 | 58 | 47 | 79 | 68 | ||||||||||||||||||||
58 | 105 | 59 | 94 | 351 | |||||||||||||||||||||
Refined products | 44 | 29 | 29 | 34 | 27 | ||||||||||||||||||||
Corporate | 23 | 22 | 15 | 8 | 12 | ||||||||||||||||||||
$ | 1,692 | $ | 1,473 | $ | 803 | $ | 706 | $ | 829 | ||||||||||||||||
Upstream Operating Information
2002 | 2001 | 2000 | 1999 | 1998 | |||||||||||||||||
Daily production, before royalties | |||||||||||||||||||||
Light/medium crude oil & NGL(mbbls/day) | 125.9 | 112.0 | 63.6 | 26.5 | 27.6 | ||||||||||||||||
Lloydminster heavy crude oil(mbbls/day) | 79.4 | 65.4 | 53.5 | 42.1 | 42.0 | ||||||||||||||||
205.3 | 177.4 | 117.1 | 68.6 | 69.6 | |||||||||||||||||
Natural gas(mmcf/day) | 569.2 | 572.6 | 358.0 | 250.5 | 232.6 | ||||||||||||||||
Total production(mboe/day) | 300.2 | 272.8 | 176.8 | 110.4 | 108.4 | ||||||||||||||||
Average realized sales prices | |||||||||||||||||||||
Light/medium crude oil & NGL($/bbl) | $ | 33.28 | $ | 27.19 | $ | 33.42 | $ | 21.52 | $ | 16.07 | |||||||||||
Lloydminster heavy crude oil($/bbl) | $ | 26.09 | $ | 15.85 | $ | 21.26 | $ | 16.00 | $ | 8.26 | |||||||||||
Natural gas($/mcf) | $ | 3.83 | $ | 5.47 | $ | 5.16 | $ | 2.41 | $ | 2.17 | |||||||||||
Operating costs($/boe) | $ | 6.24 | $ | 6.08 | $ | 5.27 | $ | 4.80 | $ | 4.53 | |||||||||||
Operating netbacks(1) | |||||||||||||||||||||
Light/medium crude oil & NGL($/boe) | $ | 21.20 | $ | 15.08 | $ | 20.61 | $ | 13.71 | $ | 9.78 | |||||||||||
Lloydminster heavy crude oil($/boe) | $ | 16.02 | $ | 7.13 | $ | 12.11 | $ | 7.75 | $ | 1.61 | |||||||||||
Natural gas($/mcfge) | $ | 2.44 | $ | 3.51 | $ | 3.59 | $ | 1.54 | $ | 1.46 |
(1) | Operating netbacks are Husky’s average realized prices less royalties, hedging (gains)/losses and operating costs on a per unit basis. |
Certain prior years’ amounts have been reclassified to conform with current presentation.
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Upstream Operating Information (continued)
2002 | 2001 | 2000 | 1999 | 1998 | |||||||||||||||||||||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||||||||||||||||||||
Wells drilled(1) | |||||||||||||||||||||||||||||||||||||||||||||
Exploration | Oil | 21 | 20 | 78 | 76 | 16 | 13 | 9 | 9 | 16 | 11 | ||||||||||||||||||||||||||||||||||
Gas | 139 | 131 | 102 | 90 | 30 | 20 | 13 | 5 | 9 | 7 | |||||||||||||||||||||||||||||||||||
Dry | 15 | 14 | 36 | 34 | 9 | 9 | 9 | 9 | 8 | 6 | |||||||||||||||||||||||||||||||||||
175 | 165 | 216 | 200 | 55 | 42 | 31 | 23 | 33 | 24 | ||||||||||||||||||||||||||||||||||||
Development | Oil | 497 | 453 | 594 | 542 | 411 | 363 | 203 | 190 | 75 | 55 | ||||||||||||||||||||||||||||||||||
Gas | 485 | 453 | 251 | 221 | 92 | 70 | 42 | 23 | 22 | 7 | |||||||||||||||||||||||||||||||||||
Dry | 58 | 55 | 68 | 63 | 30 | 28 | 23 | 22 | 6 | 4 | |||||||||||||||||||||||||||||||||||
1,040 | 961 | 913 | 826 | 533 | 461 | 268 | 235 | 103 | 66 | ||||||||||||||||||||||||||||||||||||
1,215 | 1,126 | 1,129 | 1,026 | 588 | 503 | 299 | 258 | 136 | 90 | ||||||||||||||||||||||||||||||||||||
Success ratio (percent) | 94 | 94 | 91 | 91 | 93 | 93 | 89 | 88 | 90 | 89 |
(1) | Western Canada. |
Undeveloped Land Holdings
(thousands of acres - net) | 2002 | 2001 | 2000 | 1999 | 1998 | ||||||||||||||||
Western Canada | |||||||||||||||||||||
Alberta | 4,907 | 5,373 | 5,616 | 692 | 877 | ||||||||||||||||
Saskatchewan | 1,986 | 1,921 | 2,639 | 586 | 662 | ||||||||||||||||
British Columbia | 273 | 141 | 173 | 66 | 133 | ||||||||||||||||
Manitoba | 13 | 75 | 162 | — | — | ||||||||||||||||
7,179 | 7,510 | 8,590 | 1,344 | 1,672 | |||||||||||||||||
Northwest Territories and Arctic | 175 | 409 | 409 | 417 | 474 | ||||||||||||||||
Eastern Canada | 2,104 | 1,471 | 1,489 | 258 | 243 | ||||||||||||||||
Total Canada | 9,458 | 9,390 | 10,488 | 2,019 | 2,389 | ||||||||||||||||
International | 2,066 | 697 | 221 | 389 | 392 | ||||||||||||||||
Total | 11,524 | 10,087 | 10,709 | 2,408 | 2,781 | ||||||||||||||||
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Selected Eleven-Year Financial and Operating Summary
($ millions, except where indicated) | 2002 | 2001 | 2000 | 1999 | 1998 | 1997 | 1996 | 1995 | 1994 | 1993 | 1992 | ||||||||||||||||||||||||||||||||||
Sales and operating revenues, net of royalties | $ | 6,384 | $ | 6,596 | $ | 5,066 | $ | 2,787 | $ | 2,023 | $ | 2,282 | $ | 2,104 | $ | 1,783 | $ | 1,373 | $ | 1,138 | $ | 977 | |||||||||||||||||||||||
Net earnings (loss) | $ | 804 | $ | 654 | $ | 438 | $ | 96 | $ | (5 | ) | $ | 55 | $ | 49 | $ | 20 | $ | (40 | ) | $ | (249 | ) | $ | (395 | ) | |||||||||||||||||||
Net earnings per share | |||||||||||||||||||||||||||||||||||||||||||||
Basic | $ | 1.88 | $ | 1.49 | $ | 1.28 | $ | 0.34 | $ | (0.04 | ) | $ | 0.20 | $ | 0.18 | $ | 0.08 | $ | (0.15 | ) | $ | (0.92 | ) | $ | (1.46 | ) | |||||||||||||||||||
Diluted | $ | 1.88 | $ | 1.48 | $ | 1.28 | $ | 0.34 | $ | (0.04 | ) | $ | 0.20 | $ | 0.18 | $ | 0.08 | $ | (0.15 | ) | $ | (0.92 | ) | $ | (1.46 | ) | |||||||||||||||||||
Cash flow from operations | $ | 2,096 | $ | 1,946 | $ | 1,399 | $ | 517 | $ | 449 | $ | 453 | $ | 378 | $ | 303 | $ | 242 | $ | 171 | $ | 183 | |||||||||||||||||||||||
Cash flow from operations per share | |||||||||||||||||||||||||||||||||||||||||||||
Basic | $ | 4.94 | $ | 4.60 | $ | 4.26 | $ | 1.80 | $ | 1.61 | $ | 1.68 | $ | 1.40 | $ | 1.12 | $ | 0.90 | $ | 0.63 | $ | 0.68 | |||||||||||||||||||||||
Diluted | $ | 4.92 | $ | 4.57 | $ | 4.26 | $ | 1.80 | $ | 1.61 | $ | 1.68 | $ | 1.40 | $ | 1.12 | $ | 0.90 | $ | 0.63 | $ | 0.68 | |||||||||||||||||||||||
Capital expenditures(1) | $ | 1,692 | $ | 1,473 | $ | 803 | $ | 706 | $ | 829 | $ | 601 | $ | 218 | $ | 155 | $ | 257 | $ | 315 | $ | 312 | |||||||||||||||||||||||
Total debt | $ | 2,385 | $ | 2,192 | $ | 2,378 | $ | 1,382 | $ | 1,131 | $ | 1,014 | $ | 853 | $ | 1,474 | $ | 1,667 | $ | 1,570 | $ | 1,570 | |||||||||||||||||||||||
Debt to capital employed(percent) | 32 | 33 | 37 | 41 | 39 | 43 | 42 | 63 | 69 | 67 | 62 | ||||||||||||||||||||||||||||||||||
Debt to cash flow from operations(times) | 1.1 | 1.1 | 1.7 | 2.7 | 2.5 | 2.2 | 2.3 | 4.9 | 6.9 | 9.2 | 8.6 | ||||||||||||||||||||||||||||||||||
Reinvestment ratio(3)(percent) | 76 | 78 | 57 | 134 | 199 | 132 | 46 | 44 | 62 | 117 | 118 | ||||||||||||||||||||||||||||||||||
Return on average capital employed(2)(percent) | 12.2 | 10.9 | 12.4 | 6.9 | 4.2 | 7.2 | 6.7 | 5.5 | 1.2 | (8.5 | ) | (12.8 | ) | ||||||||||||||||||||||||||||||||
Return on equity(4)(percent) | 16.7 | 15.4 | 19.4 | 11.4 | 6.7 | 12.1 | 11.7 | 14.1 | (3.0 | ) | (28.3 | ) | (31.0 | ) | |||||||||||||||||||||||||||||||
Upstream | |||||||||||||||||||||||||||||||||||||||||||||
Daily production, before royalties | |||||||||||||||||||||||||||||||||||||||||||||
Light/medium crude oil & NGL(mbbls/day) | 125.9 | 112.0 | 63.6 | 26.5 | 27.6 | 27.6 | 28.3 | 27.7 | 29.4 | 29.9 | 28.9 | ||||||||||||||||||||||||||||||||||
Lloydminster heavy crude oil(mbbls/day) | 79.4 | 65.4 | 53.5 | 42.1 | 42.0 | 41.9 | 34.5 | 30.0 | 26.6 | 21.9 | 18.4 | ||||||||||||||||||||||||||||||||||
205.3 | 177.4 | 117.1 | 68.6 | 69.6 | 69.5 | 62.8 | 57.7 | 56.0 | 51.8 | 47.3 | |||||||||||||||||||||||||||||||||||
Natural gas(mmcf/day) | 569 | 573 | 358 | 251 | 233 | 246 | 268 | 286 | 248 | 246 | 252 | ||||||||||||||||||||||||||||||||||
Total production(mboe/day) | 300.2 | 272.8 | 176.8 | 110.4 | 108.4 | 110.6 | 107.5 | 105.4 | 97.4 | 92.8 | 89.3 | ||||||||||||||||||||||||||||||||||
Total proved reserves, before royalties(mmboe) | 918 | 927 | 872 | 430 | 431 | 421 | 432 | 416 | 401 | 408 | 472 | ||||||||||||||||||||||||||||||||||
Midstream | |||||||||||||||||||||||||||||||||||||||||||||
Synthetic crude oil sales(mbbls/day) | 59.3 | 59.5 | 60.6 | 61.9 | 54.8 | 27.5 | 26.8 | 26.6 | 18.8 | 11.3 | 0.6 | ||||||||||||||||||||||||||||||||||
Upgrading differential($/bbl) | $ | 10.81 | $ | 17.91 | $ | 13.77 | $ | 6.49 | $ | 7.85 | $ | 8.54 | $ | 5.94 | $ | 4.34 | $ | 4.18 | $ | 5.50 | $ | 5.22 | |||||||||||||||||||||||
Pipeline throughput(mbbls/day) | 457 | 537 | 528 | 394 | 412 | 417 | 359 | 296 | 238 | 217 | 169 | ||||||||||||||||||||||||||||||||||
Refined products | |||||||||||||||||||||||||||||||||||||||||||||
Light oil sales(million litres/day) | 7.7 | 7.6 | 7.4 | 7.6 | 6.0 | 4.5 | 4.2 | 3.9 | 3.2 | 2.9 | 2.5 | ||||||||||||||||||||||||||||||||||
Asphalt product sales(mbbls/day) | 20.8 | 21.4 | 20.2 | 17.1 | 19.5 | 17.7 | 15.1 | 13.5 | 13.1 | 10.8 | 9.9 | ||||||||||||||||||||||||||||||||||
Refinery throughput | |||||||||||||||||||||||||||||||||||||||||||||
Lloydminster refinery(mbbls/day) | 22.0 | 23.7 | 23.4 | 17.9 | 21.9 | 21.5 | 18.4 | 15.6 | 16.4 | 13.2 | 10.9 | ||||||||||||||||||||||||||||||||||
Prince George refinery(mbbls/day) | 10.1 | 10.2 | 9.2 | 10.2 | 9.9 | 10.3 | 10.0 | 9.9 | 9.7 | 9.7 | 8.7 | ||||||||||||||||||||||||||||||||||
Refinery utilization(percent) | 92 | 97 | 93 | 80 | 91 | 91 | 81 | 73 | 75 | 65 | 56 |
(1) | Excludes corporate acquisitions. | |
(2) | Capital employed for purposes of this calculation has been weighted for 2000. | |
(3) | Reinvestment ratio is based on net capital expenditures including corporate acquisitions (other than Renaissance Energy Ltd.). | |
(4) | Equity for purposes of this calculation has been weighted for 2000 and includes amounts due to shareholders prior to August 25, 2000. |
Certain prior years’ amounts have been reclassified to conform with current presentation.
Page 66
COMMON SHARE INFORMATION
Year ended December 31 | 2002 | 2001 | 2000 | |||||||||||||
Share price | High | $ | 17.98 | $ | 20.95 | $ | 15.95 | |||||||||
Low | $ | 14.00 | $ | 13.10 | $ | 11.50 | ||||||||||
Close at December 31 | $ | 16.47 | $ | 16.47 | $ | 14.90 | ||||||||||
Average daily trading volumes(thousands) | 463 | 625 | 979 | |||||||||||||
Number of common shares outstanding, December 31(thousands) | 417,874 | 416,878 | 415,803 | |||||||||||||
Number of weighted average common shares outstanding(thousands) | ||||||||||||||||
Basic | 417,425 | 416,100 | 415,803 | |||||||||||||
Diluted | 419,334 | 418,640 | 416,753 |
Trading in the common shares of Husky Energy Inc. (“HSE”) commenced on the Toronto Stock Exchange on August 28, 2000. The Company is represented in the S&P/TSX Composite, S&P/TSX Canadian Energy Sector and in the S&P/TSX 60 indices.
TERMS AND ABBREVIATIONS
bbls | barrels | |
mbbls | thousand barrels | |
mbbls/day | thousand barrels per day | |
mmbbls | million barrels | |
mcf | thousand cubic feet | |
mmcf | million cubic feet | |
mmcf/day | million cubic feet per day | |
bcf | billion cubic feet | |
tcf | trillion cubic feet | |
boe | barrels of oil equivalent | |
mboe | thousand barrels of oil equivalent | |
mboe/day | thousand barrels of oil equivalent per day | |
mmboe | million barrels of oil equivalent | |
mcfge | thousand cubic feet of gas equivalent | |
GJ | gigajoule | |
mmbtu | million British Thermal Units | |
mmlt | million long tons | |
NGL | natural gas liquids | |
hectare | 1 hectare is equal to 2.47 acres | |
Capital Employed | Short- and long-term debt and shareholders’ equity | |
Capital Expenditures | Includes capitalized administrative expenses and capitalized interest but does not include proceeds or other assets | |
Cash Flow from Operations | Earnings from operations plus non-cash charges before change in non-cash working capital | |
Equity | Capital securities and accrued return, shares, retained earnings and amounts due to shareholders prior to August 25, 2000 | |
Total Debt | Long-term debt including current portion and bank operating loans |
Natural gas converted on the basis that six mcf of natural gas equals one barrel of oil.
In this report, the terms “Husky Energy Inc.”, “Husky” or “the Company” mean Husky Energy Inc. and its subsidiaries and partnership interests on a consolidated basis.
Page 67