Exhibit 99.1
management’s statement of responsibility for financial reporting
The management of Suncor Energy Inc. is responsible for the presentation and preparation of the accompanying consolidated financial statements of Suncor Energy Inc. on pages 58 to 92 and all related financial information contained in this Annual Report, including Management’s Discussion and Analysis.
We, as Suncor Energy Inc.’s Chief Executive Officer and Chief Financial Officer, will certify Suncor’s annual disclosure document filed with the United States Securities and Exchange Commission (Form 40-F) as required by the United States Sarbanes-Oxley Act.
The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles. They include certain amounts that are based on estimates and judgments relating to matters not concluded by year-end. Financial information presented elsewhere in this Annual Report is consistent with that contained in the consolidated financial statements.
In management’s opinion, the consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the significant accounting policies adopted by management as summarized on pages 58 to 61. If alternate accounting methods exist, management has chosen those policies it deems the most appropriate in the circumstances. In discharging its responsibilities for the integrity and reliability of the financial statements, management maintains and relies upon a system of internal controls designed to ensure that transactions are properly authorized and recorded, assets are safeguarded against unauthorized use or disposition and liabilities are recognized. These controls include quality standards in hiring and training of employees, formalized policies and procedures, a corporate code of conduct and associated compliance program designed to establish and monitor conflicts of interest, the integrity of accounting records and financial information among others, and employee and management accountability for performance within appropriate and well-defined areas of responsibility.
The system of internal controls is further supported by the professional staff of an internal audit function who conduct periodic audits of all aspects of the company’s operations.
The company retains independent petroleum consultants, Gilbert Laustsen Jung Associates Ltd., to conduct independent evaluations of the company’s oil and gas reserves.
The Audit Committee of the Board of Directors, currently composed of five independent directors, reviews the effectiveness of the company’s financial reporting systems, management information systems, internal control systems and internal auditors. It recommends to the Board of Directors the external auditors to be appointed by the shareholders at each annual meeting and reviews the independence and effectiveness of their work. In addition, it reviews with management and the external auditors any significant financial reporting issues, the presentation and impact of significant risks and uncertainties, and key estimates and judgments of management that may be material for financial reporting purposes. The Audit Committee appoints the independent petroleum consultants. The Audit Committee meets at least quarterly to review and approve interim financial statements prior to their release, as well as annually to review Suncor’s annual financial statements and Management’s Discussion and Analysis, Annual Information Form/Form 40-F, and annual reserves estimates, and recommend their approval to the Board of Directors. The internal auditors and PricewaterhouseCoopers LLP have unrestricted access to the company, the Audit Committee and the Board of Directors.
/s/ Richard L. George |
|
| /s/ J. Kenneth Alley |
|
Richard L. George |
| J. Kenneth Alley | ||
President and |
| Senior Vice President and | ||
|
|
| ||
February 23, 2005 |
|
|
Suncor Energy Inc. 2004 Annual Report
54
The following report is provided by management in respect of the company’s internal control over financial reporting (as defined in Rule 13a-15(f) under the U.S. Securities Exchange Act of 1934):
management’s report on internal control over financial reporting
1. Management is responsible for establishing and maintaining adequate internal control over the company’s financial reporting.
2. Management has used the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) framework in Internal Control – Integrated Framework to evaluate the effectiveness of the company’s internal control over financial reporting.
3. Management has assessed the effectiveness of the company’s internal control over financial reporting as at December 31, 2004, and has concluded that such internal control over financial reporting was effective as at that date. Additionally, based on our assessment, we determined that there were no material weaknesses in internal control over financial reporting as of December 31, 2004.
4. PricewaterhouseCoopers LLP, who has audited the company’s consolidated financial statements for the year ended December 31, 2004, has also audited management’s assessment of the effectiveness of the company’s internal control over financial reporting as at December 31, 2004 as stated in their report which appears herein.
/s/ Richard L. George |
| /s/ J. Kenneth Alley |
|
Richard L. George | J. Kenneth Alley | ||
President and | Senior Vice President and | ||
Chief Executive Officer | Chief Financial Officer |
February 23, 2005
Suncor Energy Inc. 2004 Annual Report
55
auditors’ report
TO THE SHAREHOLDERS OF SUNCOR ENERGY INC.
We have audited the accompanying Consolidated Balance Sheets of Suncor Energy Inc. (the company) as at December 31, 2004 and 2003 and the related Consolidated Statements of Earnings, Cash Flows and Changes in Shareholders’ Equity for each of the years in the three-year period ended December 31, 2004. We have also audited the effectiveness of the company’s internal control over financial reporting as at December 31, 2004, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) and management’s assessment thereof included in the accompanying Management’s Report on Internal Control over Financial Reporting. The company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on these financial statements, an opinion on management’s assessment and an opinion on the effectiveness of the company’s internal control over financial reporting based on our audits.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
We conducted our audits of the company’s financial statements in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. A financial statement audit also includes assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We conducted our audit of the effectiveness of the company’s internal control over financial reporting and management’s assessment thereof in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control and performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the company as at December 31, 2004 and 2003 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2004 in accordance with Canadian generally accepted accounting principles. Also, in our opinion, management’s assessment that the company maintained effective internal control over financial reporting as at December 31, 2004 is fairly stated, in all material respects, based on criteria established in Internal Control – Integrated Framework issued by the COSO. Furthermore, in our opinion, the company maintained, in all material respects, effective internal control over financial reporting as at December 31, 2004 based on criteria established in Internal Control – Integrated Framework issued by the COSO.
Suncor Energy Inc. 2004 Annual Report
56
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP |
|
|
PricewaterhouseCoopers LLP |
| |
Chartered Accountants |
| |
Calgary, Alberta |
| |
|
| |
February 23, 2005 |
|
COMMENTS BY AUDITORS FOR U.S. READERS ON CANADA – U.S. REPORTING DIFFERENCES
In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when there is a change in accounting principles that has a material effect on the comparability of the company’s financial statements, such as the change described in Note 1 to the consolidated financial statements. Our report to the shareholders dated February 23, 2005 is expressed in accordance with Canadian reporting standards which do not require a reference to such a change in accounting principles in the Auditors’ Report when the change is properly accounted for and adequately disclosed in the financial statements.
/s/ PricewaterhouseCoopers LLP |
|
|
PricewaterhouseCoopers LLP |
| |
Chartered Accountants |
| |
Calgary, Alberta, Canada |
| |
|
| |
February 23, 2005 |
|
Suncor Energy Inc. 2004 Annual Report
57
summary of significant accounting policies
Suncor Energy Inc. is a Canadian integrated energy company comprised of four operating segments: Oil Sands, Natural Gas, Energy Marketing and Refining – Canada, and Refining and Marketing – U.S.A.
Oil Sands includes the production of light sweet and light sour crude oil, diesel fuel and various custom blends from oil sands in the Athabasca region of northeastern Alberta, and the marketing of these products substantially in Canada and the United States.
Natural Gas includes the exploration, acquisition, development, production, transportation and marketing of natural gas and crude oil in Canada and the United States.
Energy Marketing and Refining – Canada includes the manufacture, transportation and marketing of petroleum and petrochemical products, primarily in Ontario and Quebec. Petrochemical products are also sold in the United States and Europe.
Refining and Marketing – U.S.A. includes the manufacture, transportation and marketing of petroleum products, primarily in Colorado.
The significant accounting policies of the company are summarized below:
(a) Principles of Consolidation and the Preparation of Financial Statements
These consolidated financial statements are prepared and reported in Canadian dollars in accordance with generally accepted accounting principles (GAAP) in Canada, which differ in some respects from GAAP in the United States. These differences are quantified and explained in note 19.
The consolidated financial statements include the accounts of Suncor Energy Inc. and its subsidiaries and the company’s proportionate share of the assets, liabilities, revenues, expenses and cash flows of its joint-ventures.
The timely preparation of financial statements requires that management make estimates and assumptions, and use judgment regarding assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur.
Certain prior period comparative figures have also been reclassified to conform to the current period presentation.
(b) Cash Equivalents and Investments
Cash equivalents consist primarily of term deposits, certificates of deposit and all other highly liquid investments with a maturity at the time of purchase of three months or less. Investments with maturities greater than three months and up to one year are classified as short-term investments, while those with maturities in excess of one year are classified as long-term investments. Cash equivalents and short-term investments are stated at cost, which approximates market value.
(c) Revenues
Crude oil sales from upstream operations (Oil Sands and Natural Gas) to downstream operations (Energy Marketing and Refining – Canada and Refining and Marketing – U.S.A.) are based on actual product shipments. On consolidation, revenues and purchases related to these sales transactions are eliminated from operating revenues and purchases of crude oil and products.
The company also uses a portion of its natural gas production for internal consumption at its oil sands plant and Sarnia refinery. On consolidation, revenues from these sales are eliminated from operating revenues, crude oil and products purchases, and operating, selling and general expenses.
Revenues associated with sales of crude oil, natural gas, petroleum and petrochemical products and all other items not eliminated on consolidation are recorded when title passes to the customer and delivery has taken place. Revenues from oil and natural gas production from properties in which the company has an interest with other producers are recognized on the basis of the company’s net working interest. Revenues associated with multi-element arrangements are recognized on a straight-line basis over the term of associated services.
(d) Property, Plant and Equipment and Intangible Assets
Cost
Property, plant and equipment and intangible assets are recorded at cost.
Expenditures to acquire and develop Oil Sands mining properties are capitalized. Development costs to expand the capacity of existing mines or to develop mine areas substantially in advance of current production are also capitalized.
Suncor Energy Inc. 2004 Annual Report
58
The company follows the successful efforts method of accounting for its conventional natural gas and in-situ oil sands operations. Under the successful efforts method, acquisition costs of proved and unproved properties are capitalized. Costs of unproved properties are transferred to proved properties when proved reserves are confirmed. Exploration costs, including geological and geophysical costs, are expensed as incurred. Exploratory drilling costs are initially capitalized. If it is determined that a specific well does not contain proved reserves, the related capitalized exploratory drilling costs are charged to expense, as dry hole costs, at that time. Related land costs are expensed through the amortization of unproved properties as covered under the Natural Gas section of the depreciation, depletion and amortization policy below.
Development costs, which include the costs of wellhead equipment, development drilling costs, gas plants and handling facilities, applicable geological and geophysical costs and the costs of acquiring or constructing support facilities and equipment, are capitalized. Costs incurred to operate and maintain wells and equipment and to lift oil and gas to the surface are expensed as operating costs.
Costs incurred after the inception of operations are expensed.
Interest Capitalization
Interest costs relating to major capital projects in progress and to the portion of non-producing oil and gas properties expected to become producing are capitalized as part of property, plant and equipment. Capitalization of interest ceases when the capital asset is substantially complete and ready for its intended productive use.
Leases
Leases that transfer substantially all the benefits and risks of ownership to the company are recorded as capital leases and classified as property, plant and equipment with offsetting long-term debt. All other leases are classified as operating leases under which leasing costs are expensed in the period incurred.
Gains and losses on the sale and leaseback of assets recorded as capital leases are deferred and amortized to earnings in proportion to the amortization of leased assets.
Depreciation, Depletion and Amortization
OIL SANDS Property, plant and equipment are depreciated over their useful lives on a straight-line basis, commencing when the assets are placed into service. Mine and mobile equipment is depreciated over periods ranging from three to 20 years and plant and other property and equipment, including leases in service, primarily over four to 40 years. Capitalized costs related to the in-progress phase of projects are not depreciated until the facilities are substantially complete and ready for their intended productive use.
NATURAL GAS Acquisition costs of unproved properties that are individually significant are evaluated for impairment by management. Impairment of unproved properties that are not individually significant is provided for through amortization over the average projected holding period for that portion of acquisition costs not expected to become producing. The average projected holding period of five years is based on historical experience.
Acquisition costs of proved properties are depleted using the unit of production method based on proved reserves. Capitalized exploratory drilling costs and development costs are depleted on the basis of proved developed reserves. For purposes of the depletion calculation, production and reserves volumes for oil and natural gas are converted to a common unit of measure on the basis of their approximate relative energy content. Gas plants, support facilities and equipment are depreciated on a straight-line basis over their useful lives, which average 12 years.
DOWNSTREAM OPERATIONS (INCLUDING ENERGY MARKETING AND REFINING – CANADA AND REFINING AND MARKETING – U.S.A.) Depreciation of property, plant and equipment is provided on a straight-line basis over the useful lives of assets. The Sarnia and Denver refineries and additions thereto are depreciated over an average of 30 years, service stations and related equipment over an average of 20 years and pipeline facilities and other equipment over three to 40 years. Intangible assets with determinable useful lives are amortized over a maximum period of four years. The amortization of intangible assets is included within depreciation expense in the Consolidated Statements of Earnings.
Asset Retirement Obligations
On January 1, 2004, the company retroactively adopted the new Canadian accounting standard related to “Asset Retirement Obligations” (ARO). Under the new standard, a liability is recognized for the future retirement obligations associated with the company’s property, plant and equipment. The fair value of the ARO is recorded on a discounted basis. This amount is capitalized as part of the cost of the related asset and amortized to expense over its useful life. The liability accretes until the company settles the obligation.
Suncor Energy Inc. 2004 Annual Report
59
Impairment
Property, plant and equipment, including capitalized asset retirement costs are reviewed for impairment whenever events or conditions indicate that their net carrying amount, less future income taxes, may not be recoverable from estimated undiscounted future cash flows. If it is determined that the estimated net recoverable amount is less than the net carrying amount, a write-down to the asset’s fair value is recognized during the period, with a charge to earnings.
Disposals
Gains or losses on disposals of non-oil and gas property, plant and equipment are recognized in earnings. For oil and gas property, plant and equipment, gains or losses are recognized in earnings for significant disposals or disposal of an entire property. However, the acquisition cost of a subsequently surrendered or abandoned unproved property that is not individually significant, or a partial abandonment of a proved property, is charged to accumulated depreciation, depletion or amortization.
(e) Deferred Charges and Other
Deferred charges and other are primarily comprised of deferred overburden removal costs, deferred maintenance shutdown costs and deferred financing costs.
Overburden removal may precede mining of the oil sands deposit by as much as two years. Accordingly, the company employs a deferral method of accounting for overburden removal costs where all such costs are initially recorded as a deferred charge (see note 4), rather than expensing overburden removal costs as incurred. These deferred charges are allocated to the mining activity in the year on a last-in, first-out (LIFO) basis using stripping ratios based on a life-of-mine approach for each mine pit whereby all of the overburden to be removed is related to all of the oil sands proved and probable ore reserves. Amortization of deferred overburden removal cost is reported as part of the depreciation, depletion and amortization expense in the Consolidated Statements of Earnings. Stripping ratios are regularly reviewed to reflect changes in operating experience and other factors.
The cost of major maintenance shutdowns is deferred and amortized on a straight-line basis over the period to the next shutdown, which varies from three to seven years. Normal maintenance and repair costs are charged to expense as incurred.
Financing costs related to the issuance of long-term debt are amortized over the term of the related debt.
(f) Employee Future Benefits
The company’s employee future benefit programs consist of defined benefit and defined contribution pension plans, as well as other post-retirement benefits.
The estimated future cost of providing defined benefit pension and other post-retirement benefits is actuarially determined using management’s best estimates of demographic and financial assumptions, and such cost is accrued ratably from the date of hire of the employee to the date the employee becomes fully eligible to receive the benefits. The discount rate used to determine accrued benefit obligations is based on a year-end market rate of interest for high quality debt instruments with cash flows that match the timing and amount of expected benefit payments. Company contributions to the defined contribution plan are expensed as incurred.
(g) Inventories
Inventories of crude oil and refined products are valued at the lower of cost (using the LIFO method) and net realizable value.
Materials and supplies are valued at the lower of average cost and net realizable value.
Costs include direct and indirect expenditures incurred in bringing an item or product to its existing condition and location.
(h) Derivative Financial Instruments
The company periodically enters into derivative financial instrument commodity contracts such as forwards, futures, swaps and options to hedge against the potential adverse impact of changing market prices due to changes in the underlying commodity indices. The company also periodically enters into derivative financial instrument contracts such as interest rate swaps as part of its risk management strategy to manage exposure to interest rate fluctuations.
These derivative contracts are initiated within the guidelines of the company’s risk management policies, which require stringent authorities for approval and commitment of contracts, designation of the contracts by management as hedges of the related transactions, and monitoring of the effectiveness of such contracts in reducing the related risks. Contract maturities are consistent with the settlement dates of the related hedged transactions.
Derivative contracts accounted for as hedges are not recognized in the Consolidated Balance Sheets. Gains or losses on these contracts, including realized gains and losses on hedging derivative contracts settled prior to maturity, are recognized in earnings and cash flows when the related sales revenues, costs, interest expense and cash flows are recognized. Gains or
Suncor Energy Inc. 2004 Annual Report
60
losses resulting from changes in the fair value of derivative contracts that do not qualify for hedge accounting are recognized in earnings and cash flows when those changes occur.
Canadian Accounting Guideline 13 (AcG 13), “Hedging Relationships,” is applicable to the company’s hedging relationships in 2004 and subsequent fiscal years. AcG 13 specifies the circumstances in which hedge accounting is appropriate, including the identification, documentation, designation and effectiveness of hedges, as well as the discontinuance of hedge accounting. The Guideline does not specify hedge accounting methods. The company believes that its hedging documentation and tests of effectiveness are prepared in accordance with the provisions of AcG-13.
The company also uses energy derivatives, including physical and financial swaps, forwards and options, to gain market information and to earn trading revenues. These energy marketing and trading activities are accounted for at fair value.
(i) Foreign Currency Translation
Monetary assets and liabilities denominated in foreign currencies are translated to Canadian dollars at rates of exchange in effect at the end of the period. Other assets and related depreciation, depletion and amortization, other liabilities, revenues and expenses are translated at rates of exchange in effect at the respective transaction dates. The resulting exchange gains and losses are included in earnings.
The company’s Refining and Marketing – U.S.A. operations are classified as self-sustaining and are translated into Canadian dollars using the current rate method. Assets and liabilities are translated at the period end exchange rate, while revenues and expenses are translated using average exchange rates during the period. Translation gains or losses are included in cumulative foreign exchange adjustments in the Consolidated Statements of Changes in Shareholders’ Equity.
(j) Stock-based Compensation Plans
Under the company’s common share option programs (see note 13), common share options are granted to executives, employees and non-employee directors.
Compensation expense is recorded in the Consolidated Statements of Earnings as operating, selling and general expense for all common share options granted to employees and non-employee directors on or after January 1, 2003, with a corresponding increase recorded as contributed surplus in the Consolidated Statements of Changes in Shareholders’ Equity. The expense is based on the fair values of the option at the time of grant and is recognized in the Consolidated Statements of Earnings over the estimated vesting periods of the respective options. For common share options granted prior to January 1, 2003 (“pre-2003 options”), compensation expense is not recognized in the Consolidated Statement of Earnings. The company continues to disclose the pro forma earnings impact of related stock-based compensation expense for pre-2003 options. Consideration paid to the company on exercise of options is credited to share capital.
Stock-based compensation awards that are to be settled in cash are measured using the fair value based method of accounting.
(k) Transportation Costs
Transportation costs billed to customers are classified as revenues with the related transportation costs classified as transportation and other costs in the Consolidated Statements of Earnings.
(l) Recently Issued Canadian Accounting Standards
Variable Interest Entities
In 2003, Canadian Accounting Guideline 15 (AcG 15), “Consolidation of Variable Interest Entities” (VIEs), was issued. Effective January 1, 2005, AcG 15 requires consolidation of a VIE where the company will absorb a majority of a VIE’s losses, receive a majority of its returns, or both. The company will be required to consolidate the VIE related to the sale of equipment as described in note 11(c). The company does not expect a significant impact on net earnings upon consolidation of the equipment VIE. The impact on the balance sheet will be an increase to property, plant and equipment of $14 million, an increase to inventory of $8 million, and an increase to long-term debt of $22 million. The company’s accounts receivable securitization program described in note 11(c), as currently structured, does not meet the AcG 15 criteria for consolidation by Suncor.
Liabilities and Equity
In 2003, the Canadian Accounting Standards Board approved an amendment to its Handbook Section 3860 “Financial Instruments – Disclosure and Presentation” requiring certain obligations that must or could be settled with an entity’s own equity instruments to be presented as liabilities. The amendment, effective for the company’s 2005 fiscal year and applied on a retroactive basis, will affect the company’s current presentation of preferred securities as equity (see note 12). The reclassification of the preferred securities from equity to long-term debt is expected to increase property, plant and equipment by $37 million, and increase depreciation, depletion and amortization by $1 million.
Suncor Energy Inc. 2004 Annual Report
61
consolidated statements of earnings
For the years ended December 31 ($ millions) |
| 2004 |
| 2003 |
| 2002 |
|
Revenues |
|
|
|
|
|
|
|
Operating revenues (notes 7, 17 and 18) |
| 8 226 |
| 6 289 |
| 4 883 |
|
Energy marketing and trading activities (note 7c) |
| 392 |
| 276 |
| 147 |
|
Interest |
| 3 |
| 6 |
| 2 |
|
|
| 8 621 |
| 6 571 |
| 5 032 |
|
Expenses |
|
|
|
|
|
|
|
Purchases of crude oil and products |
| 2 867 |
| 1 686 |
| 1 156 |
|
Operating, selling and general |
| 1 769 |
| 1 478 |
| 1 274 |
|
Energy marketing and trading activities (note 7) |
| 373 |
| 279 |
| 142 |
|
Transportation and other costs |
| 132 |
| 135 |
| 128 |
|
Depreciation, depletion and amortization |
| 717 |
| 618 |
| 595 |
|
Accretion of asset retirement obligations |
| 26 |
| 25 |
| 25 |
|
Exploration (note 18) |
| 55 |
| 51 |
| 26 |
|
Royalties (note 5) |
| 531 |
| 139 |
| 98 |
|
Taxes other than income taxes (note 18) |
| 496 |
| 426 |
| 374 |
|
(Gain) on disposal of assets |
| (16 | ) | (17 | ) | (2 | ) |
(Gain) on sale of retail natural gas marketing business (note 18) |
| — |
| — |
| (38 | ) |
Project start-up costs |
| 26 |
| 16 |
| 3 |
|
Financing expenses (income) (note 15) |
| 9 |
| (66 | ) | 124 |
|
|
| 6 985 |
| 4 770 |
| 3 905 |
|
Earnings Before Income Taxes |
| 1 636 |
| 1 801 |
| 1 127 |
|
Provision for income taxes (note 10) |
|
|
|
|
|
|
|
Current |
| 69 |
| 38 |
| 74 |
|
Future |
| 467 |
| 688 |
| 304 |
|
|
| 536 |
| 726 |
| 378 |
|
Net Earnings |
| 1 100 |
| 1 075 |
| 749 |
|
Dividends on preferred securities, net of tax (note 12) |
| (6 | ) | (27 | ) | (28 | ) |
Revaluation of US$ preferred securities, net of tax |
| (6 | ) | 37 |
| 1 |
|
Net earnings attributable to common shareholders |
| 1 088 |
| 1 085 |
| 722 |
|
|
|
|
|
|
|
|
|
Per Common Share (dollars) (note 14) |
|
|
|
|
|
|
|
Net earnings attributable to common shareholders |
|
|
|
|
|
|
|
Basic |
| 2.40 |
| 2.41 |
| 1.61 |
|
Diluted |
| 2.36 |
| 2.24 |
| 1.58 |
|
Cash dividends |
| 0.23 |
| 0.1925 |
| 0.17 |
|
See accompanying Summary of Significant Accounting Policies and Notes.
Suncor Energy Inc. 2004 Annual Report
62
consolidated balance sheets
As at December 31 ($ millions) |
| 2004 |
| 2003 |
|
Assets |
|
|
|
|
|
Current assets |
|
|
|
|
|
Cash and cash equivalents |
| 88 |
| 388 |
|
Accounts receivable (notes 11c and 18) |
| 627 |
| 505 |
|
Inventories (note 16) |
| 423 |
| 371 |
|
Future income taxes (note 10) |
| 57 |
| 15 |
|
Total current assets |
| 1 195 |
| 1 279 |
|
Property, plant and equipment, net (note 3) |
| 10 289 |
| 8 936 |
|
Deferred charges and other (note 4) |
| 320 |
| 286 |
|
Total assets |
| 11 804 |
| 10 501 |
|
Liabilities and Shareholders’ Equity |
|
|
|
|
|
Current liabilities |
|
|
|
|
|
Short-term debt |
| 30 |
| 31 |
|
Accounts payable and accrued liabilities (notes 8 and 9) |
| 1 306 |
| 970 |
|
Income taxes payable |
| 32 |
| 9 |
|
Taxes other than income taxes |
| 41 |
| 49 |
|
Future income taxes (note 10) |
| — |
| 1 |
|
Total current liabilities |
| 1 409 |
| 1 060 |
|
Long-term debt (note 6) |
| 2 217 |
| 2 448 |
|
Accrued liabilities and other (notes 8 and 9) |
| 749 |
| 616 |
|
Future income taxes (note 10) |
| 2 532 |
| 2 022 |
|
Total liabilities |
| 6 907 |
| 6 146 |
|
|
|
|
|
|
|
Commitments and contingencies (note 11) |
|
|
|
|
|
|
|
|
|
|
|
Shareholders’ equity |
|
|
|
|
|
Preferred securities (note 12) |
| — |
| 476 |
|
Share capital (note 13) |
| 651 |
| 604 |
|
Contributed surplus (note 13) |
| 32 |
| 7 |
|
Cumulative foreign currency translation |
| (55 | ) | (26 | ) |
Retained earnings |
| 4 269 |
| 3 294 |
|
Total shareholders’ equity |
| 4 897 |
| 4 355 |
|
Total liabilities and shareholders’ equity |
| 11 804 |
| 10 501 |
|
See accompanying Summary of Significant Accounting Policies and Notes.
Approved on behalf of the Board of Directors:
/s/ Richard L. George |
| /s/ John T. Ferguson |
|
Richard L. George | John T. Ferguson | ||
Director | Director | ||
|
| ||
February 23, 2005 |
|
Suncor Energy Inc. 2004 Annual Report
63
consolidated statements of cash flows
For the years ended December 31 ($ millions) |
| 2004 |
| 2003 |
| 2002 |
|
Operating Activities |
|
|
|
|
|
|
|
Cash flow from operations (a) |
| 2 021 |
| 2 079 |
| 1 440 |
|
Decrease (increase) in operating working capital (net of effects of acquisition of Denver refinery and related assets) |
|
|
|
|
|
|
|
Accounts receivable |
| (121 | ) | (105 | ) | (97 | ) |
Inventories |
| (51 | ) | (19 | ) | (8 | ) |
Accounts payable and accrued liabilities |
| 337 |
| 258 |
| 44 |
|
Taxes payable |
| 16 |
| 5 |
| 77 |
|
Cash flow from operating activities |
| 2 202 |
| 2 218 |
| 1 456 |
|
Cash Used in Investing Activities (a) |
| (1 824 | ) | (1 702 | ) | (861 | ) |
Net Cash Surplus Before Financing Activities |
| 378 |
| 516 |
| 595 |
|
Financing Activities |
|
|
|
|
|
|
|
Increase (decrease) in short-term debt |
| (1 | ) | 31 |
| (31 | ) |
Proceeds from issuance of long-term debt |
| — |
| 651 |
| 797 |
|
Net decrease in other long-term debt |
| (142 | ) | (716 | ) | (1 245 | ) |
Redemption of preferred securities (note 12) |
| (493 | ) | — |
| — |
|
Issuance of common shares under stock option plans |
| 41 |
| 20 |
| 19 |
|
Dividends paid on preferred securities |
| (9 | ) | (45 | ) | (48 | ) |
Dividends paid on common shares |
| (97 | ) | (81 | ) | (73 | ) |
Deferred revenue |
| 26 |
| — |
| — |
|
Cash flow used in financing activities |
| (675 | ) | (140 | ) | (581 | ) |
Increase (Decrease) in Cash and Cash Equivalents |
| (297 | ) | 376 |
| 14 |
|
Effect of Foreign Exchange on Cash and Cash Equivalents |
| (3 | ) | (3 | ) | — |
|
Cash and Cash Equivalents at Beginning of Year |
| 388 |
| 15 |
| 1 |
|
Cash and Cash Equivalents at End of Year |
| 88 |
| 388 |
| 15 |
|
(a) See Schedules of Segmented Data on pages 68 and 69.
See accompanying Summary of Significant Accounting Policies and Notes.
Suncor Energy Inc. 2004 Annual Report
64
consolidated statements of changes in shareholders ‘ equity
For the years ended December 31 ($ millions) |
| Preferred |
| Share |
| Contributed |
| Cumulative |
| Retained |
|
At December 31, 2001, as previously reported |
| 525 |
| 555 |
| — |
| — |
| 1 700 |
|
Retroactive adjustment for change in accounting policy, net of tax (note 1) |
| — |
| — |
| — |
| — |
| (49 | ) |
At December 31, 2001, as restated |
| 525 |
| 555 |
| — |
| — |
| 1 651 |
|
Net earnings |
| — |
| — |
| — |
| — |
| 749 |
|
Dividends paid on preferred securities, net of tax |
| — |
| — |
| — |
| — |
| (28 | ) |
Dividends paid on common shares |
| — |
| — |
| — |
| — |
| (73 | ) |
Issued for cash under stock option plans |
| — |
| 19 |
| — |
| — |
| — |
|
Issued under dividend reinvestment plan |
| — |
| 4 |
| — |
| — |
| (4 | ) |
Revaluation of US$ preferred securities |
| (2 | ) | — |
| — |
| — |
| 1 |
|
At December 31, 2002, as restated |
| 523 |
| 578 |
| — |
| — |
| 2 296 |
|
Net earnings |
| — |
| — |
| — |
| — |
| 1 075 |
|
Dividends paid on preferred securities, net of tax |
| — |
| — |
| — |
| — |
| (27 | ) |
Dividends paid on common shares |
| — |
| — |
| — |
| — |
| (81 | ) |
Issued for cash under stock option plans |
| — |
| 2 0 |
| — |
| — |
| — |
|
Issued under dividend reinvestment plan |
| — |
| 6 |
| — |
| — |
| (6 | ) |
Stock-based compensation expense |
| — |
| — |
| 7 |
| — |
| — |
|
Foreign currency translation adjustment |
| — |
| — |
| — |
| (26 | ) | — |
|
Revaluation of US$ preferred securities |
| (47 | ) | — |
| — |
| — |
| 37 |
|
At December 31, 2003, as restated |
| 476 |
| 604 |
| 7 |
| (26 | ) | 3 294 |
|
Net earnings |
| — |
| — |
| — |
| — |
| 1 100 |
|
Dividends paid on preferred securities, net of tax |
| — |
| — |
| — |
| — |
| (6 | ) |
Dividends paid on common shares |
| — |
| — |
| — |
| — |
| (97 | ) |
Issued for cash under stock option plans |
| — |
| 41 |
| — |
| — |
| — |
|
Issued under dividend reinvestment plan |
| — |
| 6 |
| — |
| — |
| (6 | ) |
Stock-based compensation expense |
| — |
| — |
| 25 |
| — |
| — |
|
Foreign currency translation adjustment |
| — |
| — |
| — |
| (29 | ) | — |
|
Revaluation of US$ preferred securities |
| 7 |
| — |
| — |
| — |
| (6 | ) |
Reclassification of issue costs for preferred securities |
| 10 |
| — |
| — |
| — |
| (10 | ) |
Redemption of preferred securities (note 12) |
| (493 | ) | — |
| — |
| — |
| — |
|
At December 31, 2004 |
| — |
| 651 |
| 32 |
| (55 | ) | 4 269 |
|
See accompanying Summary of Significant Accounting Policies and Notes.
Suncor Energy Inc. 2004 Annual Report
65
schedules of segmented data (a)
|
| Oil Sands |
| Natural Gas |
| Energy Marketing |
| ||||||||||||
For the years ended December 31 ($ millions) |
| 2004 |
| 2003 |
| 2002 |
| 2004 |
| 2003 |
| 2002 |
| 2004 |
| 2003 |
| 2002 |
|
EARNINGS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues (b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
| 3 171 |
| 2 676 |
| 2 241 |
| 499 |
| 436 |
| 279 |
| 3 060 |
| 2 660 |
| 2 361 |
|
Energy marketing and trading activities |
| — |
| — |
| — |
| — |
| — |
| — |
| 400 |
| 276 |
| 147 |
|
Intersegment revenues (c) |
| 425 |
| 385 |
| 375 |
| 68 |
| 76 |
| 60 |
| — |
| — |
| — |
|
Interest |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
|
|
| 3 596 |
| 3 061 |
| 2 616 |
| 567 |
| 512 |
| 339 |
| 3 460 |
| 2 936 |
| 2 508 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases of crude oil and products |
| 75 |
| 12 |
| 7 |
| — |
| — |
| 16 |
| 2 115 |
| 1 797 |
| 1 564 |
|
Operating, selling and general |
| 939 |
| 865 |
| 790 |
| 100 |
| 73 |
| 67 |
| 418 |
| 359 |
| 352 |
|
Energy marketing and trading activities |
| — |
| — |
| — |
| — |
| — |
| — |
| 381 |
| 279 |
| 142 |
|
Transportation and other costs |
| 88 |
| 101 |
| 104 |
| 21 |
| 24 |
| 24 |
| 3 |
| 3 |
| — |
|
Depreciation, depletion and amortization |
| 503 |
| 458 |
| 458 |
| 115 |
| 91 |
| 75 |
| 69 |
| 59 |
| 60 |
|
Accretion of asset retirement obligations |
| 21 |
| 21 |
| 19 |
| 4 |
| 3 |
| 4 |
| 1 |
| 1 |
| 2 |
|
Exploration |
| 17 |
| 11 |
| 9 |
| 38 |
| 40 |
| 17 |
| — |
| — |
| — |
|
Royalties (note 5) |
| 407 |
| 33 |
| 33 |
| 124 |
| 106 |
| 65 |
| — |
| — |
| — |
|
Taxes other than income taxes |
| 28 |
| 24 |
| 23 |
| 2 |
| 3 |
| 2 |
| 352 |
| 342 |
| 348 |
|
(Gain) loss on disposal of assets |
| 4 |
| (1 | ) | 2 |
| (19 | ) | (12 | ) | (4 | ) | (2 | ) | (4 | ) | — |
|
(Gain) on sale of retail natural gas marketing business |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| (38 | ) |
Project start-up costs |
| 26 |
| 10 |
| 3 |
| — |
| — |
| — |
| — |
| — |
| — |
|
Financing expenses (income) |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
|
|
| 2 108 |
| 1 534 |
| 1 448 |
| 385 |
| 328 |
| 266 |
| 3 337 |
| 2 836 |
| 2 430 |
|
Earnings (loss) before income taxes |
| 1 488 |
| 1 527 |
| 1 168 |
| 182 |
| 184 |
| 73 |
| 123 |
| 100 |
| 78 |
|
Provision for income taxes |
| (493 | ) | (639 | ) | (386 | ) | (67 | ) | (64 | ) | (39 | ) | (43 | ) | (47 | ) | (17 | ) |
Net earnings (loss) |
| 995 |
| 888 |
| 782 |
| 115 |
| 120 |
| 34 |
| 80 |
| 53 |
| 61 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS |
| 9 032 |
| 7 934 |
| 7 186 |
| 965 |
| 763 |
| 793 |
| 1 321 |
| 1 080 |
| 978 |
|
(a) Accounting policies for segments are the same as those described in the Summary of Significant Accounting Policies.
(b) There were no customers that represented 10% or more of the company’s 2004 or 2003 consolidated revenues. (2002 – one customer represented 10% or more ($641 million)).
(c) Intersegment revenues are recorded at prevailing fair market prices and accounted for as if the sales were to third parties.
See accompanying Summary of Significant Accounting Policies and Notes.
Suncor Energy Inc. 2004 Annual Report
66
|
| Refining and Marketing |
| Corporate and Eliminations |
| Total |
| ||||||||||||
For the years ended December 31 ($ millions) |
| 2004 |
| 2003 |
| 2002 |
| 2004 |
| 2003 |
| 2002 |
| 2004 |
| 2003 |
| 2002 |
|
EARNINGS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues (b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
| 1 494 |
| 515 |
| — |
| 2 |
| 2 |
| 2 |
| 8 226 |
| 6 289 |
| 4 883 |
|
Energy marketing and trading activities |
| — |
| — |
| — |
| (8 | ) | — |
| — |
| 392 |
| 276 |
| 147 |
|
Intersegment revenues (c) |
| — |
| — |
| — |
| (493 | ) | (461 | ) | (435 | ) | — |
| — |
| — |
|
Interest |
| 1 |
| — |
| — |
| 2 |
| 6 |
| 2 |
| 3 |
| 6 |
| 2 |
|
|
| 1 495 |
| 515 |
| — |
| (497 | ) | (453 | ) | (431 | ) | 8 621 |
| 6 571 |
| 5 032 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases of crude oil and products |
| 1 171 |
| 340 |
| — |
| (494 | ) | (463 | ) | (431 | ) | 2 867 |
| 1 686 |
| 1 156 |
|
Operating, selling and general |
| 124 |
| 68 |
| — |
| 188 |
| 113 |
| 65 |
| 1 769 |
| 1 478 |
| 1 274 |
|
Energy marketing and trading activities |
| — |
| — |
| — |
| (8 | ) | — |
| — |
| 373 |
| 279 |
| 142 |
|
Transportation and other costs |
| 20 |
| 7 |
| — |
| — |
| — |
| — |
| 132 |
| 135 |
| 128 |
|
Depreciation, depletion and amortization |
| 22 |
| 6 |
| — |
| 8 |
| 4 |
| 2 |
| 717 |
| 618 |
| 595 |
|
Accretion of asset retirement obligations |
| — |
| — |
| — |
| — |
| — |
| — |
| 26 |
| 25 |
| 25 |
|
Exploration |
| — |
| — |
| — |
| — |
| — |
| — |
| 55 |
| 51 |
| 26 |
|
Royalties (note 5) |
| — |
| — |
| — |
| — |
| — |
| — |
| 531 |
| 139 |
| 98 |
|
Taxes other than income taxes |
| 114 |
| 57 |
| — |
| — |
| — |
| 1 |
| 496 |
| 426 |
| 374 |
|
(Gain) loss on disposal of assets |
| 1 |
| — |
| — |
| — |
| — |
| — |
| (16 | ) | (17 | ) | (2 | ) |
(Gain) on sale of retail natural gas marketing business |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| (38 | ) |
Project start-up costs |
| — |
| 6 |
| — |
| — |
| — |
| — |
| 26 |
| 16 |
| 3 |
|
Financing expenses (income) |
| — |
| — |
| — |
| 9 |
| (66 | ) | 124 |
| 9 |
| (66 | ) | 124 |
|
|
| 1 452 |
| 484 |
| — |
| (297 | ) | (412 | ) | (239 | ) | 6 985 |
| 4 770 |
| 3 905 |
|
Earnings (loss) before income taxes |
| 43 |
| 31 |
| — |
| (200 | ) | (41 | ) | (192 | ) | 1 636 |
| 1 801 |
| 1 127 |
|
Provision for income taxes |
| (9 | ) | (13 | ) | — |
| 76 |
| 37 |
| 64 |
| (536 | ) | (726 | ) | (378 | ) |
Net earnings (loss) |
| 34 |
| 18 |
| — |
| (124 | ) | (4 | ) | (128 | ) | 1 100 |
| 1 075 |
| 749 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS |
| 518 |
| 442 |
| — |
| (32 | ) | 282 |
| 54 |
| 11 804 |
| 10 501 |
| 9 011 |
|
Suncor Energy Inc. 2004 Annual Report
67
schedules of segmented data (a) (continued)
|
| Oil Sands |
| Natural Gas |
| Energy Marketing |
| ||||||||||||
For the years ended December 31 ($ millions) |
| 2004 |
| 2003 |
| 2002 |
| 2004 |
| 2003 |
| 2002 |
| 2004 |
| 2003 |
| 2002 |
|
CASH FLOW BEFORE FINANCING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash from (used in) operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from (used in) operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) |
| 995 |
| 888 |
| 782 |
| 115 |
| 120 |
| 34 |
| 80 |
| 53 |
| 61 |
|
Exploration expenses |
| — |
| — |
| — |
| 38 |
| 40 |
| 17 |
| — |
| — |
| — |
|
Non-cash items included in earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
| 503 |
| 458 |
| 458 |
| 115 |
| 91 |
| 75 |
| 69 |
| 59 |
| 60 |
|
Income taxes |
| 493 |
| 639 |
| 386 |
| 67 |
| 64 |
| 39 |
| 43 |
| 47 |
| 17 |
|
(Gain) loss on disposal of assets |
| 4 |
| (1 | ) | 2 |
| (19 | ) | (12 | ) | (4 | ) | (2 | ) | (4 | ) | (38 | ) |
Stock-based compensation expense |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
|
Other |
| (29 | ) | 4 |
| 15 |
| 4 |
| (5 | ) | 4 |
| (3 | ) | 10 |
| 11 |
|
Overburden removal outlays |
| (222 | ) | (175 | ) | (160 | ) | — |
| — |
| — |
| — |
| — |
| — |
|
Increase (decrease) in deferred credits and other |
| 8 |
| (10 | ) | (8 | ) | (1 | ) | — |
| (1 | ) | 1 |
| (1 | ) | 1 |
|
Total cash flow from (used in) operations |
| 1 752 |
| 1 803 |
| 1 475 |
| 319 |
| 298 |
| 164 |
| 188 |
| 164 |
| 112 |
|
Decrease (increase) in operating working capital (net of effects of acquisition of Denver refinery and related assets) |
| 71 |
| 51 |
| (116 | ) | (1 | ) | 11 |
| 22 |
| 50 |
| — |
| (15 | ) |
Total cash from (used in) operating activities |
| 1 823 |
| 1 854 |
| 1 359 |
| 318 |
| 309 |
| 186 |
| 238 |
| 164 |
| 97 |
|
Cash from (used in) investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital and exploration expenditures |
| (1 118 | ) | (948 | ) | (617 | ) | (279 | ) | (183 | ) | (163 | ) | (228 | ) | (122 | ) | (60 | ) |
Acquisition of Denver refinery and related assets |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
|
Deferred maintenance shutdown expenditures |
| (4 | ) | (100 | ) | (9 | ) | (1 | ) | — |
| — |
| (20 | ) | (17 | ) | (18 | ) |
Deferred outlays and other investments |
| (9 | ) | (10 | ) | (4 | ) | — |
| — |
| — |
| (14 | ) | (2 | ) | (18 | ) |
Proceeds from disposals |
| 45 |
| 3 |
| — |
| 29 |
| 17 |
| 5 |
| 3 |
| 6 |
| 62 |
|
Total cash (used in) investing activities |
| (1 086 | ) | (1 055 | ) | (630 | ) | (251 | ) | (166 | ) | (158 | ) | (259 | ) | (135 | ) | (34 | ) |
Net cash surplus (deficiency) before financing activities |
| 737 |
| 799 |
| 729 |
| 67 |
| 143 |
| 28 |
| (21 | ) | 29 |
| 63 |
|
(a) Accounting policies for segments are the same as those described in the Summary of Significant Accounting Policies.
See accompanying Summary of Significant Accounting Policies and Notes.
68
|
| Refining and Marketing |
| Corporate and Eliminations |
| Total |
| ||||||||||||
For the years ended December 31 ($ millions) |
| 2004 |
| 2003 |
| 2002 |
| 2004 |
| 2003 |
| 2002 |
| 2004 |
| 2003 |
| 2002 |
|
CASH FLOW BEFORE FINANCING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash from (used in) operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from (used in) operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) |
| 34 |
| 18 |
| — |
| (124 | ) | (4 | ) | (128 | ) | 1 100 |
| 1 075 |
| 749 |
|
Exploration expenses |
| — |
| — |
| — |
| — |
| — |
| — |
| 38 |
| 40 |
| 17 |
|
Non-cash items included in earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
| 22 |
| 6 |
| — |
| 8 |
| 4 |
| 2 |
| 717 |
| 618 |
| 595 |
|
Income taxes |
| 9 |
| 13 |
| — |
| (145 | ) | (75 | ) | (138 | ) | 467 |
| 688 |
| 304 |
|
(Gain) loss on disposal of assets |
| 1 |
| — |
| — |
| — |
| — |
| — |
| (16 | ) | (17 | ) | (40 | ) |
Stock-based compensation expense |
| — |
| — |
| — |
| 25 |
| 7 |
| — |
| 25 |
| 7 |
| — |
|
Other |
| (8 | ) | (2 | ) | — |
| (78 | ) | (163 | ) | (3 | ) | (114 | ) | (156 | ) | 27 |
|
Overburden removal outlays |
| — |
| — |
| — |
| — |
| — |
| — |
| (222 | ) | (175 | ) | (160 | ) |
Increase (decrease) in deferred credits and other |
| 1 |
| (1 | ) | — |
| 17 |
| 11 |
| (44 | ) | 26 |
| (1 | ) | (52 | ) |
Total cash flow from (used in) operations |
| 59 |
| 34 |
| — |
| (297 | ) | (220 | ) | (311 | ) | 2 021 |
| 2 079 |
| 1 440 |
|
Decrease (increase) in operating working capital (net of effects of acquisition of Denver refinery and related assets) |
| 68 |
| 46 |
| — |
| (7 | ) | 31 |
| 125 |
| 181 |
| 139 |
| 16 |
|
Total cash from (used in) operating activities |
| 127 |
| 80 |
| — |
| (304 | ) | (189 | ) | (186 | ) | 2 202 |
| 2 218 |
| 1 456 |
|
Cash from (used in) investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital and exploration expenditures |
| (190 | ) | (31 | ) | — |
| (31 | ) | (32 | ) | (37 | ) | (1 846 | ) | (1 316 | ) | (877 | ) |
Acquisition of Denver refinery and related assets |
| — |
| (272 | ) | — |
| — |
| — |
| — |
| — |
| (272 | ) | — |
|
Deferred maintenance shutdown expenditures |
| (7 | ) | — |
| — |
| — |
| — |
| — |
| (32 | ) | (117 | ) | (27 | ) |
Deferred outlays and other investments |
| (1 | ) | 3 |
| — |
| 1 |
| (14 | ) | (2 | ) | (23 | ) | (23 | ) | (24 | ) |
Proceeds from disposals |
| — |
| — |
| — |
| — |
| — |
| — |
| 77 |
| 26 |
| 67 |
|
Total cash (used in) investing activities |
| (198 | ) | (300 | ) | — |
| (30 | ) | (46 | ) | (39 | ) | (1 824 | ) | (1 702 | ) | (861 | ) |
Net cash surplus (deficiency) before financing activities |
| (71 | ) | (220 | ) | — |
| (334 | ) | (235 | ) | (225 | ) | 378 |
| 516 |
| 595 |
|
Suncor Energy Inc. 2004 Annual Report
69
notes to the consolidated financial statements
1. CHANGE IN ACCOUNTING POLICY
On January 1, 2004, the company retroactively adopted a new accounting policy for asset retirement obligations (see Summary of Significant Accounting Policies). The 2003 and estimated 2004 impact of adopting the new Canadian accounting standard compared to the previous standard is:
Change in Consolidated Balance Sheets
($ millions, increase/(decrease)) |
| 2004 |
| 2003 |
|
Property, plant and equipment |
| 284 |
| 211 |
|
Future income tax assets |
| 33 |
| 37 |
|
Total assets |
| 317 |
| 248 |
|
Accounts payable and accrued liabilities |
| — |
| (2 | ) |
Accrued liabilities and other |
| 382 |
| 320 |
|
Retained earnings |
| (65 | ) | (70 | ) |
Total liabilities and shareholders’ equity |
| 317 |
| 248 |
|
Change in Consolidated Statements of Earnings
($ millions, increase/(decrease)) |
| 2004 |
| 2003 |
| 2002 |
|
Depreciation, depletion and amortization |
| 9 |
| 7 |
| 10 |
|
Accretion of asset retirement obligations |
| 26 |
| 25 |
| 25 |
|
Operating, selling and general expenses |
| (43 | ) | (29 | ) | (18 | ) |
Future income taxes |
| 3 |
| 6 |
| (5 | ) |
Net earnings |
| 5 |
| (9 | ) | (12 | ) |
Per common share – basic (dollars) |
| 0.01 |
| (0.02 | ) | (0.03 | ) |
Per common share – diluted (dollars) |
| 0.01 |
| (0.02 | ) | (0.03 | ) |
See note 8 for a reconciliation of the beginning and ending aggregate carrying amount of the asset retirement obligation.
2. ACQUISITION OF REFINERY AND RELATED ASSETS
On August 1, 2003, the company acquired a Denver refinery, 43 retail stations and associated storage, pipeline and distribution facilities, and inventory from ConocoPhillips for cash consideration of $272 million. The purchase price was determined through a competitive bid process. The results of operations for these assets have been included in the consolidated financial statements from the date of acquisition.
The acquisition was accounted for by the purchase method of accounting. The allocation of fair value to the assets acquired and liabilities assumed was:
($ millions) |
|
|
|
Property, plant and equipment, and intangible assets |
| 242 |
|
Inventory |
| 88 |
|
Other assets |
| 9 |
|
Total assets acquired |
| 339 |
|
Liabilities assumed |
| (67 | ) |
Net assets acquired |
| 272 |
|
Suncor Energy Inc. 2004 Annual Report
70
Suncor recorded an environmental liability of $9 million at the acquisition date for the estimated costs of environmental clean-up work currently under way. A $9 million receivable was also recorded as ConocoPhillips agreed to indemnify Suncor for these costs. The recorded liability is part of an agreement between Suncor and ConocoPhillips whereby Suncor will be indemnified for any reclamation work identified prior to closing for a period up to 10 years from acquisition date, and up to $30 million. Additional costs ordered by a governmental agency are subject to indemnification from ConocoPhillips on a rolling 10-year limitation period from the date the contamination is discovered by Suncor. There is no time or dollar limit for any third-party claims against Suncor for which ConocoPhillips is liable.
Additionally, a $39 million liability was recorded at acquisition for environmental work required pursuant to a consent decree between ConocoPhillips, the Colorado Department of Public Health and the Environment and the United States Environmental Protection Agency.
For segmented reporting purposes, the results of the new Denver-based operations since the date of acquisition are reported in a new operating segment (Refining and Marketing – U.S.A.) in the accompanying Schedules of Segmented Data.
3. PROPERTY, PLANT AND EQUIPMENT
|
| 2004 |
| 2003 |
| ||||
($ millions) |
| Cost |
| Accumulated |
| Cost |
| Accumulated |
|
Oil Sands |
|
|
|
|
|
|
|
|
|
Plant |
| 5 156 |
| 929 |
| 4 721 |
| 828 |
|
Mine and mobile equipment |
| 1 313 |
| 480 |
| 1 267 |
| 426 |
|
In-situ properties |
| 1 267 |
| 26 |
| 867 |
| — |
|
Pipeline |
| 101 |
| 48 |
| 100 |
| 46 |
|
Capital leases |
| 29 |
| 25 |
| 130 |
| 18 |
|
Major projects in progress |
| 1 486 |
| — |
| 1 232 |
| — |
|
Asset retirement cost |
| 325 |
| 71 |
| 267 |
| 63 |
|
|
| 9 677 |
| 1 579 |
| 8 584 |
| 1 381 |
|
Natural Gas |
|
|
|
|
|
|
|
|
|
Proved properties |
| 1 396 |
| 653 |
| 1 206 |
| 552 |
|
Unproved properties |
| 124 |
| 18 |
| 114 |
| 38 |
|
Other support facilities and equipment |
| 18 |
| 13 |
| 18 |
| 12 |
|
Asset retirement cost |
| 27 |
| 3 |
| 4 |
| 2 |
|
|
| 1 565 |
| 687 |
| 1 342 |
| 604 |
|
Energy Marketing and Refining – Canada |
|
|
|
|
|
|
|
|
|
Refinery |
| 875 |
| 468 |
| 874 |
| 443 |
|
Marketing |
| 525 |
| 248 |
| 494 |
| 239 |
|
Major projects in progress |
| 171 |
| — |
| — |
| — |
|
Asset retirement cost |
| 11 |
| 5 |
| 10 |
| 5 |
|
|
| 1 582 |
| 721 |
| 1 378 |
| 687 |
|
Refining and Marketing – U.S.A. |
|
|
|
|
|
|
|
|
|
Refinery and intangible assets |
| 175 |
| 11 |
| 165 |
| 2 |
|
Marketing |
| 38 |
| 2 |
| 39 |
| 1 |
|
Pipeline |
| 25 |
| 1 |
| 27 |
| — |
|
Major projects in progress |
| 128 |
| — |
| — |
| — |
|
|
| 366 |
| 14 |
| 231 |
| 3 |
|
Corporate |
| 118 |
| 18 |
| 86 |
| 10 |
|
|
| 13 308 |
| 3 019 |
| 11 621 |
| 2 685 |
|
Net property, plant and equipment |
|
|
| 10 289 |
|
|
| 8 936 |
|
Suncor Energy Inc. 2004 Annual Report
71
4. DEFERRED CHARGES AND OTHER
($ millions) |
| 2004 |
| 2003 |
|
Oil Sands overburden removal costs (see below) |
| 67 |
| 51 |
|
Deferred maintenance shutdown costs |
| 129 |
| 137 |
|
Deferred financing costs |
| 25 |
| 26 |
|
Other |
| 99 |
| 72 |
|
Total deferred charges and other |
| 320 |
| 286 |
|
Oil Sands overburden removal costs |
|
|
|
|
|
Balance – beginning of year |
| 51 |
| 68 |
|
Outlays during the year |
| 222 |
| 175 |
|
Depreciation on equipment during year |
| 19 |
| 16 |
|
|
| 292 |
| 259 |
|
Amortization during year |
| (225 | ) | (208 | ) |
Balance – end of year |
| 67 |
| 51 |
|
5. ROYALTIES
Crown royalties in effect for each Oil Sands project require payments to the Government of Alberta, based on annual gross revenues less related transportation costs (R) less allowable costs (C), including the deduction of certain capital expenditures (the 25% R-C royalty), subject to a minimum payment of 1% of R. During 2004, the Alberta government confirmed it would modify Suncor’s royalty treatment because it does not recognize the company’s Firebag in-situ facility as an expansion to the company’s existing base mining and upgrading operations. Accordingly, for Alberta Crown royalty purposes, Suncor’s Oil Sands operations are considered as two separate projects: Suncor’s base Oil Sands mining and associated upgrading operations and Suncor’s Firebag in-situ oil sands project. On the basis of this classification, Suncor provided for Alberta Crown royalty obligations of $407 million in 2004 (2003 and 2002 – $33 million).
In July 2004, Suncor issued a statement of claim against the Province of Alberta, seeking, among other things, to overturn the Crown’s decision on the royalty treatment of Firebag. The Crown has issued a statement of defence. Should the company be successful in its claim, any recoveries would be recognized in the period they are realized.
6. LONG-TERM DEBT
($ millions) |
| 2004 |
| 2003 |
|
Fixed-term debt, redeemable at the option of the company |
|
|
|
|
|
5.95% Notes, denominated in U.S. dollars, due in 2034 (a) |
| 602 |
| 646 |
|
7.15% Notes, denominated in U.S. dollars, due in 2032 |
| 602 |
| 646 |
|
6.70% Series 2 Medium Term Notes, due in 2011(b) |
| 500 |
| 500 |
|
6.80% Medium Term Notes, due in 2007 (b) |
| 250 |
| 250 |
|
6.10% Medium Term Notes, due in 2007 (b) |
| 150 |
| 150 |
|
7.40% Debentures, Series C, repaid in 2004 |
| — |
| 125 |
|
|
| 2 104 |
| 2 317 |
|
Revolving-term debt, with interest at variable rates (see Credit Facilities) |
|
|
|
|
|
Commercial paper (interest at December 31, 2004 – 2.3%) (c) |
| 89 |
| — |
|
Total unsecured long-term debt |
| 2 193 |
| 2 317 |
|
Secured long-term debt with interest rates averaging 5.4% (2003 – 5.6%) |
| 5 |
| 4 |
|
Capital leases (d), (e) |
| 19 |
| 127 |
|
Total long-term debt |
| 2 217 |
| 2 448 |
|
(a) In 2003, the company issued 5.95% Notes with a principal amount of US$500 million (Cdn$ equivalent of $651 million).
(b) The company has entered into various interest rate swap transactions that are outstanding at December 31, 2004. The swap transactions result in an average effective interest rate that is different from the stated interest rate of the related underlying long-term debt instruments.
Description of Swap Transaction |
| Principal |
| Swap |
| 2004 Effective |
|
Swap of 6.10% Medium Term Notes to floating rates |
| 150 |
| 2007 |
| 3.6 | % |
Swap of 6.80% Medium Term Notes to floating rates |
| 250 |
| 2007 |
| 4.3 | % |
Swap of 6.70% Medium Term Notes to floating rates |
| 200 |
| 2011 |
| 3.5 | % |
Suncor Energy Inc. 2004 Annual Report
72
(c) The company is authorized to issue commercial paper to a maximum of $900 million having a term not to exceed 364 days. Commercial paper is supported by unutilized credit facilities.
(d) Obligations under capital leases are as follows:
($ millions) |
| 2004 |
| 2003 |
|
Energy services assets lease with interest at 6.82%, repaid in 2004 |
| — |
| 101 |
|
Other equipment leases with interest rates between prime plus 0.5% and 12.4% and maturity dates ranging from 2008 to 2029 |
| 19 |
| 26 |
|
|
| 19 |
| 127 |
|
(e) Future minimum amounts payable under capital leases and other long-term debt are as follows:
($ millions) |
| Capital |
| Other Long-term |
|
2005 |
| 3 |
| 90 |
|
2006 |
| 3 |
| 1 |
|
2007 |
| 3 |
| 401 |
|
2008 |
| 3 |
| — |
|
2009 |
| 3 |
| — |
|
Later years |
| 24 |
| 1 706 |
|
Total minimum payments |
| 39 |
| 2 198 |
|
Less amount representing imputed interest |
| 20 |
|
|
|
Present value of obligation under capital leases |
| 19 |
|
|
|
Long-term Debt (per cent) |
| 2004 |
| 2003 |
|
Variable rate |
| 31 |
| 25 |
|
Fixed rate |
| 69 |
| 75 |
|
Credit Facilities
At December 31, 2004, the company had available credit facilities of $1,730 million, of which $1,510 million was undrawn, as follows:
($ millions) |
|
|
|
Facility that is fully revolving for 364 days, has a term period of one year and expires in 2006 |
| 200 |
|
Facility that is fully revolving for a period of three years and expires in 2007 |
| 1 500 |
|
Facilities that can be terminated at any time at the option of the lenders |
| 30 |
|
Total available credit facilities |
| 1 730 |
|
Credit facilities supporting outstanding commercial paper and standby letters of credit |
| 220 |
|
Total undrawn credit facilities |
| 1 510 |
|
At December 31, 2004, the company had issued $131 million in letters of credit to various third parties.
Suncor Energy Inc. 2004 Annual Report
73
7. FINANCIAL INSTRUMENTS
Derivatives are financial instruments that either imitate or counter the price movements of stocks, bonds, currencies, commodities, and interest rates. Suncor uses derivatives to reduce (hedge) its exposure to fluctuations in commodity prices and foreign currency exchange rates and to manage interest or currency-sensitive assets and liabilities. Suncor also uses derivatives for trading purposes. When used in a trading activity, the company is attempting to realize a gain on the fluctuations in the market value of the derivative.
Forwards and futures are contracts to purchase or sell a specific item at a specified date and price. When used as hedges, forwards and futures manage the exposure to losses that could result if commodity prices or foreign currency exchange rates change adversely.
An option is a contract where its holder, for a fee, has purchased the right (but not the obligation) to buy or sell a specified item at a fixed price during a specified period. Options used as hedges can protect against adverse changes in commodity prices, interest rates, or foreign currency exchange rates.
A costless collar is a combination of two option contracts that limits the holder’s exposure to changes in prices to within a specific range. The “costless” nature of this derivative is achieved by buying a put option (the right to sell) for consideration equal to the premium received from selling a call option (the right to purchase).
A swap is a contract where two parties exchange commodity, currency, interest or other payments in order to alter the nature of the payments. For example, fixed interest rate payments on debt may be converted to payments based on a floating interest rate, or vice versa; a domestic currency debt may be converted to a foreign currency debt.
See below for more technical details and amounts.
(a) Balance Sheet Financial Instruments
The company’s financial instruments recognized in the Consolidated Balance Sheets consist of cash and cash equivalents, accounts receivable, derivative contracts not accounted for as hedges, substantially all current liabilities (except for the current portions of income taxes payable, future income taxes and retirement obligations), and long-term debt.
The estimated fair values of recognized financial instruments have been determined based on the company’s assessment of available market information and appropriate valuation methodologies; however, these estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction.
The following table summarizes estimated fair value information about the company’s financial instruments recognized in the Consolidated Balance Sheets at December 31:
|
| 2004 |
| 2003 |
| ||||
($ millions) |
| Carrying |
| Fair |
| Carrying |
| Fair |
|
Cash and cash equivalents |
| 88 |
| 88 |
| 388 |
| 388 |
|
Accounts receivable |
| 627 |
| 627 |
| 505 |
| 505 |
|
Current liabilities |
| 1 252 |
| 1 252 |
| 976 |
| 976 |
|
Long-term debt |
|
|
|
|
|
|
|
|
|
Fixed-term |
| 2 104 |
| 2 339 |
| 2 317 |
| 2 502 |
|
Revolving-term |
| 89 |
| 89 |
| — |
| — |
|
Other |
| 5 |
| 5 |
| 4 |
| 4 |
|
Capital leases |
| 19 |
| 19 |
| 127 |
| 127 |
|
The fair values of the company’s fixed and revolving-term long-term debt, capital leases, and other long-term debt were determined through comparisons to similar debt instruments.
(b) Unrecognized Derivative Financial Instruments
The company is also a party to certain derivative financial instruments that are not recognized in the Consolidated Balance Sheets, as follows:
Revenue and Margin Hedges
Suncor operates in a global industry where the market price of its petroleum and natural gas products is determined based on floating benchmark indices denominated in U.S. dollars. The company periodically enters into derivative financial instrument contracts such as forwards, futures, swaps and options to hedge against the potential adverse impact of changing market prices due to changes in the underlying indices. Specifically, the company manages crude sales price variability by entering into U.S. dollar West Texas Intermediate (WTI) derivative transactions. As at December 31, 2004, the company had hedged a portion of its forecasted Canadian dollar denominated cash flows subject to U.S. dollar WTI commodity price risk until
Suncor Energy Inc. 2004 Annual Report
74
December 31, 2005. The company had not hedged any portion of the foreign exchange component of these forecasted cash flows. As a result of the company’s decision to suspend its strategic crude oil hedging program, no strategic crude oil hedges were entered into in 2004.
At December 31, 2004, the company had also hedged a portion of its forecasted cash flows related to natural gas production and refinery operations.
The financial instrument contracts do not require the payment of premiums or cash margin deposits prior to settlement. On settlement, these contracts result in cash receipts or payments by the company for the difference between the contract and market rates for the applicable dollars and volumes hedged during the contract term. Such cash receipts or payments offset corresponding decreases or increases in the company’s sales revenues or crude oil purchase costs. For accounting purposes, amounts received or paid on settlement are recorded as part of the related hedged sales or purchase transactions.
Contracts outstanding at December 31 were as follows:
Strategic Crude Oil Hedges
($ millions except for average price) |
| Quantity |
| Average |
| Revenue |
| Hedge |
|
As at December 31, 2004 |
|
|
|
|
|
|
|
|
|
Crude oil swaps |
| 36 000 |
| 23 |
| 364 | (c) | 2005 |
|
As at December 31, 2003 |
|
|
|
|
|
|
|
|
|
Crude oil swaps |
| 68 000 |
| 24 |
| 772 | (c) | 2004 |
|
Costless collars |
| 11 000 |
| 21 – 24 |
| 109 – 125 | (c) | 2004 |
|
Crude oil swaps |
| 36 000 |
| 23 |
| 390 | (c) | 2005 |
|
As at December 31, 2002 |
|
|
|
|
|
|
|
|
|
Crude oil swaps |
| 10 000 |
| 30 |
| 57 | (c) | 2003 | (b) |
Crude oil swaps |
| 15 000 |
| 24 |
| 208 | (c) | 2003 |
|
Costless collars |
| 60 000 |
| 21 – 26 |
| 726 – 899 | (c) | 2003 |
|
Crude oil swaps |
| 25 000 |
| 23 |
| 332 | (c) | 2004 |
|
Costless collars |
| 11 000 |
| 21 – 24 |
| 133 – 152 | (c) | 2004 |
|
Crude oil swaps |
| 21 000 |
| 22 |
| 266 | (c) | 2005 |
|
Margin Hedges |
| Quantity |
| Average |
| Margin |
| Hedge |
|
Refined product sale and crude purchase swaps |
|
|
|
|
|
|
|
|
|
As at December 31, 2004 |
| 6 300 |
| 7 |
| 15 | (c) | 2005 | (d) |
As at December 31, 2003 |
| 6 600 |
| 5 |
| 3 | (c) | 2004 | (e) |
As at December 31, 2002 |
| 20 700 |
| 5 |
| 9 | (c) | 2003 | (f) |
Natural Gas Hedges |
| Quantity |
| Average |
| Revenue |
| Hedge |
|
Swaps and costless collars |
|
|
|
|
|
|
|
|
|
As at December 31, 2004 |
|
|
|
|
|
|
|
|
|
Natural gas swaps |
| 4 000 |
| 7 |
| 10 |
| 2005 |
|
Natural gas swaps |
| 4 000 |
| 7 |
| 10 |
| 2006 |
|
Natural gas swaps |
| 4 000 |
| 6 |
| 9 |
| 2007 |
|
Costless collars |
| 10 000 |
| 8 – 9 |
| 7 – 8 |
| 2005 | (g) |
As at December 31, 2003 (j) |
| 30 000 |
| 6 |
| 16 |
| 2004 | (h) |
As at December 31, 2002 (k) |
| 25 000 |
| 4 – 6 |
| 9 – 14 |
| 2003 | (i) |
(a) Average price for crude oil swaps is US$/barrel WTI at Cushing.
(b) For the period January to April 2003, inclusive. All other crude oil positions are for the full year.
(c) The revenue and margin hedged is translated to Cdn$ at the year-end exchange rate for convenience purposes.
(d) For the period January to September 2005.
(e) For the period January and February 2004.
(f) For the period January and February 2003.
(g) For the period January to March 2005.
(h) For the period January to March 2004.
(i) For the period January to March 2003.
(j) As of December 31, 2003, only swap hedges were outstanding.
(k) As of December 31, 2002, only costless collar hedges were outstanding.
Suncor Energy Inc. 2004 Annual Report
75
Interest Rate Hedges
The company periodically enters into interest rate swap contracts as part of its risk management strategy to manage its exposure to interest rates. The interest rate swap contracts involve an exchange of floating rate and fixed rate interest payments between the company and investment grade counterparties. The differentials on the exchange of periodic interest payments are recognized in the accounts as an adjustment to interest expense.
The notional amounts of interest rate swap contracts outstanding at December 31, 2004, are detailed in note 6, Long-term Debt.
Fair Value of Derivative Financial Instruments
The fair value of hedging derivative financial instruments is the estimated amount, based on broker quotes and/or internal valuation models, that the company would receive (pay) to terminate the contracts. Such amounts, which also represent the unrecognized and unrecorded gain (loss) on the contracts, were as follows at December 31:
($ millions) |
| 2004 |
| 2003 |
|
Revenue hedge swaps and collars |
| (305 | ) | (285 | ) |
Margin hedge swaps |
| 5 |
| 2 |
|
Interest rate and cross-currency interest rate swaps |
| 36 |
| 32 |
|
|
| (264 | ) | (251 | ) |
(c) Energy Marketing and Trading Activities
In addition to those financial derivatives used for hedging activities, the company also uses energy derivatives, including physical and financial swaps, forwards, futures and options to gain market information and earn trading revenues. These energy trading activities are accounted for using the mark-to-market method and, as such, physical and financial energy contracts are recorded at fair value at each balance sheet date. During 2004 Suncor recorded a net pretax gain of $11 million (2003 – pretax loss of $3 million; 2002 – $nil) related to the settlement and revaluation of financial energy trading contracts. In 2004 the settlement of physical trading activities also resulted in a net pretax gain of $12 million (2003 – $2 million; 2002 – $6 million). These gains were included as energy trading and marketing activities in the Consolidated Statement of Earnings. The above amounts do not include the impact of related general and administrative costs.
The fair value of unsettled financial energy trading assets and liabilities at December 31 were as follows:
($ millions) |
| 2004 |
| 2003 |
|
Energy trading assets |
| 26 |
| 5 |
|
Energy trading liabilities |
| 9 |
| 5 |
|
The source of the valuations of the above contracts was based on actively quoted prices and internal valuation models.
(d) Counterparty Credit Risk
The company may be exposed to certain losses in the event that counterparties to the derivative financial instruments are unable to meet the terms of the contracts. The company’s exposure is limited to those counterparties holding derivative contracts with positive fair values at the reporting date. The company minimizes this risk by entering into agreements with counterparties, of which substantially all are investment grade. Risk is also minimized through regular management review of credit ratings and potential exposure to such counterparties. At December 31, the company had exposure to credit risk with counterparties as follows:
($ millions) |
| 2004 |
| 2003 |
|
Derivative contracts not accounted for as hedges |
| 7 |
| 30 |
|
Unrecognized derivative contracts |
| 21 |
| 27 |
|
|
| 28 |
| 57 |
|
8. ACCRUED LIABILITIES AND OTHER
($ millions) |
| 2004 |
| 2003 |
|
Asset retirement obligations (a) |
| 429 |
| 363 |
|
Employee future benefits liability (see note 9) |
| 183 |
| 181 |
|
Employee and director incentive plans |
| 50 |
| 35 |
|
Deferred revenue |
| 64 |
| — |
|
Environmental remediation costs (b) |
| 8 |
| 34 |
|
Other |
| 15 |
| 3 |
|
Total |
| 749 |
| 616 |
|
Suncor Energy Inc. 2004 Annual Report
76
(a) Asset Retirement Obligations
The asset retirement obligation also includes $47 million in current liabilities (2003 – $38 million). The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the long-term obligations associated with the retirement of property, plant and equipment.
($ millions) |
| 2004 |
| 2003 |
|
Asset retirement obligations, beginning of year |
| 401 |
| 400 |
|
Liabilities incurred |
| 82 |
| — |
|
Liabilities settled |
| (33 | ) | (24 | ) |
Accretion of asset retirement obligations |
| 26 |
| 25 |
|
Asset retirement obligations, end of period |
| 476 |
| 401 |
|
The total undiscounted amount of estimated cash flows required to settle the obligations at December 31, 2004, was approximately $1.1 billion (2003 – $1.0 billion), and has been discounted using a credit-adjusted risk-free rate of 6% (2003 – 6.5%). Payments to settle the ARO occur on an ongoing basis and will continue over the lives of the operating assets, which can exceed 35 years.
A significant portion of the company’s assets have retirement obligations for which the fair value cannot be reasonably determined because the assets currently have an indeterminate life. The asset retirement obligation for these assets will be recorded in the first period in which the lives of the assets are determinable.
(b) Environmental Remediation Costs
Total accrued environmental remediation costs also include $35 million in current liabilities (2003 – $20 million).
9. EMPLOYEE FUTURE BENEFITS LIABILITY
Suncor employees are eligible to receive certain pension, health care and insurance benefits when they retire. The related Benefit Obligation or commitment that Suncor has to employees and retirees at December 31, 2004, was $752 million.
As required by government regulations and plan performance, Suncor sets aside funds with an independent trustee to meet certain of these obligations. At the end of December 2004, Plan Assets to meet the Benefit Obligation were $399 million.
The excess of the Benefit Obligation over Plan Assets of $353 million represents the Net Unfunded Obligation.
See below for more technical details and amounts.
Defined Benefit Pension Plans and Other Post-retirement Benefits
The company’s defined benefit pension plans provide non-indexed pension benefits at retirement based on years of service and final average earnings. These obligations are met through funded registered retirement plans and through unfunded, unregistered supplementary benefits that are paid directly to recipients. Company contributions to the funded plans are deposited with independent trustees who act as custodians of the funded pension plans’ assets, as well as the disbursing agents of the benefits to recipients. Plan assets are managed by a pension committee on behalf of beneficiaries. The committee retains independent managers and advisors.
Funding of the registered retirement plans complies with applicable regulations that require actuarial valuations of the pension funds at least once every three years in Canada, depending on funding status, and every year in the United States. The most recent valuation for the Canadian and U.S. plans was performed in 2004.
The company’s other post-retirement benefits programs, which are unfunded, include certain health care and life insurance benefits provided to retired employees and eligible surviving dependants.
The expense and obligations for both funded and unfunded benefits are determined in accordance with Canadian GAAP and actuarial principles. Obligations are based on the projected benefit method of valuation that includes employee service to date and present pay levels, as well as a projection of salaries and service to retirement.
Suncor Energy Inc. 2004 Annual Report
77
Obligations and Funded Status
The following table presents information about obligations recognized in the Consolidated Balance Sheets and the funded status of the plans at December 31:
|
| Pension Benefits |
| Other Post-retirement Benefits |
| ||||
($ millions) |
| 2004 |
| 2003 |
| 2004 |
| 2003 |
|
Change in benefit obligation |
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year |
| 568 |
| 489 |
| 117 |
| 97 |
|
Service costs |
| 25 |
| 18 |
| 5 |
| 3 |
|
Interest costs |
| 34 |
| 32 |
| 7 |
| 6 |
|
Plan participants’ contributions |
| 3 |
| 3 |
| — |
| — |
|
Acquisition (a) |
| — |
| 14 |
| — |
| 6 |
|
Foreign exchange |
| (2 | ) | (1 | ) | (1 | ) | — |
|
Actuarial loss |
| 21 |
| 37 |
| 4 |
| 8 |
|
Benefits paid |
| (25 | ) | (24 | ) | (4 | ) | (3 | ) |
Benefit obligation at end of year (b), (f) |
| 624 |
| 568 |
| 128 |
| 117 |
|
Change in plan assets (c) |
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year |
| 336 |
| 273 |
| — |
| — |
|
Actual return on plan assets |
| 33 |
| 45 |
| — |
| — |
|
Employer contributions |
| 49 |
| 36 |
| — |
| — |
|
Plan participants’ contributions |
| 3 |
| 3 |
| — |
| — |
|
Benefits paid |
| (22 | ) | (21 | ) | — |
| — |
|
Fair value of plan assets at end of year (f) |
| 399 |
| 336 |
| — |
| — |
|
Net unfunded obligation |
| (225 | ) | (232 | ) | (128 | ) | (117 | ) |
Items not yet recognized in earnings: |
|
|
|
|
|
|
|
|
|
Unamortized net actuarial loss (d) |
| 125 |
| 133 |
| 49 |
| 50 |
|
Unamortized past service costs (e) |
| — |
| — |
| (29 | ) | (31 | ) |
Accrued benefit liability |
| (100 | ) | (99 | ) | (108 | ) | (98 | ) |
Current liability |
| (40 | ) | (14 | ) | (3 | ) | (2 | ) |
Long-term liability |
| (78 | ) | (85 | ) | (105 | ) | (96 | ) |
Long-term asset |
| 18 |
| — |
| — |
| — |
|
Total accrued benefit liability |
| (100 | ) | (99 | ) | (108 | ) | (98 | ) |
(a) In 2003, in connection with the acquisition of the Denver refinery and related assets from ConocoPhillips, the company assumed a pension benefit obligation of $14 million and other post-retirement benefit obligations of $6 million. No pension plan assets were acquired.
(b) Obligations are based on the following assumptions:
|
| Pension Benefit Obligations |
| Other Post-retirement |
| ||||
(per cent) |
| 2004 |
| 2003 |
| 2004 |
| 2003 |
|
Discount rate |
| 5.75 |
| 6.00 |
| 5.75 |
| 6.00 |
|
Rate of compensation increase |
| 4.50 |
| 4.00 |
| 4.25 |
| 4.00 |
|
A one percent change in the assumptions at which pension benefits and other post-retirement benefits liabilities could be
effectively settled is as follows:
|
| Rate of Return |
| Discount Rate |
| Rate of |
| ||||||
($ millions) |
| 1% |
| 1% |
| 1% |
| 1% |
| 1% |
| 1% |
|
Increase (decrease) to net periodic benefit cost |
| (4 | ) | 4 |
| (11 | ) | 12 |
| 6 |
| (5 | ) |
Increase (decrease) to benefit obligation |
| — |
| — |
| (99 | ) | 115 |
| 30 |
| (27 | ) |
In order to measure the expected cost of other post-retirement benefits, an 11.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2004 (2003 – 12%; 2002 – 9%). It is assumed that this rate will decrease by 0.5% annually, to 5% for 2017, and remain at that level thereafter.
Suncor Energy Inc. 2004 Annual Report
78
Assumed health care cost trend rates have a significant effect on the amounts reported for other post-retirement benefit obligations. A one per cent change in assumed health care cost trend rates would have the following effects:
($ millions) |
| 1% increase |
| 1% decrease |
|
Increase (decrease) to total of service and interest cost components of net periodic |
| 2 |
| (1 | ) |
Increase (decrease) to the health care component of the accumulated Post-retirement benefit obligation |
| 13 |
| (11 | ) |
(c) Pension plan assets are not the company’s assets and therefore are not included in the Consolidated Balance Sheets.
(d) The unamortized net actuarial loss represents annually calculated differences between actual and projected plan performance. These amounts are amortized as part of the net periodic benefit cost over the expected average remaining service life of employees of 12 years for pension benefits (2003 – 12 years; 2002 – 13 years), and over the expected average future service life to full eligibility age of 12 years for other post-retirement benefits (2003 and 2002 – 12 years).
(e) Effective April 1, 2003, the company implemented amendments to its post-retirement benefits program to manage its exposures to future health care and life insurance costs. Certain of the company’s employees will continue to receive post-retirement benefits under the old plan provisions. These plan amendments reduced the company’s other post-retirement benefits obligation at December 31, 2002, by $34 million.
(f) The company uses a measurement date of December 31 to value the plan assets and accrued benefit obligation.
The above benefit obligation at year-end includes funded and unfunded plans, as follows:
|
| Pension Benefits |
| Other Post-retirement Benefits |
| ||||
($ millions) |
| 2004 |
| 2003 |
| 2004 |
| 2003 |
|
Funded plans |
| 537 |
| 498 |
| — |
| — |
|
Unfunded plans |
| 87 |
| 70 |
| 128 |
| 117 |
|
Benefit obligation at end of year |
| 624 |
| 568 |
| 128 |
| 117 |
|
Components of Net Periodic Benefit Cost (a)
|
| Pension Benefits |
| Other Post-retirement Benefits |
| ||||||||
($ millions) |
| 2004 |
| 2003 |
| 2002 |
| 2004 |
| 2003 |
| 2002 |
|
Current service costs |
| 25 |
| 18 |
| 17 |
| 5 |
| 3 |
| 4 |
|
Interest costs |
| 34 |
| 32 |
| 30 |
| 7 |
| 6 |
| 6 |
|
Expected return on plan assets (b) |
| (25 | ) | (20 | ) | (22 | ) | — |
| — |
| — |
|
Amortization of net actuarial loss |
| 19 |
| 22 |
| 15 |
| 1 |
| 1 |
| 2 |
|
Net periodic benefit cost recognized (c) |
| 53 |
| 52 |
| 40 |
| 13 |
| 10 |
| 12 |
|
Components of Net Incurred Benefit Cost (a)
|
| Pension Benefits |
| Other Post-retirement Benefits |
| ||||||||
($ millions) |
| 2004 |
| 2003 |
| 2002 |
| 2004 |
| 2003 |
| 2002 |
|
Current service costs |
| 25 |
| 18 |
| 17 |
| 5 |
| 3 |
| 4 |
|
Interest costs |
| 34 |
| 32 |
| 30 |
| 7 |
| 6 |
| 6 |
|
Actual (return) loss on plan assets |
| (33 | ) | (45 | ) | 24 |
| — |
| — |
| — |
|
Amendments |
| — |
| — |
| — |
| — |
| — |
| (34 | ) |
Actuarial (gain) loss |
| 21 |
| 37 |
| (1 | ) | 4 |
| 8 |
| 30 |
|
Net incurred benefit cost |
| 47 |
| 42 |
| 70 |
| 16 |
| 17 |
| 6 |
|
(a) The net periodic benefit cost includes certain accounting adjustments made to allocate costs to the periods in which employee services are rendered, consistent with the long-term nature of the benefits. Costs actually incurred in the period (arising from actual returns on plan assets and actuarial gains and losses in the period) differ from allocated costs recognized.
(b) The expected return on plan assets is the expected long-term rate of return on plan assets for the year. It is based on plan assets at the beginning of the year that have been adjusted on a weighted-average basis for contributions and benefit payments expected for the year. The expected return on plan assets is included in the net periodic benefit cost for the year to which it relates, while the difference between it and the actual return realized on plan assets in the same year is amortized over the expected average remaining service life of employees of 12 years for pension benefits.
To estimate the expected long-term rate of return on plan assets, the company considered the current level of expected returns on the fixed income portion of the portfolio, the historical level of the risk premium associated with other asset classes in which the portfolio is invested and the expectation for future returns on each asset class. The expected return for each asset class was weighted based on the policy asset mix to develop an expected long-term rate of return on asset assumption for the portfolio.
(c) Pension expense is based on the following assumptions:
|
| Pension Benefit Expense |
| Other Post-retirement Benefits Expense |
| ||||||||
(per cent) |
| 2004 |
| 2003 |
| 2002 |
| 2004 |
| 2003 |
| 2002 |
|
Discount rate |
| 6.00 |
| 6.50 |
| 6.50 |
| 6.00 |
| 6.50 |
| 6.50 |
|
Expected return on plan assets |
| 7.00 |
| 7.25 |
| 7.25 |
| — |
| — |
| — |
|
Rate of compensation increase |
| 4.00 |
| 4.00 |
| 4.25 |
| 4.00 |
| 4.00 |
| 4.25 |
|
Suncor Energy Inc. 2004 Annual Report
79
Plan Assets and Investment Objectives
The company’s long-term investment objective is to secure the defined pension benefits while managing the variability and level of its contributions. The portfolio is rebalanced periodically as required, while ensuring that the maximum equity content is 65% at any time. Plan assets are managed by external managers, who report to a Pension Committee, and are restricted to those permitted by applicable legislation. Investments are made through pooled, mutual or segregated funds.
The company’s pension plan asset allocation based on market values as at December 31, 2004 and 2003, and the target allocation for 2005 is as follows:
|
| Target Allocation % |
| Percentage of Plan Assets |
| ||
|
| 2005 |
| 2004 |
| 2003 |
|
Asset Category |
|
|
|
|
|
|
|
Equities |
| 60 |
| 60 |
| 61 |
|
Fixed income |
| 40 |
| 40 |
| 39 |
|
Total |
| 100 |
| 100 |
| 100 |
|
Equity securities do not include any direct investments in Suncor shares.
Cash Flows
The company expects that contributions to its pension plans in 2005 will be $65 million, including approximately $15 million for the company’s senior executive and supplemental retirement plans. Expected benefit payments from the plans are as follows:
|
| Pension |
| Other Post- |
|
2005 |
| 27 |
| 4 |
|
2006 |
| 29 |
| 5 |
|
2007 |
| 31 |
| 5 |
|
2008 |
| 33 |
| 6 |
|
2009 |
| 34 |
| 7 |
|
2010 – 2014 |
| 211 |
| 49 |
|
Total |
| 365 |
| 76 |
|
Defined Contribution Pension Plan
The company has a Canadian defined contribution plan and a U.S. 401(k) savings plan, under which both the company and employees make contributions. Company contributions and corresponding expense totalled $8 million in 2004 (2003 – $6 million; 2002 – $5 million).
10. INCOME TAXES
The assets and liabilities shown on Suncor’s balance sheets are calculated in accordance with Canadian GAAP. Suncor’s income taxes are calculated according to government tax laws and regulations, which results in different values for certain assets and liabilities for income tax purposes. These differences are known as temporary differences, because eventually these differences will reverse.
The amount shown on the balance sheets as future income taxes represent income taxes that will eventually be payable or recoverable in future years when these temporary differences reverse.
See next page for more technical details and amounts.
80
The provision for income taxes reflects an effective tax rate that differs from the statutory tax rate. A reconciliation of the two rates and the dollar effect is as follows:
|
| 2004 |
| 2003 |
| 2002 |
| ||||||
($ millions) |
| Amount |
| % |
| Amount |
| % |
| Amount |
| % |
|
Federal tax rate |
| 589 |
| 36 |
| 666 |
| 37 |
| 428 |
| 38 |
|
Provincial abatement |
| (164 | ) | (10 | ) | (180 | ) | (10 | ) | (113 | ) | (10 | ) |
Federal surtax |
| 18 |
| 1 |
| 20 |
| 1 |
| 13 |
| 1 |
|
Provincial tax rates |
| 192 |
| 12 |
| 225 |
| 13 |
| 148 |
| 13 |
|
Statutory tax and rate |
| 635 |
| 39 |
| 731 |
| 41 |
| 476 |
| 42 |
|
Adjustment of statutory rate for future rate reductions |
| (86 | ) | (5 | ) | (92 | ) | (6 | ) | — |
| — |
|
|
| 549 |
| 34 |
| 639 |
| 35 |
| 476 |
| 42 |
|
Add (deduct) the tax effect of: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Crown royalties |
| 133 |
| 8 |
| 50 |
| 3 |
| 39 |
| 3 |
|
Resource allowance |
| (69 | ) | (4 | ) | (31 | ) | (2 | ) | (34 | ) | (3 | ) |
Temporary difference in resource allowance |
| — |
| — |
| — |
| — |
| (117 | ) | (10 | ) |
Large corporations tax |
| 18 |
| 1 |
| 19 |
| 1 |
| 17 |
| 1 |
|
Tax rate changes on opening future income taxes |
| (53 | ) | (3 | ) | 89 |
| 5 |
| (10 | ) | (1 | ) |
Attributed Canadian royalty income |
| (29 | ) | (2 | ) | (8 | ) | — |
| (2 | ) | — |
|
Stock-based compensation |
| 8 |
| — |
| 3 |
| — |
| — |
| — |
|
Assessments and adjustments |
| — |
| — |
| — |
| — |
| 10 |
| 1 |
|
Capital gains |
| (18 | ) | (1 | ) | (34 | ) | (2 | ) | — |
| — |
|
Other |
| (3 | ) | — |
| (1 | ) | — |
| (1 | ) | — |
|
Income taxes and effective rate |
| 536 |
| 33 |
| 726 |
| 40 |
| 378 |
| 33 |
|
In 2004 net income tax payments totalled $50 million (2003 – $45 million payment; 2002 – $8 million refund).
The resource allowance is a federal tax deduction allowed as a proxy for non-deductible provincial Crown royalties. As required by Canadian GAAP, resource allowance is accounted for by adjusting the statutory tax rate by the resource allowance rate.
Effective January 1, 2003, the Canadian government enacted changes to the federal taxation policies relating to the resource sector. The changes are to be fully phased in by 2007 and include a 7% reduction of the federal rate, deductibility of provincial Crown royalties and the elimination of the federal resource allowance deduction. In 2004 and 2003, the company’s future income tax liabilities related to its resource operations were based on the future tax rates with the full 7% federal tax rate reduction.
Effective April 1, 2004, the Alberta provincial corporate tax rate decreased by 1% (2003 – decrease of 1%). In 2003 the Ontario government substantively enacted a general corporate tax rate and manufacturing and processing tax rate increase of 1.5% and 1% respectively, effective January 1, 2004.
Accordingly, in 2004, the company revalued its future income tax liabilities and recognized a decrease in future income tax expense of $53 million (2003 – increase of $89 million).
At December 31, future income taxes were comprised of the following:
|
| 2004 |
| 2003 |
| ||||
($ millions) |
| Current |
| Non-current |
| Current |
| Non-current |
|
Future income tax assets: |
|
|
|
|
|
|
|
|
|
Employee future benefits |
| 14 |
| — |
| 4 |
| — |
|
Asset retirement obligations |
| 16 |
| — |
| 9 |
| — |
|
Inventories |
| 27 |
| — |
| 2 |
| — |
|
|
| 57 |
| — |
| 15 |
| — |
|
Future income tax liabilities: |
|
|
|
|
|
|
|
|
|
Depreciation |
| — |
| 2 734 |
| — |
| 2 095 |
|
Overburden removal costs |
| — |
| 20 |
| — |
| 16 |
|
Deferred maintenance shutdown costs |
| — |
| 44 |
| — |
| 41 |
|
Inventories |
| — |
| — |
| (12 | ) | — |
|
Employee future benefits |
| — |
| (77 | ) | — |
| (70 | ) |
Asset retirement obligations |
| — |
| (139 | ) | — |
| (7 | ) |
Attributed Canadian royalty income |
| — |
| (69 | ) | — |
| (47 | ) |
Other |
| — |
| 19 |
| 13 |
| (6 | ) |
|
| — |
| 2 532 |
| 1 |
| 2 022 |
|
Suncor Energy Inc. 2004 Annual Report
81
11. COMMITMENTS, CONTINGENCIES, GUARANTEES AND SUBSEQUENT EVENT
(a) Operating Commitments
In order to ensure continued availability of, and access to, facilities and services to meet its operational requirements, the company periodically enters into transportation service agreements for pipeline capacity and energy services agreements as well as non-cancellable operating leases for service stations, office space and other property and equipment. Under contracts existing at December 31, 2004, future minimum amounts payable under these leases and agreements are as follows:
($ millions) |
| Pipeline |
| Operating |
|
2005 |
| 178 |
| 44 |
|
2006 |
| 190 |
| 31 |
|
2007 |
| 190 |
| 27 |
|
2008 |
| 210 |
| 22 |
|
2009 |
| 211 |
| 15 |
|
Later years |
| 3 626 |
| 54 |
|
|
| 4 605 |
| 193 |
|
(1) Includes annual tolls payable under a transportation service agreement with a major pipeline company to use a portion of its pipeline capacity and tankage for the shipment of crude oil from Fort McMurray to Hardisty, Alberta. The agreement commenced in 1999 and extends to 2028. As the initial shipper on the pipeline, Suncor’s tolls payable under the agreement are subject to annual adjustments.
To meet the energy needs of its oil sands operation, Suncor has a commitment under long-term energy agreements to obtain a portion of the power and all of the steam generated by a cogeneration facility owned by a major third-party energy company. Since October 1999, this third-party has managed the operations of Suncor’s existing energy services facility.
(b) Contingencies
The company is subject to various regulatory and statutory requirements relating to the protection of the environment. These requirements, in addition to contractual agreements and management decisions, result in the recognition of estimated asset retirement obligations. Effective January 1, 2004, the company adopted new Canadian accounting standards that required recognition of a liability for the future retirement obligations associated with the company’s property, plant and equipment (see Summary of Significant Accounting Policies and Note 1). Estimates of retirement obligation costs can change significantly based on such factors as operating experience, changes in legislation and regulations and cost.
The company carries property loss and business interruption insurance policies with a combined coverage limit of up to US$1,150 million, net of deductible amounts. The primary property loss policy of US$250 million has a deductible of US$10 million per incident and the primary business interruption policy of US$200 million has a deductible per incident of the greater of US$50 million gross earnings lost (as defined in the insurance policy) or 30 days from the incident. In addition to these primary coverage insurance policies, Suncor has excess coverage of US$700 million that can be used for either property loss or business interruption coverage. For business interruption purposes this excess coverage begins the later of full utilization of the primary business interruption coverage or 90 days from the date of the incident.
The company is defendant and plaintiff in a number of legal actions that arise in the normal course of business. The company believes that any liabilities that might arise pertaining to such matters would not have a material effect on its consolidated financial position.
Costs attributable to these commitments and contingencies are expected to be incurred over an extended period of time and to be funded from the company’s cash provided from operating activities. Although the ultimate impact of these matters on net earnings cannot be determined at this time, the impact may be material.
(c) Variable Interest Entities and Guarantees
At December 31, 2004, the company had off-balance sheet arrangements with Variable Interest Entities, and indemnification agreements with other third parties, as described below.
The company has a securitization program in place to sell, on a revolving, fully serviced and limited recourse basis, up to $170 million of accounts receivable having a maturity of 45 days or less, to a third-party. The third-party is a multiple party securitization vehicle that provides funding for numerous asset pools. As at December 31, 2004, $170 million in outstanding accounts receivable had been sold under the program. Under the recourse provisions, the company will provide indemnification against credit losses for certain counterparties, which did not exceed $50 million in 2004. A liability has not been recorded for this
Suncor Energy Inc. 2004 Annual Report
82
indemnification as the company believes it has no significant exposure to credit losses. There were no new securitization proceeds in 2004. Proceeds from collections reinvested in securitizations on a revolving basis for the year ended December 31, 2004 were approximately $2,073 million. The company recorded an after-tax loss of approximately $2 million on the securitization program in 2004 (2003 and 2002 – $3 million).
In 1999, the company entered into an equipment sale and leaseback arrangement with a third-party for proceeds of $30 million. The third-party’s sole asset is the equipment sold to it and leased back by the company. The initial lease term covers a period of seven years and as at December 31, 2004, was accounted for as an operating lease. The company has provided a residual value guarantee on the equipment of up to $7 million should it elect not to repurchase the equipment at the end of the lease term. An early termination purchase option allows for the repurchase of the equipment at a specified date in 2005. Had the company elected to terminate the lease at December 31, 2004, the total cost would have been $25 million. Annualized equipment lease payments in 2004 were $6 million (2003 – $4 million; 2002 – $2 million).
The company has agreed to indemnify holders of the 7.15% notes, the 5.95% notes and the company’s credit facility lenders (see note 6) for added costs relating to taxes, assessments or other government charges or conditions, including any required withholding amounts. Similar indemnity terms apply to the receivables securitization program, and certain facility and equipment leases.
There is no limit to the maximum amount payable under the indemnification agreements described above. The company is unable to determine the maximum potential amount payable as government regulations and legislation are subject to change without notice. Under these agreements, Suncor has the option to redeem or terminate these contracts if additional costs are incurred.
(d) Subsequent Event
On January 4, 2005, a fire occurred at the company’s Oil Sands operations. The fire was confined to one of the upgraders, primarily affecting a coker fractionator. Daily production capacity at the Oil Sands facility has been reduced during the investigation and repair of fire-related damage.
12. PREFERRED SECURITIES
On March 15, 2004, the company redeemed all of its then outstanding 9.05% and 9.125% preferred securities for total cash consideration of $493 million. In 2004, dividends of $9 million were paid on the preferred securities (2003 – $45 million; 2002 – $48 million).
13. SHARE CAPITAL
(a) Authorized:
Common Shares
The company is authorized to issue an unlimited number of common shares without nominal or par value.
Preferred Shares
The company is authorized to issue an unlimited number of preferred shares in series, without nominal or par value.
(b) Issued:
|
| Common Shares |
| ||
|
| Number |
| Amount |
|
|
| (thousands) |
| ($ millions) |
|
Balance as at December 31, 2002 |
| 448 972 |
| 578 |
|
Issued for cash under stock option plans |
| 1 977 |
| 20 |
|
Issued under dividend reinvestment plan |
| 235 |
| 6 |
|
Balance as at December 31, 2003 |
| 451 184 |
| 604 |
|
Issued for cash under stock option plans |
| 2 880 |
| 41 |
|
Issued under dividend reinvestment plan |
| 177 |
| 6 |
|
Balance as at December 31, 2004 |
| 454 241 |
| 651 |
|
Suncor Energy Inc. 2004 Annual Report
83
Common Share Options
A common share option gives the holder the right, but not the obligation, to purchase common shares at a predetermined price over a specified period of time.
After the date of grant, employees and directors that hold options must earn the right to exercise them. This is done by the employee or director fulfilling a time requirement for service to the company, and with respect to certain options, subject to accelerated vesting should the company meet predetermined performance criteria. Once this right has been earned, these options are considered vested.
The predetermined price at which an option can be exercised is equal to or greater than the market price of the common shares on the date the options are granted.
See below for more technical details and amounts on the company’s stock option plans:
(i) EXECUTIVE STOCK PLAN Under this plan, the company granted 1,346,000 common share options in 2004 (2003 – 1,902,000; 2002 – 1,803,000) to non-employee directors and certain executives and other senior employees of the company. The exercise price of an option is equal to the market value of the common shares at the date of grant. Options granted have a 10-year life and vest annually over a three-year period.
(ii) SUNSHARE PERFORMANCE STOCK OPTION PLAN During 2004, the company granted 1,742,000 options (2003 –1,305,000; 2002 – 8,938,000) to eligible permanent full-time and part-time employees, both executive and non-executive, under its employee stock option incentive plan (“SunShare”). Under SunShare, meeting specified performance targets accelerates the vesting of some or all options.
In October 2004, the company met the predetermined performance criteria for the accelerated vesting of 2,097,000 common share options granted to executive and non-executive employees. The vested options represented approximately 20% of the then outstanding common share options granted under the SunShare plan. An additional 2,062,000 options, representing approximately 25% of outstanding SunShare options at December 31, 2004, will vest on January 31, 2005 in connection with the achievement of the second predetermined performance criterion. The remaining 60% of outstanding SunShare options may vest on April 30, 2008. All unvested options, which have not previously expired or been cancelled, will automatically vest on January 1, 2012.
In 2004, the Board of Directors approved an additional 3,000,000 options available for grant under the SunShare plan.
(iii) KEY CONTRIBUTOR STOCK OPTION PLAN In 2004, the Board of Directors approved the establishment of the new Key Contributor stock option plan, under which 5,200,000 options were made available for grant to senior managers and key employees.
(iv) DEFERRED SHARE UNITS (DSUs) The company had 1,228,000 DSUs outstanding at December 31, 2004. DSUs were granted to certain executives under the company’s former employee long-term incentive program. Certain members of the Board of Directors have also elected to receive DSUs in lieu of cash compensation. DSUs are only redeemable at the time a unitholder ceases employment or Board membership, as applicable.
In 2004, there were no redemptions of DSUs for cash (2003 – 185,000 redeemed for cash consideration of $5 million; 2002 – 220,000 redeemed for cash consideration of $6 million). Over time, DSU unitholders are entitled to receive additional DSUs equivalent in value to future notional dividend reinvestments. Final DSU redemption amounts are subject to change depending on the company’s share price at the time of exercise. Accordingly, the company revalues the DSUs on each reporting date, with any changes in value recorded as an adjustment to compensation expense in the period. As at December 31, 2004, the total liability related to the DSUs was $52 million, of which $2 million was classified as current (see note 8).
During 2004, total pretax compensation expense related to deferred share units was $12 million (2003 – $8 million; 2002 – income of $2 million).
(v) PERFORMANCE SHARE UNITS (PSUs) During 2004, the company issued 354,000 PSUs (2003 and 2002 – nil) under its new employee incentive compensation plan. PSUs granted replace the remuneration value of reduced grants under the company’s stock option plans. PSUs vest and are settled in cash approximately three years after the grant date to varying degrees (0%, 50%, 100% and 150%) contingent upon Suncor’s performance. Performance is measured by reference to the company’s total shareholder return (stock price appreciation and dividend income) relative to a peer group of companies. Expense related to the PSUs is accrued based on the price of common shares at the end of the period and the probability of vesting. This expense is recognized on a straight-line basis over the term of the grant. Pretax expense recognized for PSUs during 2004 was $5 million (2003 and 2002 – $nil).
Suncor Energy Inc. 2004 Annual Report
84
The following tables cover all common share options granted by the company for the years indicated:
|
| Number |
| Range of |
| Weighted- |
|
Outstanding, December 31, 2001 |
| 11 768 |
| 2.38 – 21.35 |
| 12.12 |
|
Granted |
| 10 741 |
| 23.93 – 28.14 |
| 27.08 |
|
Exercised |
| (1 777 | ) | 2.38 – 17.45 |
| 10.42 |
|
Cancelled |
| (406 | ) | 13.04 – 27.65 |
| 26.48 |
|
Outstanding, December 31, 2002 |
| 20 326 |
| 3.80 – 28.14 |
| 19.89 |
|
Granted |
| 3 207 |
| 23.65 – 29.85 |
| 26.70 |
|
Exercised |
| (1 977 | ) | 3.80 – 23.93 |
| 10.35 |
|
Cancelled |
| (540 | ) | 10.13 – 27.93 |
| 20.94 |
|
Outstanding, December 31, 2003 |
| 21 016 |
| 4.11 – 29.85 |
| 21.69 |
|
Granted |
| 3 088 |
| 30.63 – 42.02 |
| 34.52 |
|
Exercised |
| (2 880 | ) | 4.11 – 40.67 |
| 13.94 |
|
Cancelled |
| (537 | ) | 23.93 – 41.38 |
| 28.71 |
|
Outstanding, December 31, 2004 |
| 20 687 |
| 5.22 – 42.02 |
| 24.49 |
|
|
|
|
|
|
|
|
|
Exercisable, December 31, 2004 |
| 9 067 |
| 5.22 – 40.67 |
| 18.78 |
|
Common shares authorized for issuance by the Board of Directors that remain available for the granting of future options, at December 31:
(thousands of common shares) |
| 2004 |
| 2003 |
| 2002 |
|
|
| 4 342 |
| 6 893 |
| 11 175 |
|
The following table is an analysis of outstanding and exercisable common share options as at December 31, 2004:
|
| Outstanding |
| Exercisable |
| ||||||
Exercise Prices ($) |
| Number |
| Weighted- |
| Weighted- |
| Number |
| Weighted- |
|
5.22 – 10.13 |
| 1 459 |
| 3 |
| 8.82 |
| 1 459 |
| 8.82 |
|
12.28 – 21.35 |
| 4 040 |
| 4 |
| 15.22 |
| 4 040 |
| 15.22 |
|
23.65 – 28.93 |
| 12 265 |
| 7 |
| 27.01 |
| 3 282 |
| 26.27 |
|
30.63 – 42.02 |
| 2 923 |
| 8 |
| 34.58 |
| 286 |
| 33.82 |
|
Total |
| 20 687 |
| 6 |
| 24.49 |
| 9 067 |
| 18.78 |
|
(vi) FAIR VALUE OF OPTIONS GRANTED The fair values of all common share options granted are estimated as at the grant date using the Black-Scholes option-pricing model. The weighted-average fair values of the options granted during the year and the weighted-average assumptions used in their determination are as noted below:
|
| 2004 |
| 2003 |
| 2002 |
| |||
Annual dividend per share |
| $ | 0.23 |
| $ | 0.1925 |
| $ | 0.17 |
|
Risk-free interest rate |
| 3.79 | % | 4.39 | % | 5.39 | % | |||
Expected life |
| 6 years |
| 7 years |
| 8 years |
| |||
Expected volatility |
| 29 | % | 32 | % | 31 | % | |||
Weighted-average fair value per option |
| $ | 12.02 |
| $ | 9.94 |
| $ | 12.08 |
|
Suncor Energy Inc. 2004 Annual Report
85
The company’s reported net earnings attributable to common shareholders and earnings per share prepared in accordance with the fair value method of accounting for stock-based compensation would have been reduced for all common share options granted prior to 2003 to the pro forma amounts stated below:
($ millions, except per share amounts) |
| 2004 |
| 2003 |
| 2002 |
|
Net earnings attributable to common shareholders – as reported |
| 1 088 |
| 1 085 |
| 722 |
|
Less: compensation cost under the fair value method for pre-2003 options |
| 47 |
| 30 |
| 32 |
|
Pro forma net earnings attributable to common shareholders for pre-2003 options |
| 1 041 |
| 1 055 |
| 690 |
|
Basic earnings per share |
|
|
|
|
|
|
|
As reported |
| 2.40 |
| 2.41 |
| 1.61 |
|
Pro forma |
| 2.30 |
| 2.35 |
| 1.54 |
|
Diluted earnings per share |
|
|
|
|
|
|
|
As reported |
| 2.36 |
| 2.24 |
| 1.58 |
|
Pro forma |
| 2.26 |
| 2.18 |
| 1.51 |
|
14. EARNINGS PER COMMON SHARE
The following is a reconciliation of basic and diluted earnings per common share:
($ millions) |
| 2004 |
| 2003 |
| 2002 |
|
Net earnings attributable to common shareholders |
| 1 088 |
| 1 085 |
| 722 |
|
Dividends on preferred securities, net of tax |
| — | (a) | 27 |
| 28 |
|
Revaluation of US$ preferred securities, net of tax |
| — | (a) | (37 | ) | (1 | ) |
Adjusted net earnings attributable to common shareholders |
| 1 088 |
| 1 075 |
| 749 |
|
|
|
|
|
|
|
|
|
(millions of common shares) |
|
|
|
|
|
|
|
Weighted-average number of common shares |
| 453 |
| 450 |
| 448 |
|
Dilutive securities: |
|
|
|
|
|
|
|
Options issued under stock-based compensation plans |
| 9 |
| 8 |
| 5 |
|
Redemption of preferred securities by the issuance of common shares |
| — | (a) | 22 |
| 20 |
|
Weighted-average number of diluted common shares |
| 462 |
| 480 |
| 473 |
|
|
|
|
|
|
|
|
|
(dollars per common share) |
|
|
|
|
|
|
|
Basic earnings per share (b) |
| 2.40 |
| 2.41 |
| 1.61 |
|
Diluted earnings per share |
| 2.36 |
| 2.24 | (c) | 1.58 | (c) |
Common share and earnings per common share amounts in the above table reflect a two-for-one share split effective May 15, 2002.
Note: An option will have a dilutive effect under the treasury stock method only when the average market price of the common stock during the period exceeds the exercise price of the option.
(a) For the year ended December 31, 2004, diluted earnings per share is the net earnings attributable to common shareholders divided by the weighted-average number of diluted common shares. Dividends on preferred securities, the revaluation of US$ preferred securities and the redemption of preferred securities by the issuance of common shares have an anti-dilutive impact, therefore they are not included in the calculation of diluted earnings per share. The company redeemed its preferred securities in the first quarter of 2004.
(b) Basic earnings per share is the net earnings attributable to common shareholders divided by the weighted-average number of common shares.
(c) Diluted earnings per share is the adjusted net earnings attributable to common shareholders, divided by the weighted-average number of diluted common shares.
Suncor Energy Inc. 2004 Annual Report
86
15. FINANCING EXPENSES (INCOME)
($ millions) |
| 2004 |
| 2003 |
| 2002 |
|
Interest on debt |
| 148 |
| 140 |
| 155 |
|
Capitalized interest |
| (61 | ) | (57 | ) | (22 | ) |
Net interest expense |
| 87 |
| 83 |
| 133 |
|
Foreign exchange (gain) on long-term debt |
| (89 | ) | (166 | ) | (9 | ) |
Other foreign exchange loss |
| 11 |
| 17 |
| — |
|
Total financing expenses (income) |
| 9 |
| (66 | ) | 124 |
|
Cash interest payments in 2004 totalled $143 million (2003 – $139 million; 2002 – $134 million).
16. INVENTORIES
($ millions) |
| 2004 |
| 2003 |
|
Crude oil |
| 109 |
| 135 |
|
Refined products |
| 120 |
| 134 |
|
Materials, supplies and merchandise |
| 194 |
| 102 |
|
Total |
| 423 |
| 371 |
|
As at December 31, 2004, the replacement cost of crude oil and refined product inventories, valued using the LIFO cost method, exceeded their carrying value by $65 million (2003 – $48 million).
During 2004, the company recorded a pretax gain of $8 million related to a permanent reduction in LIFO inventory layers.
17. RELATED PARTY TRANSACTIONS
The following table summarizes the company’s related party transactions after eliminations for the year. These transactions are in the normal course of operations and have been carried out on the same terms as would apply with unrelated parties.
($ millions) |
| 2004 |
| 2003 |
| 2002 |
|
Operating revenues |
|
|
|
|
|
|
|
Sales to Energy Marketing and Refining – Canada segment joint-ventures: |
|
|
|
|
|
|
|
Refined products |
| 320 |
| 301 |
| 321 |
|
Petrochemicals |
| 272 |
| 187 |
| 142 |
|
The company has supply agreements with two Energy Marketing and Refining – Canada segment joint-ventures for the sale of refined products. The company also has a supply agreement with an Energy Marketing and Refining – Canada segment joint-venture for the sale of petrochemicals.
At December 31, 2004, amounts due from Energy Marketing and Refining – Canada segment joint-ventures were $17 million (2003 – $36 million).
Sales to and balances with Energy Marketing and Refining – Canada segment joint-ventures are established and agreed to by the various parties and approximate fair value.
Suncor Energy Inc. 2004 Annual Report
87
18. SUPPLEMENTAL INFORMATION
($ millions) |
| 2004 |
| 2003 |
| 2002 |
|
Export sales (a) |
| 693 |
| 549 |
| 501 |
|
Exploration expenses |
|
|
|
|
|
|
|
Geological and geophysical |
| 33 |
| 18 |
| 13 |
|
Other |
| 1 |
| 1 |
| 2 |
|
Cash costs |
| 34 |
| 19 |
| 15 |
|
Dry hole costs |
| 21 |
| 32 |
| 11 |
|
Cash and dry hole costs (b) |
| 55 |
| 51 |
| 26 |
|
Leasehold impairment (c) |
| 8 |
| 16 |
| 10 |
|
|
| 63 |
| 67 |
| 36 |
|
Taxes other than income taxes |
|
|
|
|
|
|
|
Excise taxes (d) |
| 452 |
| 388 |
| 340 |
|
Production, property and other taxes |
| 44 |
| 38 |
| 34 |
|
|
| 496 |
| 426 |
| 374 |
|
Allowance for doubtful accounts |
| 3 |
| 4 |
|
|
|
(a) Sales of crude oil, natural gas and refined products to customers in the United States and sales of petrochemicals to customers in the United States and Europe.
(b) Included in exploration expenses in the Consolidated Statements of Earnings.
(c) Included in depreciation, depletion and amortization in the Consolidated Statements of Earnings.
(d) Included in operating revenues in the Consolidated Statements of Earnings.
In 2002, the company sold its retail natural gas marketing business in the Energy Marketing and Refining – Canada segment for cash consideration of $62 million, net of related closing costs and adjustments of $4 million, resulting in an after-tax gain of $35 million.
19. DIFFERENCES BETWEEN CANADIAN AND U.S. GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
The consolidated financial statements have been prepared in accordance with Canadian GAAP. The application of United States GAAP (U.S. GAAP) would have the following effects on earnings and comprehensive income as reported:
($ millions) |
| Notes |
| 2004 |
| 2003 |
| 2002 |
|
Net earnings as reported, Canadian GAAP |
|
|
| 1 100 |
| 1 075 |
| 749 |
|
Adjustments net of applicable income taxes |
|
|
|
|
|
|
|
|
|
Derivatives and hedging activities |
| (a) |
| 65 |
| (120 | ) | 6 |
|
Stock-based compensation |
| (b) |
| (10 | ) | (2 | ) | (12 | ) |
Preferred securities |
| (c) |
| (12 | ) | 12 |
| (29 | ) |
Asset retirement obligations |
| (d) |
| — |
| 5 |
| 12 |
|
Cumulative effect of change in accounting principles |
| (d) |
| — |
| (66 | ) | — |
|
Net earnings attributable to discontinued operations |
| (f) |
| — |
| — |
| (56 | ) |
Net earnings from continuing operations, U.S. GAAP |
|
|
| 1 143 |
| 904 |
| 670 |
|
Net earnings from discontinued operations, U.S. GAAP |
| (f) |
| — |
| — |
| 56 |
|
Derivatives and hedging activities, net of income taxes of $35 (2003 – $7; 2002 – $54) |
| (a) |
| (67 | ) | 18 |
| (118 | ) |
Minimum pension liability, net of income taxes of $3 (2003 – $nil; 2002 – $10) |
| (e) |
| 5 |
| 7 |
| (20 | ) |
Foreign currency translation adjustment |
| (g) |
| (29 | ) | (26 | ) | — |
|
Comprehensive income, U.S. GAAP |
|
|
| 1 052 |
| 903 |
| 588 |
|
per common share (dollars) |
|
|
| 2004 |
| 2003 |
| 2002 |
|
Net earnings per share from continuing operations |
|
|
|
|
|
|
|
|
|
Basic |
|
|
| 2.52 |
| 2.01 |
| 1.50 |
|
Diluted |
|
|
| 2.47 |
| 1.86 |
| 1.47 |
|
Net earnings per share from discontinued operations |
|
|
|
|
|
|
|
|
|
Basic |
|
|
| — |
| — |
| 0.12 |
|
Diluted |
|
|
| — |
| — |
| 0.12 |
|
Suncor Energy Inc. 2004 Annual Report
88
The application of U.S. GAAP would have the following effects on the Consolidated Balance Sheets as reported:
|
|
|
| December 31, 2004 |
| December 31, 2003 |
| ||||
|
|
|
| As |
| U.S. |
| As |
| U.S. |
|
|
| Notes |
| Reported |
| GAAP |
| Reported |
| GAAP |
|
Current assets |
| (a),(h) |
| 1 195 |
| 1 300 |
| 1 279 |
| 1 375 |
|
Property, plant and equipment, net |
| (c),(h) |
| 10 289 |
| 10 340 |
| 8 936 |
| 8 974 |
|
Deferred charges and other |
| (a),(e) |
| 320 |
| 367 |
| 286 |
| 333 |
|
Total assets |
|
|
| 11 804 |
| 12 007 |
| 10 501 |
| 10 682 |
|
Current liabilities |
| (a) |
| 1 409 |
| 1 701 |
| 1 060 |
| 1 349 |
|
Long-term borrowings |
| (a),(h) |
| 2 217 |
| 2 275 |
| 2 448 |
| 2 967 |
|
Accrued liabilities and other |
| (e) |
| 749 |
| 815 |
| 616 |
| 692 |
|
Future income taxes |
| (a),(c),(e) |
| 2 532 |
| 2 526 |
| 2 022 |
| 2 015 |
|
Preferred securities |
| (c) |
| — |
| — |
| 476 |
| — |
|
Share capital |
| (b) |
| 651 |
| 699 |
| 604 |
| 652 |
|
Contributed surplus |
| (b) |
| 32 |
| 44 |
| 7 |
| 9 |
|
Cumulative foreign currency translation |
| (g) |
| (55 | ) | — |
| (26 | ) | — |
|
Retained earnings |
|
|
| 4 269 |
| 4 176 |
| 3 294 |
| 3 136 |
|
Accumulated other comprehensive income |
| (a),(e),(g) |
| — |
| (229 | ) | — |
| (138 | ) |
Total liabilities and shareholders’ equity |
|
|
| 11 804 |
| 12 007 |
| 10 501 |
| 10 682 |
|
(a) Derivative Financial Instruments
The company accounts for its derivative financial instruments under Canadian GAAP as described in note 7. Financial Accounting Standards Board Statement (Statement) 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended by Statements 138 and 149 (the Standards), establishes U.S. GAAP accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. Generally, all derivatives, whether designated in hedging relationships or not, and excluding normal purchases and normal sales, are required to be recorded on the balance sheet at fair value. If the derivative is designated as a fair value hedge, changes in the fair value of the derivative and changes in the fair value of the hedged item attributable to the hedged risk each period are recognized in the Consolidated Statements of Earnings. If the derivative is designated as a cash flow hedge, the effective portions of the changes in fair value of the derivative are initially recorded in other comprehensive income (“OCI”) each period and are recognized in the Consolidated Statements of Earnings when the hedged item is recognized. Accordingly, ineffective portions of changes in the fair value of hedging instruments are recognized in net earnings immediately for both fair value and cash flow hedges. Gains or losses arising from hedging activities, including the ineffective portion, are reported in the same earnings statement caption as the hedged item.
The determination of hedge effectiveness and the measurement of hedge ineffectiveness for cash flow hedges is based on internally derived valuations. The company uses these valuations to estimate the fair values of the underlying physical commodity contracts.
Commodity Price Risk
As described in note 7, Suncor manages crude price variability by entering into U.S. dollar WTI derivative transactions and has historically, in certain instances, combined U.S. dollar WTI derivative transactions and Canadian/U.S. foreign exchange derivative contracts. As at December 31, 2004 the company had hedged a portion of its forecasted Canadian dollar denominated cash flows subject to U.S. dollar WTI commodity price risk for 2005. The company had not hedged any portion of the foreign exchange component of these forecasted cash flows.
While the company’s current strategic intent is to only manage the exposure relating to changes in the U.S. dollar WTI component of its crude oil sales, U.S. GAAP requires the company to consider all cash flows arising from forecasted Canadian dollar denominated crude oil sales when measuring the ineffectiveness of its cash flow hedges. In periods of significant Canadian/U.S. dollar foreign exchange fluctuations, material hedge ineffectiveness can result from unhedged foreign exchange exposures. This ineffectiveness arises despite the company’s assessment that its U.S. dollar WTI hedging instruments are highly effective in achieving offsetting changes in cash flows attributable to its forecasted Canadian dollar denominated crude oil sales.
Suncor Energy Inc. 2004 Annual Report
89
Under U.S. GAAP, for the year ended December 31, 2004, the company would have recognized $57 million of hedge ineffectiveness relating to forecasted cash flows in 2005 primarily due to foreign exchange fluctuations during the period. The net earnings impact of this ineffectiveness will not be recognized for Canadian GAAP purposes until the related forecasted crude oil sales occur in 2005.
Interest Rate Risk
The company periodically enters into derivative financial instrument contracts such as interest rate swaps as part of its risk management strategy to minimize exposure to changes in cash flows of interest-bearing debt. At December 31, 2004, the company had interest rate derivatives classified as fair value hedges outstanding for up to seven years relating to fixed rate debt.
De-designated Hedging Instruments
During 2003, the company de-designated and monetized purchased crude oil call option hedging instruments for net proceeds of $28 million. For Canadian GAAP purposes, as it was probable that the underlying forecasted crude oil sales would occur, the related $28 million pretax gain on monetization of the call options was deferred and will be recognized as additional crude oil revenues during 2004. For US GAAP purposes, the company would have recognized the $28 million pre tax gain as hedge ineffectiveness income during 2003.
Non-designated Hedging Instruments
In 1999, the company sold inventory and subsequently entered into a derivative contract with an option to repurchase the inventory at the end of five years. The company realized an economic benefit as a result of liquidating a portion of its inventory. The derivative did not qualify for hedge accounting as the company did not have purchase price risk associated with the repurchase of the inventory. This derivative did not represent a U.S. GAAP difference as the company recorded this derivative at fair value for Canadian purposes.
During the fourth quarter of 2001, the company made a payment of $29 million to terminate a long-term natural gas contract. The contract had been designated as a hedge under Canadian GAAP, and the resulting settlement loss of $18 million, net of income taxes of $11 million, was to be deferred and recognized as the hedged item was settled. During 2002, in connection with the sale of the company’s retail natural gas marketing business (see note 18), the company disposed of the related hedged item. Accordingly, for Canadian GAAP purposes, the company recognized the entire settlement loss of $18 million during 2002. For U.S. GAAP purposes, the long-term contract would have been designated as a normal purchase and sale transaction, and the after-tax loss of $18 million would have been recognized in 2001 on the initial settlement of the contract.
Accumulated OCI and U.S. GAAP Net Earnings Impacts
A reconciliation of changes in accumulated OCI attributable to derivative hedging activities for the years ended December 31 is as follows:
($ millions) |
| 2004 |
| 2003 |
|
OCI attributable to derivatives and hedging activities, beginning of the period, net of income taxes of $34 (2003 – $41) |
| (71 | ) | (89 | ) |
Current period net changes arising from cash flow hedges, net of income taxes of $61 (2003 – $26) |
| (122 | ) | (54 | ) |
Net hedging losses at the beginning of the period reclassified to earnings during the period, net of income taxes of $26 (2003 – $33) |
| 55 |
| 72 |
|
OCI attributable to derivatives and hedging activities, end of period, net of income taxes of $69 (2003 – $34) |
| (138 | ) | (71 | ) |
For the year ended December 31, 2004, assets increased by $133 million and liabilities increased by $328 million as a result of recording all derivative instruments at fair value.
The loss associated with realized and unrealized hedge ineffectiveness on derivative contracts designated as cash flow hedges during the period was $130 million, net of income taxes of $66 million (2003 – loss of $199 million, net of income taxes of $93 million; 2002 – loss of $19 million, net of income taxes of $9 million). The company estimates that $139 million of after-tax hedging losses will be reclassified from OCI to current period earnings within the next 12 months as a result of forecasted sales occurring.
For the year ended December 31, 2004, U.S. GAAP net earnings would have increased by $65 million, net of income taxes of $27 million (2003 – decreased net earnings of $120 million, net of income taxes of $56 million; 2002 – increased net earnings of $6 million, net of income taxes of $4 million) to reflect the impact of the above items.
Suncor Energy Inc. 2004 Annual Report
90
(b) Stock-based Compensation
Under Canadian GAAP, compensation expense has not been recognized for common share options granted prior to January 1, 2003, including options issued in connection with both the company’s SunShare long-term incentive plan, as well as those common shares and common share options awarded to employees under the company’s previous long-term incentive program that matured April 1, 2002. Under U.S. GAAP, certain of the SunShare options would have been accounted for using the variable method of accounting for employee stock compensation. Further, for U.S. GAAP purposes, compensation expense would have been recognized ratably over the life of the previous long-term incentive program for those options and common shares awarded under that plan. For the year ended December 31, 2004, U.S. GAAP net earnings would have been reduced by $10 million (2003 – $2 million; 2002 – $12 million) to reflect additional stock-based compensation expense.
The company now expenses the compensation cost of all common share options issued after January 1, 2003, ratably over the estimated vesting period of the respective options. For U.S. GAAP purposes, the company would have adopted Statement 148 in 2003, permitting the company to expense common share options issued after January 1, 2003, in a manner consistent with Canadian GAAP.
Consistent with Canadian GAAP, for U.S. GAAP purposes the company would have continued to disclose pro forma stock-based compensation cost for common stock options awarded prior to January 1, 2003 (“pre-2003 options”) as if the fair value method had been adopted. Under U.S. GAAP, had the company accounted for its pre-2003 options using the fair value method (excluding the earnings effect of the SunShare and long-term employee incentive options described above), pro forma net earnings and pro forma basic earnings per share for the year ended December 31, 2004, would have been reduced by $37 million (2003 – $27 million; 2002 – $24 million) and $0.08 per share (2003 – $0.06; 2002 – $0.05), respectively.
(c) Preferred Securities
Under Canadian GAAP, preferred securities were classified as shareholders’ equity and the interest distributions thereon, net of income taxes, were accounted for as dividends. Under U.S. GAAP, the preferred securities would have been classified as long-term debt and the interest distributions thereon would have been accounted for as financing expenses. Preferred securities denominated in U.S. dollars of US$163 million would have been revalued at the rate in effect at the related balance sheet date, with any foreign exchange gains (losses) recognized in the Consolidated Statements of Earnings. Further, under U.S. GAAP the interest distributions would have been eligible for interest capitalization.
Under Canadian GAAP, issue costs of the preferred securities, net of the related income tax credits, were charged against shareholders’ equity. Under U.S. GAAP, these issue costs would have been deferred and amortized to earnings over the term of the related long-term debt.
For U.S. GAAP purposes, these differences would have reduced net earnings for the year ended December 31, 2004 by $12 million, net of income taxes of $6 million (2003 – an increase to net earnings of $12 million, net of an income tax recovery of $8 million; 2002 – a reduction to net earnings of $29 million, net of income taxes of $20 million).
Under Canadian GAAP, the interest distributions on the preferred securities for the year ended December 31, 2004 of $9 million (2003 – $45 million; 2002 – $48 million) were classified as financing activities in the Consolidated Statements of Cash Flows. Under U.S. GAAP, the interest distributions of $9 million (2003 – $45 million; 2002 – $48 million) and the amortization of issue costs for the year ended December 31, 2004, of $1 million (2003 – $3 million; 2002 – $3 million) would have been classified as operating activities.
The preferred securities were redeemed on March 15, 2004.
(d) Asset Retirement Obligations
Under Canadian GAAP, the company retroactively adopted Canadian accounting standards related to asset retirement obligations (AROs) on January 1, 2004, with restatements of all prior period comparative amounts. Under U.S. GAAP the company would have adopted AROs on January 1, 2003, and would have been required to record the cumulative effect of the change in accounting policy in 2003 earnings. This GAAP difference would have decreased U.S. GAAP net earnings by $61 million in 2003 and increased net earnings by $12 million in 2002.
(e) Minimum Pension Liability
Under U.S. GAAP, recognition of an additional minimum pension liability is required when the accumulated benefit obligation exceeds the fair value of plan assets to the extent that such excess is greater than accrued pension costs otherwise recorded. For the purposes of determining the additional minimum pension liability, the accumulated benefit obligation does not incorporate projections of future compensation increases in the determination of the obligation. No such adjustment is required under Canadian GAAP.
Suncor Energy Inc. 2004 Annual Report
91
Under U.S. GAAP, at December 31, 2004, the company would have recognized a minimum pension liability of $66 million (2003 – $76 million), an intangible asset of $11 million (2003 – $13 million) and other comprehensive loss of $36 million, net of income taxes of $19 million (2003 – $41 million, net of income taxes of $22 million). Other comprehensive income for the year ended December 31, 2004 would have increased by $5 million, net of income taxes of $3 million (2003 – an increase in other comprehensive income of $7 million, net of income taxes of $nil; 2002 – a decrease in other comprehensive income of $20 million, net of income taxes of $10 million).
(f) Discontinued Operations
During 2002, the company disposed of its retail natural gas business for net proceeds of $62 million, and recognized an after-tax gain on sale of $35 million for Canadian GAAP purposes. The retail natural gas marketing business was not considered significant to the company’s overall business operations, and was not classified as a business segment for the purposes of discontinued operations reporting. Accordingly, financial results of the retail natural gas marketing business were not segregated from the financial results of the company’s other operations prior to the date of disposal of the business.
For U.S. GAAP purposes, the company would have adopted Statement 144, “Accounting for the Impairment and Disposal of Long-Lived Assets,” effective January 1, 2002. For the purposes of Statement 144, the retail natural gas business would have been considered a distinguishable component of the company, and reflected as a discontinued operation for the year ended December 31, 2002. For segmented reporting purposes, the retail natural gas marketing business was included in the Energy Marketing and Refining – Canada operating segment in 2002.
Selected financial information regarding the discontinued retail natural gas business is as follows for the year ended December 31:
($ millions) |
| 2004 |
| 2003 |
| 2002 |
|
Revenues included in discontinued operations |
| — |
| — |
| 81 |
|
Income from retail natural gas business operations, net of income taxes of $nil (2003 – $nil; 2002 – $4) |
| — |
| — |
| 8 |
|
Gain on disposal of retail natural gas business, net of income taxes of $nil (2003 – $nil; 2002 – $10) |
| — |
| — |
| 48 |
|
There were no remaining assets or liabilities related to the discontinued operations at December 31, 2004 or at December 31, 2003.
(g) Cumulative Foreign Currency Translation
Under Canadian GAAP, foreign currency losses of $29 million (2003 – $26 million) arising on translation of the company’s Denver-based foreign operations have been recorded directly to shareholders’ equity. Under U.S. GAAP, these foreign currency translation losses would be included as a component of comprehensive income.
(h) Variable Interest Entities
For U.S. GAAP purposes, the company would be required to consolidate the VIE related to the sale of equipment as described in note 11(c) as of January 1, 2004. The impact on the December 31, 2004, balance sheet would be an increase to property, plant and equipment of $14 million, an increase to inventory of $8 million and an increase to long-term debt of $22 million.
The accounts receivable securitization program, as currently structured, does not meet the FIN 46(R) criteria for consolidation by Suncor.
Recently Issued Accounting Standards
In December 2004, the U.S. Financial Accounting Standards Board issued SFAS 123(R), “Share-Based Payment”. The standard, effective July 1, 2005, requires the recognition of an expense for employee services received in exchange for an award of equity instruments based on the grant date fair value of the award. The cost is to be recognized over the period for which an employee is required to provide the service in exchange for the award. In addition, SFAS 123(R) requires recognition of compensation expense for the portion of outstanding unvested awards granted prior to the effective date. The company currently records an expense under Canadian GAAP for all common share options issued on or after January 1, 2003, with a corresponding increase recorded as contributed surplus in the Consolidated Statements of Changes in Shareholders’ Equity. The company expects that adoption of SFAS 123(R) on July 1, 2005, for U.S. GAAP reporting will not have a significant impact on net earnings.
Suncor Energy Inc. 2004 Annual Report
92
quarterly summary (unaudited)
FINANCIAL DATA
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Quarter Ended |
|
|
| For the Quarter Ended |
|
|
| ||||||||||||
|
| Mar |
| June |
| Sept |
| Dec |
| Total |
| Mar |
| June |
| Sept |
| Dec |
| Total |
|
|
| 31 |
| 30 |
| 30 |
| 31 |
| Year |
| 31 |
| 30 |
| 30 |
| 31 |
| Year |
|
($ millions except per share amounts) |
| 2004 |
| 2004 |
| 2004 |
| 2004 |
| 2004 |
| 2003 |
| 2003 |
| 2003 |
| 2003 |
| 2003 |
|
Revenues |
| 1 795 |
| 2 201 |
| 2 315 |
| 2 310 |
| 8 621 |
| 1 700 |
| 1 385 |
| 1 788 |
| 1 698 |
| 6 571 |
|
Net earnings (loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Sands |
| 238 |
| 232 |
| 263 |
| 262 |
| 995 |
| 305 |
| 70 |
| 259 |
| 254 |
| 888 |
|
Natural Gas |
| 22 |
| 35 |
| 23 |
| 35 |
| 115 |
| 27 |
| 28 |
| 26 |
| 39 |
| 120 |
|
Energy Marketing and Refining – Canada |
| 30 |
| (3 | ) | 29 |
| 24 |
| 80 |
| 21 |
| 17 |
| 9 |
| 6 |
| 53 |
|
Refining and Marketing – U.S.A (c) |
| (3 | ) | 12 |
| 15 |
| 10 |
| 34 |
| — |
| — |
| 14 |
| 4 |
| 18 |
|
Corporate and eliminations |
| (60 | ) | (73 | ) | 7 |
| 2 |
| (124 | ) | 13 |
| 1 |
| (17 | ) | (1 | ) | (4 | ) |
|
| 227 |
| 203 |
| 337 |
| 333 |
| 1 100 |
| 366 |
| 116 |
| 291 |
| 302 |
| 1 075 |
|
Per common share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings attributable to common shareholders |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
| 0.48 |
| 0.44 |
| 0.74 |
| 0.73 |
| 2.40 |
| 0.84 |
| 0.27 |
| 0.63 |
| 0.67 |
| 2.41 |
|
Diluted |
| 0.46 |
| 0.43 |
| 0.73 |
| 0.72 |
| 2.36 |
| 0.77 |
| 0.24 |
| 0.62 |
| 0.61 |
| 2.24 |
|
Cash dividends |
| 0.05 |
| 0.06 |
| 0.06 |
| 0.06 |
| 0.23 |
| 0.0425 |
| 0.05 |
| 0.05 |
| 0.05 |
| 0.1925 |
|
Cash flow from (used in) operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Sands |
| 365 |
| 421 |
| 509 |
| 457 |
| 1 752 |
| 541 |
| 321 |
| 488 |
| 453 |
| 1 803 |
|
Natural Gas |
| 83 |
| 90 |
| 80 |
| 66 |
| 319 |
| 88 |
| 66 |
| 80 |
| 64 |
| 298 |
|
Energy Marketing and Refining – Canada |
| 56 |
| 23 |
| 52 |
| 57 |
| 188 |
| 49 |
| 41 |
| 27 |
| 47 |
| 164 |
|
Refining and Marketing – U.S.A (c) |
| (6 | ) | 21 |
| 21 |
| 23 |
| 59 |
| — |
| — |
| 25 |
| 9 |
| 34 |
|
Corporate and eliminations |
| (76 | ) | (65 | ) | (77 | ) | (79 | ) | (297 | ) | (65 | ) | (70 | ) | (36 | ) | (49 | ) | (220 | ) |
|
| 422 |
| 490 |
| 585 |
| 524 |
| 2 021 |
| 613 |
| 358 |
| 584 |
| 524 |
| 2 079 |
|
OPERATING DATA
OIL SANDS
(thousands of barrels per day) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Base operations |
| 213.9 |
| 210.8 |
| 230.2 |
| 206.9 |
| 215.6 |
| 211.1 |
| 188.2 |
| 231.5 |
| 235.2 |
| 216.6 |
|
Firebag |
| 5.9 |
| 15.1 |
| 7.3 |
| 15.6 |
| 10.9 |
| — |
| — |
| — |
| — |
| — |
|
|
| 219.8 |
| 225.9 |
| 237.5 |
| 222.5 |
| 226.5 |
| 211.1 |
| 188.2 |
| 231.5 |
| 235.2 |
| 216.6 |
|
Sales |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Light sweet crude oil |
| 112.2 |
| 118.7 |
| 113.5 |
| 115.3 |
| 114.9 |
| 120.7 |
| 86.4 |
| 109.0 |
| 132.7 |
| 112.3 |
|
Diesel |
| 27.5 |
| 29.7 |
| 28.7 |
| 25.5 |
| 27.9 |
| 30.1 |
| 22.9 |
| 24.8 |
| 27.2 |
| 26.3 |
|
Light sour crude oil |
| 74.3 |
| 68.9 |
| 76.3 |
| 80.9 |
| 75.1 |
| 60.4 |
| 73.9 |
| 77.5 |
| 81.3 |
| 73.3 |
|
Bitumen |
| — |
| 14.5 |
| 7.9 |
| 11.0 |
| 8.4 |
| — |
| 1.2 |
| 16.1 |
| 8.3 |
| 6.4 |
|
|
| 214.0 |
| 231.8 |
| 226.4 |
| 232.7 |
| 226.3 |
| 211.2 |
| 184.4 |
| 227.4 |
| 249.5 |
| 218.3 |
|
Suncor Energy Inc. 2004 Annual Report
93
|
| For the Quarter Ended |
|
|
| For the Quarter Ended |
|
|
| ||||||||||||
|
| Mar |
| June |
| Sept |
| Dec |
| Total |
| Mar |
| June |
| Sept |
| Dec |
| Total |
|
|
| 31 |
| 30 |
| 30 |
| 31 |
| Year |
| 31 |
| 30 |
| 30 |
| 31 |
| Year |
|
|
| 2004 |
| 2004 |
| 2004 |
| 2004 |
| 2004 |
| 2003 |
| 2003 |
| 2003 |
| 2003 |
| 2003 |
|
OIL SANDS (continued) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales price (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(dollars per barrel) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Light sweet crude oil |
| 40.26 |
| 45.70 |
| 46.03 |
| 50.55 |
| 45.60 |
| 46.69 |
| 39.87 |
| 37.96 |
| 36.67 |
| 40.26 |
|
Other (diesel, light sour crude oil and bitumen) |
| 35.85 |
| 38.28 |
| 42.29 |
| 39.62 |
| 39.13 |
| 40.62 |
| 32.94 |
| 32.92 |
| 30.72 |
| 33.93 |
|
Total |
| 38.16 |
| 41.88 |
| 44.08 |
| 44.68 |
| 42.28 |
| 44.09 |
| 36.19 |
| 35.34 |
| 33.89 |
| 37.19 |
|
Total (a) |
| 43.28 |
| 48.18 |
| 52.72 |
| 54.40 |
| 49.78 |
| 48.77 |
| 38.14 |
| 38.05 |
| 36.63 |
| 40.22 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(dollars per barrel sold rounded to the nearest $0.05) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash operating costs and total operating costs – Base Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash costs |
| 9.65 |
| 9.75 |
| 9.00 |
| 10.90 |
| 9.80 |
| 9.20 |
| 10.70 |
| 8.20 |
| 9.25 |
| 9.25 |
|
Natural gas |
| 2.10 |
| 2.30 |
| 1.40 |
| 2.20 |
| 2.00 |
| 3.10 |
| 2.45 |
| 1.65 |
| 1.60 |
| 2.15 |
|
Imported bitumen |
| 0.40 |
| 0.05 |
| 0.10 |
| 0.10 |
| 0.15 |
| 0.10 |
| 0.10 |
| — |
| — |
| 0.05 |
|
Cash operating costs (2) |
| 12.15 |
| 12.10 |
| 10.50 |
| 13.20 |
| 11.95 |
| 12.40 |
| 13.25 |
| 9.85 |
| 10.85 |
| 11.45 |
|
Firebag start-up costs |
| 1.20 |
| — |
| — |
| — |
| 0.30 |
| — |
| — |
| — |
| — |
| — |
|
Total cash operating costs (3) |
| 13.35 |
| 12.10 |
| 10.50 |
| 13.20 |
| 12.25 |
| 12.40 |
| 13.25 |
| 9.85 |
| 10.85 |
| 11.45 |
|
Depreciation, depletion and amortization |
| 6.20 |
| 6.15 |
| 5.70 |
| 6.25 |
| 6.10 |
| 6.30 |
| 6.30 |
| 5.30 |
| 5.40 |
| 5.80 |
|
Total operating costs (4) |
| 19.55 |
| 18.25 |
| 16.20 |
| 19.45 |
| 18.35 |
| 18.70 |
| 19.55 |
| 15.15 |
| 16.25 |
| 17.25 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash operating costs and total operating costs – Firebag |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash costs |
| — |
| 6.55 |
| 14.90 |
| 7.00 |
| 8.30 |
| — |
| — |
| — |
| — |
| — |
|
Natural gas |
| — |
| 11.65 |
| 11.90 |
| 10.45 |
| 11.20 |
| — |
| — |
| — |
| — |
| — |
|
Cash operating costs (5) |
| — |
| 18.20 |
| 26.80 |
| 17.45 |
| 19.50 |
| — |
| — |
| — |
| — |
| — |
|
Depreciation, depletion and amortization |
| — |
| 5.80 |
| 7.45 |
| 5.55 |
| 6.00 |
| — |
| — |
| — |
| — |
| — |
|
Total operating costs (6) |
| — |
| 24.00 |
| 34.25 |
| 23.00 |
| 25.50 |
| — |
| — |
| — |
| — |
| — |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NATURAL GAS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross production (b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas |
| 197 |
| 209 |
| 201 |
| 193 |
| 200 |
| 184 |
| 175 |
| 194 |
| 194 |
| 187 |
|
Natural gas liquids |
| 2.2 |
| 2.2 |
| 2.6 |
| 2.9 |
| 2.5 |
| 2.4 |
| 2.1 |
| 2.5 |
| 2.4 |
| 2.3 |
|
Crude oil |
| 0.9 |
| 1.1 |
| 1.0 |
| 1.0 |
| 1.0 |
| 1.4 |
| 1.6 |
| 1.6 |
| 1.0 |
| 1.4 |
|
Total (barrel of oil equivalent per day at 6:1 for natural gas) |
| 35.9 |
| 38.1 |
| 37.1 |
| 36.1 |
| 36.8 |
| 34.5 |
| 32.8 |
| 36.4 |
| 35.7 |
| 34.9 |
|
Average sales price (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas |
| 6.54 |
| 6.77 |
| 6.49 |
| 7.02 |
| 6.70 |
| 7.54 |
| 6.63 |
| 6.07 |
| 5.53 |
| 6.42 |
|
Natural gas (a) (dollars per |
| 6.59 |
| 6.84 |
| 6.53 |
| 6.98 |
| 6.73 |
| 7.59 |
| 6.65 |
| 6.04 |
| 5.51 |
| 6.42 |
|
Natural gas liquids |
| 38.13 |
| 43.53 |
| 42.06 |
| 46.46 |
| 42.82 |
| 41.65 |
| 33.45 |
| 33.50 |
| 35.45 |
| 36.08 |
|
Crude oil – conventional |
| 44.14 |
| 47.08 |
| 55.43 |
| 55.26 |
| 50.41 |
| 47.75 |
| 37.82 |
| 38.31 |
| 36.91 |
| 40.29 |
|
Suncor Energy Inc. 2004 Annual Report
94
|
| For the Quarter Ended |
|
|
| For the Quarter Ended |
|
|
| ||||||||||||
|
| Mar |
| June |
| Sept |
| Dec |
| Total |
| Mar |
| June |
| Sept |
| Dec |
| Total |
|
|
| 31 |
| 30 |
| 30 |
| 31 |
| Year |
| 31 |
| 30 |
| 30 |
| 31 |
| Year |
|
|
| 2004 |
| 2004 |
| 2004 |
| 2004 |
| 2004 |
| 2003 |
| 2003 |
| 2003 |
| 2003 |
| 2003 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ENERGY MARKETING AND REFINING – CANADA |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refined product sales (thousands of cubic metres per day) |
| 15.2 |
| 15.5 |
| 15.3 |
| 15.6 |
| 15.4 |
| 15.7 |
| 14.9 |
| 15.2 |
| 14.2 |
| 15.0 |
|
Margins |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refining (7) (cents per litre) |
| 7.8 |
| 7.4 |
| 8.8 |
| 7.9 |
| 8.0 |
| 7.5 |
| 4.7 |
| 6.5 |
| 7.0 |
| 6.5 |
|
Refining (7), (a) (cents per litre) |
| 7.8 |
| 8.0 |
| 8.8 |
| 7.8 |
| 8.1 |
| 7.8 |
| 4.2 |
| 6.4 |
| 6.9 |
| 6.4 |
|
Retail (8) (cents per litre) |
| 5.0 |
| 4.3 |
| 3.7 |
| 4.5 |
| 4.4 |
| 7.0 |
| 6.2 |
| 7.0 |
| 6.3 |
| 6.6 |
|
Utilization of refining capacity (%) |
| 108 |
| 85 |
| 104 |
| 101 |
| 100 |
| 103 |
| 100 |
| 91 |
| 86 |
| 95 |
|
REFINING AND MARKETING – U.S.A. (c) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refined product sales (thousands of cubic metres per day) |
| 8.1 |
| 8.9 |
| 10.9 |
| 9.5 |
| 9.3 |
| — |
| — |
| 9.8 |
| 8.6 |
| 9.1 |
|
Margins |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refining (7) (cents per litre) |
| 5.0 |
| 9.0 |
| 5.1 |
| 7.7 |
| 6.7 |
| — |
| — |
| 7.9 |
| 4.6 |
| 5.9 |
|
Refining (7), (a) (cents per litre) |
| 5.0 |
| 9.3 |
| 5.3 |
| 7.7 |
| 6.8 |
| — |
| — |
| 7.9 |
| 4.6 |
| 5.9 |
|
Retail (8) (cents per litre) |
| 5.0 |
| 6.2 |
| 4.2 |
| 6.0 |
| 5.4 |
| — |
| — |
| 6.4 |
| 4.8 |
| 5.6 |
|
Utilization of refining capacity (%) |
| 85 |
| 86 |
| 99 |
| 100 |
| 92 |
| — |
| — |
| 101 |
| 96 |
| 98 |
|
(a) Excludes the impact of hedging activities.
(b) Currently all Natural Gas production is located in the Western Canada Sedimentary Basin.
(c) Refining and Marketing – U.S.A. reflects the results of operations since acquisition on August 1, 2003.
Definitions
(1) Average sales price – Calculated before royalties and net of related transportation costs (including or excluding the impact of hedging activities as noted).
(2) Cash operating costs – base operations – Include cash costs that are defined as operating, selling and general expenses (excluding inventory changes), accretion expense, taxes other than income taxes and the cost of bitumen imported from third parties. Per barrel amounts are based on production volumes. For a reconciliation of this non GAAP financial measure see page 52 of MD&A.
(3) Total cash operating costs – base operations – Include cash operating costs – base operations as defined above and cash start-up costs for in-situ operations. Per barrel amounts are based on mining production volumes.
(4) Total operating costs – base operations – Include total cash operating costs – base operations as defined above and non-cash operating costs. Per barrel amounts are based on mining production volumes.
(5) Cash operating costs – Firebag – Include cash costs that are defined as operating, selling and general expenses (excluding inventory changes), accretion expense and taxes other than income taxes. Per barrel amounts are based on in-situ production volumes.
(6) Total operating costs – Firebag – Include cash operating costs – Firebag as defined above and non-cash operating costs. Per barrel amounts are based on in-situ production volumes.
(7) Refining margin – Calculated as the average wholesale unit price from all products less average unit cost of crude oil.
(8) Retail margin – Calculated as the average street price of Sunoco (Energy, Marketing and Refining – Canada) and Phillips 66-branded (Refining and Marketing – U.S.A.) retail gasoline net of federal excise tax and other adjustments, less refining gasoline transfer price.
Metric conversion
Crude oil, refined products, etc. – 1m3 (cubic metre) = approx. 6.29 barrels
Natural gas – 1m3 (cubic metre) = approx. 35.49 cubic feet
Suncor Energy Inc. 2004 Annual Report
95
five-year financial summary (unaudited)
($ millions except for ratios) |
| 2004 |
| 2003(a) |
| 2002 |
| 2001 |
| 2000 |
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
Oil Sands |
| 3 596 |
| 3 061 |
| 2 616 |
| 1 372 |
| 1 402 |
|
Natural Gas |
| 567 |
| 512 |
| 339 |
| 481 |
| 458 |
|
Energy Marketing and Refining – Canada |
| 3 460 |
| 2 936 |
| 2 508 |
| 2 673 |
| 2 604 |
|
Refining and Marketing – U.S.A. |
| 1 495 |
| 515 |
| — |
| — |
| — |
|
Corporate and eliminations |
| (497 | ) | (453 | ) | (431 | ) | (232 | ) | (980 | ) |
|
| 8 621 |
| 6 571 |
| 5 032 |
| 4 294 |
| 3 484 |
|
Net earnings (loss) |
|
|
|
|
|
|
|
|
|
|
|
Oil Sands |
| 995 |
| 888 |
| 782 |
| 273 |
| 303 |
|
Natural Gas |
| 115 |
| 120 |
| 34 |
| 116 |
| 95 |
|
Energy Marketing and Refining – Canada |
| 80 |
| 53 |
| 61 |
| 79 |
| 80 |
|
Refining and Marketing – U.S.A. |
| 34 |
| 18 |
| — |
| — |
| — |
|
Corporate and eliminations |
| (124 | ) | (4 | ) | (128 | ) | (92 | ) | (117 | ) |
|
| 1 100 |
| 1 075 |
| 749 |
| 376 |
| 361 |
|
Cash flow from (used in) operations |
|
|
|
|
|
|
|
|
|
|
|
Oil Sands |
| 1 752 |
| 1 803 |
| 1 475 |
| 486 |
| 655 |
|
Natural Gas |
| 319 |
| 298 |
| 164 |
| 280 |
| 238 |
|
Energy Marketing and Refining – Canada |
| 188 |
| 164 |
| 112 |
| 165 |
| 174 |
|
Refining and Marketing – U.S.A. |
| 59 |
| 34 |
| — |
| — |
| — |
|
Corporate and eliminations |
| (297 | ) | (220 | ) | (311 | ) | (100 | ) | (109 | ) |
|
| 2 021 |
| 2 079 |
| 1 440 |
| 831 |
| 958 |
|
Capital and exploration expenditures |
|
|
|
|
|
|
|
|
|
|
|
Oil Sands |
| 1 118 |
| 948 |
| 617 |
| 1 479 |
| 1 808 |
|
Natural Gas |
| 279 |
| 183 |
| 163 |
| 132 |
| 127 |
|
Energy Marketing and Refining – Canada |
| 228 |
| 122 |
| 60 |
| 54 |
| 45 |
|
Refining and Marketing – U.S.A. |
| 190 |
| 31 |
| — |
| — |
| — |
|
Corporate |
| 31 |
| 32 |
| 37 |
| 13 |
| 18 |
|
|
| 1 846 |
| 1 316 |
| 877 |
| 1 678 |
| 1 998 |
|
Total assets |
| 11 804 |
| 10 501 |
| 9 011 |
| 8 430 |
| 7 174 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital employed (b) |
|
|
|
|
|
|
|
|
|
|
|
Short-term and long-term debt, less cash and cash equivalents |
| 2 159 |
| 2 091 |
| 2 671 |
| 3 143 |
| 2 235 |
|
Shareholders’ equity |
| 4 897 |
| 4 355 |
| 3 397 |
| 2 731 |
| 2 435 |
|
|
| 7 056 |
| 6 446 |
| 6 068 |
| 5 874 |
| 4 670 |
|
Less capitalized costs related to major projects in progress |
| (1 467 | ) | (1 122 | ) | (511 | ) | (3 691 | ) | (2 497 | ) |
|
| 5 589 |
| 5 324 |
| 5 557 |
| 2 183 |
| 2 173 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Suncor employees (number at year-end) |
| 4 605 |
| 4 231 |
| 3 422 |
| 3 307 |
| 3 043 |
|
Suncor Energy Inc. 2004 Annual Report
96
|
| 2004 |
| 2003(a) |
| 2002 |
| 2001 |
| 2000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Dollars per common share |
|
|
|
|
|
|
|
|
|
|
|
Net earnings attributable to common shareholders |
| 2.40 |
| 2.41 |
| 1.61 |
| 0.76 |
| 0.74 |
|
Cash dividends |
| 0.23 |
| 0.1925 |
| 0.17 |
| 0.17 |
| 0.17 |
|
Cash flow from operations |
| 4.46 |
| 4.62 |
| 3.22 |
| 1.87 |
| 2.16 |
|
Cash flow from operations after deducting dividends paid on preferred securities |
| 4.44 |
| 4.52 |
| 3.11 |
| 1.76 |
| 2.06 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Ratios |
|
|
|
|
|
|
|
|
|
|
|
Return on capital employed (%) (c) |
| 19.1 |
| 18.4 |
| 14.6 |
| 17.7 |
| 16.3 |
|
Return on capital employed (%) (d) |
| 16.2 |
| 16.0 |
| 13.7 |
| 7.3 |
| 9.1 |
|
Return on shareholders’ equity (%) (e) |
| 23.8 |
| 27.7 |
| 24.4 |
| 14.6 |
| 16.0 |
|
Debt to debt plus shareholders’ equity (%) (f) |
| 31.4 |
| 36.3 |
| 44.2 |
| 53.5 |
| 48.1 |
|
Net debt to cash flow from operations (times) (g) |
| 1.1 |
| 1.0 |
| 1.9 |
| 3.8 |
| 2.3 |
|
Interest coverage – cash flow basis (times) (h) |
| 14.7 |
| 15.7 |
| 10.6 |
| 5.9 |
| 9.0 |
|
Interest coverage – net earnings basis (times) (i) |
| 11.6 |
| 13.5 |
| 8.1 |
| 3.6 |
| 5.4 |
|
(a) Refining and Marketing – U.S.A. reflects the results of operations since acquisition on August 1, 2003.
(b) Capital employed – the sum of shareholders’ equity and short-term debt plus long-term debt less cash and cash equivalents, less capitalized costs related to major projects in progress (as applicable).
(c) Net earnings adjusted for after-tax financing expenses (income) for the 12-month period ended; divided by average capital employed. Average capital employed is the sum of shareholders’ equity and short-term debt plus long-term debt less cash and cash equivalents at the beginning and end of the year, divided by two, less average capitalized costs related to major projects in progress (as applicable). Return on capital employed (ROCE) for Suncor operating segments presented in the Quarterly Summary is calculated in a manner consistent with consolidated ROCE. For a detailed annual reconciliation of this non GAAP financial measure see page 51 of MD&A.
(d) If capital employed were to include capitalized costs related to major projects in progress, the return on capital employed would be as stated on this line.
(e) Net earnings as a percentage of average shareholders’ equity. Average shareholders’ equity is the sum of total shareholders’ equity at the beginning and end of the year divided by two.
(f) Short-term debt plus long-term debt; divided by the sum of short-term debt, long-term debt and shareholders’ equity.
(g) Short-term debt plus long-term debt less cash and cash equivalents; divided by cash flow from operations for the year then ended.
(h) Cash flow from operations plus current income taxes and interest expense; divided by the sum of interest expense and capitalized interest.
(i) Net earnings plus income taxes and interest expense; divided by the sum of interest expense and capitalized interest.
Suncor Energy Inc. 2004 Annual Report
97
share trading information (unaudited)
Common shares are listed on the Toronto Stock Exchange and New York Stock Exchange under the symbol SU. The following share trading information reflects a two-for-one split of the company’s common shares during 2002.
|
| For the Quarter Ended |
| For the Quarter Ended |
| ||||||||||||
|
| Mar 31 |
| June 30 |
| Sept 30 |
| Dec 31 |
| Mar 31 |
| June 30 |
| Sept 30 |
| Dec 31 |
|
Share ownership |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average number outstanding, weighted monthly (thousands) (a) |
| 452 123 |
| 452 283 |
| 452 565 |
| 453 900 |
| 449 187 |
| 449 485 |
| 449 756 |
| 450 505 |
|
Share price (dollars) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Toronto Stock Exchange |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High |
| 38.02 |
| 36.80 |
| 41.49 |
| 44.49 |
| 27.50 |
| 26.60 |
| 27.14 |
| 32.85 |
|
Low |
| 31.62 |
| 30.95 |
| 32.80 |
| 38.20 |
| 23.87 |
| 23.31 |
| 24.75 |
| 25.07 |
|
Close |
| 35.97 |
| 34.01 |
| 40.40 |
| 42.40 |
| 25.61 |
| 25.34 |
| 24.93 |
| 32.50 |
|
New York Stock Exchange – US$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High |
| 28.75 |
| 28.09 |
| 32.63 |
| 36.15 |
| 18.50 |
| 19.68 |
| 19.59 |
| 25.42 |
|
Low |
| 24.68 |
| 22.55 |
| 24.90 |
| 31.16 |
| 15.32 |
| 16.10 |
| 17.86 |
| 18.57 |
|
Close |
| 27.35 |
| 25.61 |
| 32.01 |
| 35.40 |
| 17.47 |
| 18.75 |
| 18.55 |
| 25.06 |
|
Shares traded (thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Toronto Stock Exchange |
| 100 401 |
| 109 073 |
| 102 460 |
| 86 424 |
| 83 756 |
| 67 815 |
| 64 875 |
| 93 538 |
|
New York Stock Exchange |
| 45 120 |
| 59 254 |
| 64 519 |
| 66 536 |
| 23 600 |
| 23 369 |
| 21 725 |
| 27 138 |
|
Per common share information(dollars) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings attributable to common shareholders |
| 0.48 |
| 0.44 |
| 0.74 |
| 0.73 |
| 0.84 |
| 0.27 |
| 0.63 |
| 0.67 |
|
Cash dividends |
| 0.05 |
| 0.06 |
| 0.06 |
| 0.06 |
| 0.0425 |
| 0.05 |
| 0.05 |
| 0.05 |
|
(a) The company had approximately 2,375 holders of record of common shares as at January 31, 2005.
Information for Security Holders Outside Canada
Cash dividends paid to shareholders resident in countries with which Canada has an income tax convention are usually subject to Canadian non-resident withholding tax of 15%. The withholding tax rate is reduced to 5% on dividends paid to a corporation if it is a resident of the United States that owns at least 10% of the voting shares of the company.
Suncor Energy Inc. 2004 Annual Report
98
supplemental financial and operating information (unaudited)
|
| 2004 |
| 2003 |
| 2002 |
| 2001 |
| 2000 |
|
OIL SANDS |
|
|
|
|
|
|
|
|
|
|
|
Production (thousands of barrels per day) |
| 226.5 |
| 216.6 |
| 205.8 |
| 123.2 |
| 113.9 |
|
Sales (thousands of barrels per day) |
|
|
|
|
|
|
|
|
|
|
|
Light sweet crude oil |
| 114.9 |
| 112.3 |
| 104.7 |
| 56.2 |
| 64.3 |
|
Diesel |
| 27.9 |
| 26.3 |
| 23.0 |
| 14.8 |
| 9.3 |
|
Light sour crude oil |
| 75.1 |
| 73.3 |
| 68.3 |
| 42.0 |
| 35.8 |
|
Bitumen |
| 8.4 |
| 6.4 |
| 9.3 |
| 8.5 |
| 6.2 |
|
|
| 226.3 |
| 218.3 |
| 205.3 |
| 121.5 |
| 115.6 |
|
Average sales price (dollars per barrel) |
|
|
|
|
|
|
|
|
|
|
|
Light sweet crude oil |
| 45.60 |
| 40.26 |
| 37.56 |
| 34.17 |
| 35.31 |
|
Other (diesel, light sour crude oil and bitumen) |
| 39.13 |
| 33.93 |
| 29.58 |
| 24.86 |
| 27.09 |
|
Total |
| 42.28 |
| 37.19 |
| 33.65 |
| 29.17 |
| 31.67 |
|
Total (a) |
| 49.78 |
| 40.22 |
| 36.94 |
| 34.21 |
| 41.29 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash operating costs – base operations (b) |
| 11.95 |
| 11.45 |
| 11.15 |
| 11.35 |
| 11.50 |
|
Total cash operating costs – base operations (b) |
| 12.25 |
| 11.45 |
| 11.15 |
| 11.35 |
| 11.50 |
|
Total operating costs – base operations (b) |
| 18.35 |
| 17.25 |
| 17.25 |
| 16.70 |
| 17.25 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash operating costs – Firebag (b), (e) |
| 19.50 |
|
|
|
|
|
|
|
|
|
Total operating costs – Firebag (b), (e) |
| 25.50 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital employed excluding major projects in progress |
| 4 169 |
| 4 050 |
| 4 512 |
| 1 378 |
| 1 402 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Return on capital employed (%) (c) |
| 22.9 |
| 20.8 |
| 16.7 |
| 19.6 |
| 22.1 |
|
Return on capital employed (%) (d) |
| 18.8 |
| 17.4 |
| 15.6 |
| 6.2 |
| 10.2 |
|
(a) Excludes the impact of hedging activities.
(b) Dollars per barrel rounded to the nearest $0.05. See definitions on page 95.
(c) See definitions on page 97.
(d) If capital employed were to include capitalized costs related to major projects in progress, the return on capital employed would be as stated on this line.
(e) Firebag commenced commercial operations on April 1, 2004.
Suncor Energy Inc. 2004 Annual Report
99
|
| 2004 |
| 2003 |
| 2002 |
| 2001 |
| 2000 |
|
NATURAL GAS |
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
|
|
|
|
Natural gas (millions of cubic feet per day) |
|
|
|
|
|
|
|
|
|
|
|
Gross |
| 200 |
| 187 |
| 179 |
| 177 |
| 200 |
|
Net |
| 147 |
| 142 |
| 124 |
| 124 |
| 142 |
|
Natural gas liquids (thousands of barrels per day) |
|
|
|
|
|
|
|
|
|
|
|
Gross |
| 2.5 |
| 2.3 |
| 2.4 |
| 2.4 |
| 3.0 |
|
Net |
| 1.8 |
| 1.7 |
| 1.7 |
| 1.7 |
| 2.1 |
|
Crude oil (thousands of barrels per day) |
|
|
|
|
|
|
|
|
|
|
|
Gross |
| 1.0 |
| 1.4 |
| 1.5 |
| 1.5 |
| 4.2 |
|
Net |
| 0.8 |
| 1.1 |
| 1.2 |
| 1.1 |
| 3.3 |
|
Total (thousands of boe (a) per day) |
|
|
|
|
|
|
|
|
|
|
|
Gross |
| 36.8 |
| 34.9 |
| 33.7 |
| 33.4 |
| 40.5 |
|
Net |
| 27.1 |
| 26.4 |
| 23.6 |
| 23.5 |
| 29.1 |
|
Average sales price |
|
|
|
|
|
|
|
|
|
|
|
Natural gas (dollars per thousand cubic feet) |
| 6.70 |
| 6.42 |
| 3.91 |
| 6.09 |
| 4.72 |
|
Natural gas (dollars per thousand cubic feet) (b) |
| 6.73 |
| 6.42 |
| 3.91 |
| 6.12 |
| 4.73 |
|
Natural gas liquids (dollars per barrel) |
| 42.82 |
| 36.08 |
| 29.35 |
| 34.38 |
| 36.66 |
|
Crude oil – conventional (dollars per barrel) |
| 50.41 |
| 40.29 |
| 31.72 |
| 33.92 |
| 29.50 |
|
Capital employed |
| 448 |
| 400 |
| 422 |
| 291 |
| 387 |
|
Return on capital employed (%) (e) |
| 27.1 |
| 29.2 |
| 9.5 |
| 34.2 |
| 17.8 |
|
Undeveloped landholdings (c) |
|
|
|
|
|
|
|
|
|
|
|
Oil and gas (millions of acres) |
|
|
|
|
|
|
|
|
|
|
|
Western Canada |
|
|
|
|
|
|
|
|
|
|
|
Gross |
| 0.7 |
| 0.5 |
| 0.5 |
| 0.6 |
| 1.4 |
|
Net |
| 0.5 |
| 0.4 |
| 0.4 |
| 0.5 |
| 1.1 |
|
International |
|
|
|
|
|
|
|
|
|
|
|
Gross |
| 0.7 |
| 0.9 |
| 1.2 |
| 1.7 |
| 1.3 |
|
Net |
| 0.4 |
| 0.2 |
| 0.7 |
| 1.3 |
| 1.1 |
|
Net wells drilled (d) |
|
|
|
|
|
|
|
|
|
|
|
Exploratory |
|
|
|
|
|
|
|
|
|
|
|
Oil |
| — |
| — |
| — |
| — |
| — |
|
Gas |
| 5 |
| 2 |
| 2 |
| 4 |
| 1 |
|
Dry |
| 5 |
| 31 |
| 19 |
| 16 |
| 15 |
|
Development |
|
|
|
|
|
|
|
|
|
|
|
Oil |
| — |
| 1 |
| — |
| — |
| 2 |
|
Gas |
| 16 |
| 16 |
| 18 |
| 16 |
| 14 |
|
Dry |
| — |
| 4 |
| 4 |
| 2 |
| 3 |
|
|
| 26 |
| 54 |
| 43 |
| 38 |
| 35 |
|
(a) Barrel of oil equivalent – converts natural gas to oil on the approximate energy equivalent basis that 6,000 cubic feet equals one barrel of oil.
(b) Excludes the impact of hedging activities.
(c) Metric conversion: Landholdings – 1 hectare = approximately 2.5 acres.
(d) Excludes interests in eleven net exploratory wells and three net development wells in progress at the end of 2004.
(e) See definitions on page 97.
Suncor Energy Inc. 2004 Annual Report
100
|
| 2004 |
| 2003 |
| 2002 |
| 2001 |
| 2000 |
|
ENERGY MARKETING AND REFINING – CANADA |
|
|
|
|
|
|
|
|
|
|
|
Refined product sales (thousands of cubic metres per day) |
|
|
|
|
|
|
|
|
|
|
|
Transportation fuels |
|
|
|
|
|
|
|
|
|
|
|
Gasoline |
|
|
|
|
|
|
|
|
|
|
|
Retail (b) |
| 4.6 |
| 4.4 |
| 4.5 |
| 4.3 |
| 4.2 |
|
Other |
| 4.1 |
| 4.2 |
| 4.4 |
| 4.4 |
| 4.0 |
|
Jet fuel |
| 0.9 |
| 0.7 |
| 0.4 |
| 0.7 |
| 1.1 |
|
Diesel |
| 3.1 |
| 3.0 |
| 2.9 |
| 3.1 |
| 3.1 |
|
|
| 12.7 |
| 12.3 |
| 12.2 |
| 12.5 |
| 12.4 |
|
Petrochemicals |
| 0.8 |
| 0.8 |
| 0.6 |
| 0.5 |
| 0.6 |
|
Heating oils |
| 0.4 |
| 0.5 |
| 0.4 |
| 0.4 |
| 0.4 |
|
Heavy fuel oils |
| 0.7 |
| 0.8 |
| 0.6 |
| 0.8 |
| 0.6 |
|
Other |
| 0.8 |
| 0.6 |
| 0.7 |
| 0.6 |
| 0.6 |
|
|
| 15.4 |
| 15.0 |
| 14.5 |
| 14.8 |
| 14.6 |
|
Margins (cents per litre) |
|
|
|
|
|
|
|
|
|
|
|
Refining |
| 8.0 |
| 6.5 |
| 4.8 |
| 5.7 |
| 5.9 |
|
Refining (c) |
| 8.1 |
| 6.4 |
| 4.8 |
| 5.7 |
| 5.9 |
|
Retail |
| 4.4 |
| 6.6 |
| 6.6 |
| 6.6 |
| 6.6 |
|
Crude oil supply and refining |
|
|
|
|
|
|
|
|
|
|
|
Processed at Sarnia refinery (thousands of cubic metres per day) |
| 11.1 |
| 10.5 |
| 10.6 |
| 10.2 |
| 10.9 |
|
Utilization of refining capacity (%) |
| 100 |
| 95 |
| 95 |
| 92 |
| 98 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital employed excluding major projects in progress |
| 512 |
| 551 |
| 485 |
| 480 |
| 384 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Return on capital employed (%) (d) |
| 14.6 |
| 10.3 |
| 12.0 |
| 18.3 |
| 20.3 |
|
Return on capital employed (%) (d), (e) |
| 13.6 |
| 10.3 |
| 12.0 |
| 18.3 |
| 20.3 |
|
Retail outlets (f) (number at year-end) |
| 385 |
| 379 |
| 384 |
| 400 |
| 402 |
|
Suncor Energy Inc. 2004 Annual Report
101
|
| 2004 |
| 2003 |
| 2002 |
| 2001 |
| 2000 |
|
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|
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|
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|
REFINING AND MARKETING – U.S.A. (a) |
|
|
|
|
|
|
|
|
|
|
|
Refined product sales (thousands of cubic metres per day) |
|
|
|
|
|
|
|
|
|
|
|
Transportation fuels |
|
|
|
|
|
|
|
|
|
|
|
Gasoline |
|
|
|
|
|
|
|
|
|
|
|
Retail (b) |
| 0.7 |
| 0.7 |
| — |
| — |
| — |
|
Other |
| 3.8 |
| 3.5 |
| — |
| — |
| — |
|
Jet fuel |
| 0.5 |
| 0.5 |
| — |
| — |
| — |
|
Diesel |
| 2.2 |
| 2.3 |
| — |
| — |
| — |
|
|
| 7.2 |
| 7.0 |
| — |
| — |
| — |
|
Asphalt |
| 1.5 |
| 1.7 |
| — |
| — |
| — |
|
Other |
| 0.6 |
| 0.4 |
| — |
| — |
| — |
|
|
| 9.3 |
| 9.1 |
| — |
| — |
| — |
|
Margins (cents per litre) |
|
|
|
|
|
|
|
|
|
|
|
Refining |
| 6.7 |
| 5.9 |
| — |
| — |
| — |
|
Refining (c) |
| 6.8 |
| 5.9 |
| — |
| — |
| — |
|
Retail |
| 5.4 |
| 5.6 |
| — |
| — |
| — |
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil supply and refining |
|
|
|
|
|
|
|
|
|
|
|
Processed at Denver refinery (thousands of cubic metres per day) |
| 8.8 |
| 9.4 |
| — |
| — |
| — |
|
Utilization of refining capacity (%) |
| 92 |
| 98 |
| — |
| — |
| — |
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital employed excluding major projects in progress |
| 232 |
| 270 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Return on capital employed (%) (d), (h) |
| 12.2 |
| — |
|
|
|
|
|
|
|
Return on capital employed (%) (d), (e) |
| 11.0 |
| — |
|
|
|
|
|
|
|
Retail outlets (g) (number at year-end) |
| 43 |
| 43 |
| — |
| — |
| — |
|
(a) Refining and Marketing – U.S.A. reflects the results of operations since acquisition on August 1, 2003.
(b) Excludes sales through joint-venture interests.
(c) Excludes the impact of hedging activities.
(d) See definitions on page 97.
(e) If capital employed were to include capitalized costs related to major projects in progress, the return on capital employed would be as stated on this line.
(f) Sunoco-branded service stations, other private brands managed by EM&R and EM&R’s interest in service stations managed through joint-ventures. Outlets are located mainly in Ontario.
(g) Phillips 66-branded service stations. Outlets are primarily located in the Denver, Colorado area.
(h) For 2003, represents five months of operations since acquisition August 1, 2003 therefore no annual ROCE was calculated.
Suncor Energy Inc. 2004 Annual Report
102
investor information
Stock Trading Symbols and Exchange Listing
Common shares are listed on the Toronto Stock Exchange and New York Stock Exchange under the symbol SU.
Dividends
Suncor’s Board of Directors reviews its dividend policy quarterly. Effective the second quarter of 2004, dividends were increased to $0.06 per share from $0.05 per share resulting in an aggregate 2004 dividend of $0.23 per common share.
Dividend Reinvestment and Common Share Purchase Plan
Suncor’s Dividend Reinvestment and Common Share Purchase Plan enables shareholders to invest cash dividends in common shares or acquire additional shares through optional cash payments without payment of brokerage commissions, service charges or other costs associated with administration of the plan. To obtain additional information, call Computershare Trust Company of Canada at 1-877-982-8760 or visit www.computershare.com. Information regarding the purchase plan is also available at www.suncor.com.
Stock Transfer Agent and Registrar
In Canada, Suncor’s agent is Computershare Trust Company of Canada. In the United States, Suncor’s agent is Computershare Trust Company, Inc.
Independent Auditors
PricewaterhouseCoopers LLP
Independent Reserve Evaluators
Gilbert Laustsen Jung Associates Ltd.
Annual Meeting
Suncor’s annual and special meeting of shareholders will be held at 10:30 a.m. MST on April 28, 2005 at the Metropolitan Centre, 333 Fourth Avenue S.W., Calgary, Alberta. Presentations from the meeting will be web cast live at www.suncor.com.
Corporate Office
Box 38, 112 – 4th Avenue S.W., Calgary, Alberta, T2P 2V5
Telephone: 403-269-8100 Toll free number: 1-866-SUNCOR-1
Facsimile: 403-269-6217 E-mail: info@suncor.com
Analyst and Investor Inquiries
John Rogers, vice president, Investor Relations
Telephone: (403) 269-8670 Facsimile: (403) 269-6217 Email: invest@suncor.com
For further information, to subscribe or cancel duplicate mailings
In addition to annual and quarterly reports, Suncor publishes a biennial Report on Sustainability. All of Suncor’s publications, as well as updates on company news as it happens, are available on our website at www.suncor.com. To subscribe to Suncor e-news, visit our website. To order copies of Suncor’s print materials call 1-800-558-9071.
Sometimes our shareholders receive more than one copy of our Annual Report. If you receive but do not require more than one mailing, call Computershare Trust Company of Canada at 1-877-982-8760. Computershare will update your account information accordingly.
Shareholders can help reduce mailing costs and paper waste by electing to receive Suncor’s Annual Report and other documents electronically. To register for electronic delivery, registered shareholders should visit www.computershare.com. Beneficial shareholders (shareholders holding shares through a broker) should go to www.investordeliverycanada.com and follow the instructions for enrollment.
Suncor Energy Inc. 2004 Annual Report
103
corporate directors and officers
Providing strategic guidance to the company, setting policy direction and ensuring Suncor is fairly reporting its progress are central to the work of Suncor’s Board of Directors.
The Board’s oversight role encompasses Suncor’s strategic planning process, risk management, communication with investors and other stakeholders and standards of business conduct. Suncor’s Board is also responsible for selecting, monitoring and evaluating executive leadership and aligning management’s decision making with long-term shareholder interest. There are no significant differences between Suncor’s governance practices and those prescribed by the New York Stock Exchange (NYSE), with the exception of the requirements applicable to equity compensation plans. A comprehensive description of Suncor’s governance practices, including differences between Toronto Stock Exchange (TSX) and NYSE requirements related to equity compensation plans, is available in the company’s Management Proxy Circular in the investor centre, financial reports and disclosure section of Suncor’s website at www.suncor.com or by calling 1-800-558-9071.
Sarbanes-Oxley
For the year ended December 31, 2004, Suncor has voluntarily complied with the reporting, certification and attestation provisions under the United States Sarbanes-Oxley Act, Section 404.
Independence
As of December 31, 2004, Suncor’s Board of Directors comprises thirteen directors, eleven of whom have been determined by the Board to be independent of management under the guidelines established by the TSX and NYSE. The role of chair is assumed by an independent director and is separate from the role of chief executive officer. Independent directors also chair the four committees of the Board.
Committee |
| Key Responsibilities |
Board Policy, Strategy Review and Governance Committee* |
| Oversees key matters pertaining to Suncor’s values, beliefs and standards of ethical conduct. Reviews key matters pertaining to governance, including organization, composition and effectiveness of the Board. Reviews preliminary stages of key strategic initiatives and projects. Reviews and assesses processes relating to long range and strategic planning and budgeting. |
|
|
|
Human Resources and Compensation Committee* |
| Reviews and ensures Suncor’s overall goals and objectives are supported by appropriate executive compensation philosophy and programs; annually evaluates the performance of the chief executive officer (CEO) against predetermined goals and criteria, and recommends to the Board the total compensation for the CEO. The committee also annually reviews the CEO’s evaluation and recommendations for total compensation of the other executive roles; the executive succession planning process and results, and all major human resources programs. |
|
|
|
Environment, Health and Safety (EH&S) Committee |
| Reviews the effectiveness with which Suncor meets its obligations pertaining to environment, health and safety including the establishment of appropriate policies with regard to legal, industry and community standards and related management systems and compliance. |
|
|
|
Audit Committee* |
| Assists the Board in matters relating to Suncor’s internal controls, internal and external auditors and the external audit process, oil and natural gas reserves reporting, financial reporting and public communication and certain other key financial matters. Provides an open avenue of communication between management, the internal and external auditors and the Board. Approves Suncor’s interim financial statements and management’s discussion and analysis. |
*comprised entirely of independent directors as of December 31, 2004.
Share Ownership
The Board has set guidelines for its own, as well as executive share ownership. Shares held by each Board member and guidelines for Board and executive share ownership are reported annually in Suncor’s Management Proxy Circular.
Suncor Energy Inc. 2004 Annual Report
104
board of directors
JR Shaw (2),(3)
Calgary, Alberta
Chairman of the Board of Directors
Director since 1998
JR Shaw has been the chairman of the Board of Suncor since 2001. He is also the executive chair of Shaw Communications Inc., the company he founded in 1966. Mr. Shaw has served as a director of several Canadian companies and is also a director of the Shaw Foundation. In 2003, Mr. Shaw was named an Officer of the Order of Canada.
Mel E. Benson (3),(4)
Calgary, Alberta
Director since 2000
Mel Benson is president of Mel E. Benson Management Services Inc., an international management consulting firm based in Calgary, Alberta and a director of Pan Global Ventures Energy Ltd. From 1996 to 2000, Mr. Benson was the senior operations advisor, African Development, Exxon Co. International. Mr. Benson is an active member of several charitable and Aboriginal organizations. He is a member of the Council for Advancement of Native Development Officers and the Canadian Aboriginal Professional Association. He is also chair of the Northern Alberta Institute of Technology’s Aboriginal Education Success Initiative.
Brian A. Canfield (2),(3)
Point Roberts, Washington
Chair, Human Resources
and Compensation Committee
Director since 1995
Brian Canfield is the chairman of TELUS Corporation, a telecommunications company. Mr. Canfield also serves as a director of Terasen Inc. and a director and member of the governance committee of the Canadian Public Accountability Board. In 1998, Mr. Canfield was appointed to the Order of British Columbia.
Susan E. Crocker (2),(3)
Toronto, Ontario
Director 2003 to 2005
Susan Crocker, a director of Suncor since April 24, 2003, has advised the company she will not run for re-election to the Board. During her tenure with Suncor, Ms. Crocker was employed as a corporate director and management consultant. From 1999 to 2001, she was the president and chief executive officer of the Hospitals of Ontario Pension Plan and, from 1996 to 1999, she was senior vice president, equity and derivative markets with the TSX.
Bryan P. Davies (1),(4)
Toronto, Ontario
Director 1991 to 1996 and since 2000
Bryan Davies is superintendent of the Financial Services Commission of Ontario. Prior to assuming this role, Mr. Davies served as senior vice president of regulatory affairs with the Royal Bank Financial Group and was vice president, business affairs and chief administrative officer of the University of Toronto. He worked for the Government of Ontario holding a variety of positions, including deputy minister positions in several departments. Mr. Davies is also active with numerous not-for-profit and charitable organizations. He is chair of the Canadian Merit Scholarship Foundation and a director of the Foundation for International Training.
Brian A. Felesky (1),(4)
Calgary, Alberta
Director since 2002
Brian Felesky is a partner in the law firm of Felesky Flynn LLP in Calgary, Alberta. Mr. Felesky also serves as a director of TransCanada Power LP, where he is chair of the audit committee. Mr. Felesky is actively involved in not-for-profit and charitable organizations. He is the co-chair of Homefront on Domestic Violence, vice chair of the Canada West Foundation, member of the senate of Notre Dame College, member of the Board of Governors of the Council for Canadian Unity and a director of three private companies.
John T. Ferguson (1),(2)
Edmonton, Alberta
Chair, Audit Committee
Director since 1995
John Ferguson is chairman of the Board of Princeton Developments Ltd., a real estate company in Edmonton, Alberta, and chair of the Board of TransAlta Corporation in Calgary, Alberta. Mr. Ferguson is also a director of Bellanca Developments Ltd. and the Royal Bank of Canada. He is a director of the C.D. Howe Institute, an advisory member of the Canadian Institute for Advanced Research, and chancellor emeritus and chairman emeritus of the University of Alberta. Mr. Ferguson is also a fellow of the Alberta Institute of Chartered Accountants.
W. Douglas (Doug) Ford (1),(4)
Downers Grove, Illinois
Director since 2004
Doug Ford was chief executive, refining and marketing, for BP p.l.c. from 1998 to 2002 and was responsible for the refining, marketing and transportation network of the company as well as the aviation fuels business, the marine business and BP shipping. Mr. Ford currently serves as a director of USG Corporation, United Airlines Corporation and Air Products and Chemicals, Inc. He is also a member of the Board of Trustees of the University of Notre Dame.
Richard (Rick) L. George
Calgary, Alberta
Director since 1991
Rick George is the president and chief executive officer of Suncor Energy Inc. Mr. George is also a Board member of the U.S. offshore and onshore drilling company, GlobalSantaFe Corporation and serves as chairman of the Canadian Council of Chief Executives.
Suncor Energy Inc. 2004 Annual Report
105
John R. Huff (2),(3)
Houston, Texas
Chair, Board Policy, Strategy Review
and Governance Committee
Director since 1998
John Huff is chairman and chief executive officer of Oceaneering International Inc., an oil field services company. Mr. Huff is also a director of BJ Services Company. He is active in a variety of non-profit organizations, serving as a director for the American Bureau of Shipping and the Marine Resources Foundation, Key Largo and as a trustee for the Houston Museum of Natural Science.
Robert W. Korthals (1)
Toronto, Ontario
Director since 1996
Robert Korthals is the former president of the Toronto-Dominion Bank. Mr. Korthals is currently chairman of the Board of the Ontario Teachers’ Pension Plan Board. He is a director of Bucyrus International, Inc., Great Lakes Carbon Income Trust, Jannock Properties Limited, Rogers Communications Inc., easyHome Inc., Cognos Inc. and several publicly traded investment funds sponsored by Mulvihill Investments. In addition, Mr. Korthals serves as a director of the Canadian Parks and Wilderness Foundation.
M. Ann McCaig (3),(4)
Calgary, Alberta
Chair, Environment,
Health and Safety Committee
Director since 1995
Ann McCaig is chair of the Alberta Adolescent Recovery Centre and a trustee of the Killam Estate. She is co-chair of the Alberta Children’s Hospital Foundation $50 million All for One – All for Kids campaign. Ms. McCaig has been an active member of the community with many local and national organizations including United Way, Banff Centre Foundation and chair of the City of Calgary Police Interpretative Centre. For 14 years she served on the University of Calgary’s board of governors, was named chancellor, and in 1998, earned the distinction of chancellor emeritus. In 2005, Ms. McCaig was named a Member of the Order of Canada.
Michael W. O’Brien (4)
Canmore, Alberta
Director since 2002
Michael O’Brien served as executive vice president, Corporate Development and chief financial officer of Suncor Energy Inc. before his retirement in 2002. Prior to that, Mr. O’Brien was executive vice president of Suncor’s wholly-owned subsidiary, Suncor Energy Products Inc. (formerly Sunoco Inc.) from 1992 to 2000. Mr. O’Brien also serves on the Boards of PrimeWest Energy Inc., Terasen Inc. and Shaw Communications Inc. As well, he is past chair for Canada’s Climate Change Voluntary Challenge and Registry Inc., the Canadian Petroleum Products Institute and the Nature Conservancy Canada.
(1) Audit Committee
(2) Board Policy, Strategy Review and Governance Committee
(3) Human Resources and Compensation Committee
(4) Environment, Health and Safety Committee
In 2004, the Board of Directors met six times. Committees of the Board generally meet four to six times per year with the exception of the Audit Committee, which meets more frequently. With the exception of one Board member absent from one committee meeting, all members attended all board and committee meetings in 2004.
For further information about Suncor’s corporate governance practices and the company’s code of corporate conduct, visit www.suncor.com or call 1-800-558-9071 to order a copy of the company’s Management Proxy Circular.
Suncor Energy Inc. 2004 Annual Report
106
officers
Richard L. George
President and
Chief Executive Officer
J. Kenneth Alley
Senior Vice President
and Chief Financial Officer
M. (Mike) Ashar
Executive Vice President,
Refining and Marketing – U.S.A.
David W. Byler
Executive Vice President,
Natural Gas and Renewable Energy
Robert F. Froese
Treasurer
Terrence J. Hopwood
Senior Vice President
and General Counsel
Sue Lee
Senior Vice President, Human
Resources and Communications
Kevin D. Nabholz
Executive Vice President,
Major Projects
Janice B. Odegaard
Vice President, Associate General
Counsel and Corporate Secretary
Thomas L. Ryley
Executive Vice President, Energy
Marketing and Refining – Canada
Steven W. Williams
Executive Vice President,
Oil Sands
Offices shown are positions held by the officers in relation to business units of Suncor Energy Inc. and its subsidiaries on a consolidated basis. On a legal entity basis, Mr. Ashar is president of Suncor Energy (U.S.A.) Inc., Suncor’s U.S. based downstream subsidiary; Mr. Ryley is president of Suncor’s Canada-based downstream subsidiaries, Suncor Energy Marketing Inc. and Suncor Energy Products Inc.; and Mr. Nabholz is executive vice president of Suncor Energy Services Inc., which provides major projects management and other shared services to the Suncor group of companies.
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The Dow Jones Sustainability Index (DJSI) follows a best-in-class approach comprising the sustainability leaders from each industry. Suncor has been part of the index since the DJSI was launched in 1999. |
| As an Imagine Caring Company, Suncor contributes 1% of its pretax profit to registered charities. |
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Suncor Energy Inc. 2004 Annual Report
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