Home Annual Report 2001




The consolidated financial statements of the Company have been prepared by Management in accordance with Canadian generally accepted accounting principles (Canadian GAAP). These accounting principles are different in some respects from United States generally accepted accounting principles (U.S. GAAP) and the significant differences are described in Note 20. Amounts are stated in Canadian dollars unless otherwise indicated.

The Company's financial statements reflect the plan approved by the Board of Directors in 2001 to dispose of the Gas Marketing business which is included in discontinued operations. All prior period comparative results have been restated to reflect Gas Marketing as discontinued operations. Certain other comparative figures have been reclassified to conform with the current year's presentation.

Since a determination of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of these consolidated financial statements requires the use of estimates and assumptions which have been made using careful judgment. In the opinion of Management, these consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the significant accounting policies summarized below.

BASIS OF PRESENTATION The consolidated financial statements include the accounts of TransCanada PipeLines Limited and its subsidiaries, as well as its proportionate share of the accounts of its joint ventures. The Company uses the equity method of accounting for investments over which it is able to exercise significant influence.

The Alberta System is regulated by the Alberta Energy and Utilities Board (EUB) and the Canadian Mainline and the BC System are subject to the authority of the National Energy Board (NEB). All Canadian natural gas transmission operations are regulated with respect to the determination of tolls, construction and operations. In November 2001, the NEB approved TransCanada's 2001 and 2002 Tolls and Tariff Application for the Canadian Mainline which resolved all issues other than cost of capital. The NEB also determined that interim tolls will remain in place until a final decision is made on cost of capital. Any adjustments to the interim tolls will be recorded in accordance with the final NEB decision. The natural gas pipelines in the United States, the Ocean State Power plant and the Curtis Palmer Power plant are also subject to the authority of regulatory bodies. In order to achieve a proper matching of revenues and expenses, the timing of recognition of certain revenues and expenses in these businesses may differ from that otherwise expected under generally accepted accounting principles.

The Company's short-term investments with maturities of three months or less are considered to be cash equivalents and are recorded at cost, which approximates market value.

Inventories are carried at the lower of average cost or net realizable value.

Plant, property and equipment of natural gas transmission operations are carried at cost. Depreciation is calculated on the straight-line basis. Pipeline and compression equipment are depreciated at annual rates ranging from two to five per cent and metering and other plant are depreciated at various rates. Removal and site restoration costs are not determinable and will be recorded when reasonably estimable and when approved by the regulators. An allowance for funds used during construction, using the rate of return on rate base approved by the regulators, is capitalized and included in the cost of gas transmission plant.

Power and Other
Plant, property and equipment in the power business are recorded at cost and depreciated on the straight-line basis over estimated service lives at average annual rates generally ranging from two to five per cent. Other plant, property and equipment are recorded at cost and depreciated on a straight-line basis over estimated useful lives at average annual rates ranging from four to twenty per cent.

As prescribed by the regulators, the taxes payable method of accounting for income taxes is used for tollmaking purposes for Canadian natural gas transmission operations. Under the taxes payable method, it is not necessary to provide for future income taxes. This method is also used for accounting purposes, since there is reasonable expectation that future taxes payable will be included in future costs of service and recorded in revenues at that time. The liability method of accounting for income taxes is used for the remainder of the Company's operations. Under this method, future tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Future income tax assets and liabilities are measured using enacted or substantively enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Changes to these balances are recognized in income in the period in which they occur.

Canadian income taxes are not provided on the unremitted earnings of foreign investments which are considered to be indefinitely reinvested in foreign operations.

The Company's foreign operations are self-sustaining and are translated into Canadian dollars using the current rate method. Translation adjustments are reflected in the foreign exchange adjustment in Shareholders' Equity.

Exchange gains or losses on the principal amounts of foreign currency debt, junior subordinated debentures and preferred securities related to the Alberta System and the Canadian Mainline are deferred until they are recovered in tolls.

The Company engages in price risk management practices for both trading and non-trading activities. Trading activities are provided by the Company's power marketing operations and are accounted for using the mark-to-market method. Trading activities may be conducted through a variety of instruments with third parties, including contracts for physical delivery of the energy commodity, exchange traded futures contracts involving cash settlements, forward contracts involving cash settlement or physical delivery, swap contracts which require payments to (or receipts from) counterparties based on the differential between fixed and variable prices for commodities, exchange-traded and over-the-counter options, and other contractual arrangements.

Under the mark-to-market method of accounting, energy trading contracts are recorded at fair values in the Consolidated Balance Sheet. Changes in the balance sheet accounts result primarily from changes in the valuation of the portfolio of contracts, new transactions and the maturity and settlement of contracts. The market prices used to value these transactions reflect Management's best estimate considering various factors including closing exchange and over-the-counter quotations, time value and volatility factors underlying the commitments. The values are adjusted to reflect the potential impact of liquidating the Company's position in an orderly manner over a reasonable period of time under present market conditions and to reflect other types of risk, including credit risk.

Net unrealized gains and losses recognized in a period are included in revenues in the Statement of Consolidated Income. They result primarily from transactions originating or settling within that period, and the impact of price movements on outstanding contracts. Cash inflows and outflows associated with energy trading contracts are recognized in cash from operations as settlement occurs.

The Company utilizes derivative and other financial instruments to manage price risk exposure to power generation operations and its exposure to changes in foreign currency exchange rates and interest rates. Gains or losses relating to derivatives that are hedges are deferred and recognized in the same period and in the same financial statement category as the gains or losses on the corresponding hedged transactions. The recognition of gains and losses on derivatives used as hedges for Alberta System and Canadian Mainline exposures is determined through the regulatory process.

A derivative must be designated and effective to be accounted for as a hedge. For cash flow hedges, effectiveness is achieved if the changes in the cash flows of the derivative substantially offset the changes in the cash flows of the hedged position and the timing of the cash flows is similar. Effectiveness for fair value hedges is achieved if the fair value of the derivative substantially offsets changes in fair value attributable to the hedged item. In the event that a derivative does not meet the designation or effectiveness criterion, the gain or loss on the derivative is recognized in income. If a derivative that qualifies as a hedge is settled early, the gain or loss at settlement is deferred and recognized when the gain or loss on the hedged transaction is recognized. Premiums paid or received with respect to derivatives that are hedges are deferred and amortized to income over the term of the hedge.

The Company sponsors both defined benefit and defined contribution plans. The cost of defined benefit pensions and other post-employment benefits earned by employees is actuarially determined using the projected benefit method pro-rated on service and Management's best estimate of expected plan investment performance, salary escalation, retirement ages of employees and expected health care costs. Pension plan assets are measured at fair value. The expected return on pension plan assets is determined using market-related values. Adjustments arising from plan amendments are amortized on a straight-line basis over the average remaining service period of employees active at the date of amendment. The excess of the net actuarial gain or loss over 10 per cent of the greater of the benefit obligation and the fair value of plan assets is amortized over the average remaining service period of the active employees.