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Citi Fun 24 | LSE:BC93 | London | Medium Term Loan |
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RNS Number:8669J TransCanada Pipelines Ld 16 March 2005 PART 4 FINANCIAL AND OTHER INSTRUMENTS The company issues short-term and long-term debt, including amounts in foreign currencies, purchases and sells energy commodities and invests in foreign operations. These activities result in exposures to interest rates, energy commodity prices and foreign currency exchange rates. The company utilizes derivative and other financial instruments to manage its exposure to the risks that result from these activities. A derivative must be designated and effective to be accounted for as a hedge. 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 corresponding hedged transactions. The recognition of gains and losses on derivatives used as hedges for Canadian Mainline, Alberta System, GTN and the Foothills System exposures is determined through the regulatory process. The carrying amounts of derivatives, which hedge the price risk of foreign currency denominated assets and liabilities of self-sustaining foreign operations, are recorded on the balance sheet at their fair value. Gains and losses on these derivatives, realized and unrealized, are included in the foreign exchange adjustment account in Shareholders' Equity as an offset to the corresponding gains and losses on the translation of the assets and liabilities of the foreign subsidiaries. As of January 1, 2004, carrying amounts for interest rate swaps are recorded on the balance sheet at their fair value. Foreign currency transactions hedged by foreign exchange contracts are recorded at the contract rate. Power, natural gas and heat rate derivatives are recorded on the balance sheet at their fair value. The fair values of foreign exchange and interest rate derivatives have been estimated using year-end market rates. The fair values of power, natural gas and heat rate derivatives have been calculated using estimated forward prices for the relevant period. Notional principal amounts are not recorded in the financial statements because these amounts are not exchanged by the company and its counterparties and are not a measure of the company's exposure. Notional amounts are used only as the basis for calculating payments for certain derivatives. M-36 Foreign Investments At December 31, 2004 and 2003, the company had foreign currency denominated assets and liabilities which created an exposure to changes in exchange rates. The company uses foreign currency derivatives to hedge this net exposure on an after-tax basis. The foreign currency derivatives have a floating interest rate exposure which the company partially hedges by entering into interest rate swaps and forward rate agreements. The fair values shown in the table below for those derivatives that have been designated as and are effective as hedges for foreign exchange risk are offset by translation gains or losses on the net assets and are recorded in the foreign exchange adjustment account in Shareholders' Equity. Net Investment in Foreign Assets Asset/(Liability) December 31 2004 2003 (millions of dollars) Accounting Fair Value Notional Fair Notional Treatment or Value or Principal Principal Amount Amount (U.S.) (U.S.) U.S. dollar cross-currency swaps Hedge 95 400 65 250 (maturing 2006 to 2009) U.S. dollar forward foreign Hedge (1 ) 305 3 125 exchange contracts (maturing 2005) U.S. dollar options (maturing Non-hedge 1 100 - - 2005) In accordance with the company's accounting policy, each of the above derivatives is recorded on the consolidated balance sheet at its fair value in 2004. For derivatives that have been designated as and are effective as hedges of the net investment in foreign operations, the offsetting amounts are included in the foreign exchange adjustment account. In addition, at December 31, 2004, the company had interest rate swaps associated with the cross-currency swaps with notional principal amounts of $375 million (2003 - $311 million) and US$250 million (2003 - US$200 million). The carrying amount and fair value of these interest rate swaps was $4 million (2003 - $3 million) and $4 million (2003 - $1 million), respectively. Reconciliation of Foreign Exchange Adjustment Gains/(Losses) December 31 (millions of dollars) 2004 2003 Balance at beginning of year (40 ) 14 Translation losses on foreign currency denominated net assets (64 ) (136 ) Foreign exchange gains on derivatives, net of income taxes 33 82 (71 ) (40 ) Foreign Exchange Gains/(Losses) Foreign exchange gains/(losses) included in Other Expenses/(Income) for the year ended December 31, 2004 are $4 million (2003 - nil; 2002 - $(11) million). Foreign Exchange and Interest Rate Management Activity The company manages certain of the foreign exchange risks of U.S. dollar debt, U.S. dollar expenses and the interest rate exposures of the Canadian Mainline, the Alberta System, GTN and the Foothills System through the use of foreign M-37 currency and interest rate derivatives. Certain of the realized gains and losses on these derivatives are shared with shippers on predetermined terms. The details of the foreign exchange and interest rate derivatives are shown in the table below. Asset/(Liability) December 31 2004 2003 (millions of dollars) Accounting Fair Value Notional Fair Value Notional Treatment or or Principal Principal Amount Amount Foreign Exchange Cross-currency swaps (maturing 2010 to 2012) Hedge (39 ) U.S. 157 (26 ) U.S. 282 Interest Rate Interest rate swaps Canadian dollars (maturing 2005 to 2008) Hedge 7 145 (1 ) 340 (maturing 2006 to 2009) Non-hedge 9 374 10 624 16 9 U.S. dollars (maturing 2010 to 2015) Hedge (2 ) U.S. 275 11 U.S. 50 (maturing 2007 to 2009) Non-hedge 7 U.S. 100 (3 ) U.S. 50 5 8 In accordance with the company's accounting policy, each of the above derivatives is recorded on the consolidated balance sheet at its fair value in 2004. At December 31, 2004, the company also had interest rate swaps associated with the cross-currency swaps with notional principal amounts of $227 million (2003 - $390 million) and US$157 million (2003 - US$282 million). The carrying amount and fair value of these interest rate swaps was $(4) million (2003 - nil) and $(4) million (2003 - $6 million), respectively. M-38 The company manages the foreign exchange and interest rate exposures of its other businesses through the use of foreign currency and interest rate derivatives. The details of these foreign currency and interest rate derivatives are shown in the table below. Asset/(Liability) December 31 2004 2003 (millions of dollars) Accounting Fair Value Notional Fair Value Notional Treatment or or Principal Principal Amount Amount Foreign Exchange Options (maturing 2005) Non-hedge 2 U.S. 225 1 U.S. 25 Forward foreign exchange contracts (maturing 2005) Non-hedge 1 U.S. 29 1 U.S. 19 Cross-currency swaps (maturing 2013) Hedge (16 ) U.S. 100 (7 ) U.S. 100 Interest Rate Options (maturing 2005) Non-hedge - U.S. 50 (2 ) U.S. 50 Interest rate swaps Canadian dollar (maturing 2007 to 2009) Hedge 4 100 2 50 (maturing 2005 to 2011) Non-hedge 1 110 2 100 5 4 U.S. dollar (maturing 2006 to 2013) Hedge 5 U.S. 100 40 U.S. 250 (maturing 2006 to 2010) Non-hedge 22 U.S. 250 (3 ) U.S. 200 27 37 In accordance with the company's accounting policy, each of the above derivatives is recorded on the consolidated balance sheet at its fair value in 2004. At December 31, 2004, the company also had interest rate swaps associated with the cross-currency swaps with notional principal amounts of $136 million (2003 - $136 million) and US$100 million (2003 - US$100 million). The carrying amount and fair value of these interest rate swaps was $(10) million (2003 - nil) and $(10) million (2003 - $(7) million), respectively. Certain of the company's joint ventures use interest rate derivatives to manage interest rate exposures. The company's proportionate share of the fair value of the outstanding derivatives at December 31, 2004 was $1 million (2003 - $(1) million). Energy Price Risk Management The company executes power, natural gas and heat rate derivatives for overall management of its asset portfolio. Heat rate contracts are contracts for the sale or purchase of power that are priced based on a natural gas index. The fair values and notional volumes of the swap, option, forward and heat rate contracts are shown in the tables below. In accordance with the company's accounting policy, each of the derivatives in the table below is recorded on the balance sheet at its fair value in 2004 and 2003. M-39 Power Asset/(Liability) December 31 (millions of dollars) 2004 2003 Accounting Fair Fair Treatment Value Value Power - swaps (maturing 2005 to 2011) Hedge 7 (5 ) (maturing 2005) Non-hedge (2 ) - Gas - swaps, forwards and options (maturing 2005 to 2016) Hedge (39 ) (34 ) (maturing 2005) Non-hedge (2 ) (1 ) Heat rate contracts (maturing 2005 to 2006) Hedge (1 ) (1 ) Power (GWh) Gas (Bcf) Notional Volumes December 31, 2004 Accounting Purchases Sales Purchases Sales Treatment Power - swaps (maturing 2005 to 2011) Hedge 3,314 7,029 - - (maturing 2005) Non-hedge 438 - - - Gas - swaps, forwards and options (maturing 2005 to 2016) Hedge - - 80 84 (maturing 2005) Non-hedge - - 5 8 Heat rate contracts (maturing 2005 to 2006) Hedge - 229 2 - December 31, 2003 Power - swaps Hedge 1,331 4,787 - - Non-hedge 59 77 - - Gas - swaps, forwards and options Hedge - - 79 81 Non-hedge - - - 7 Heat rate contracts Hedge - 735 1 - U.S. Dollar Transaction Hedges To reduce risk and protect margins when purchase and sale contracts are denominated in different currencies, the company may enter into forward foreign exchange contracts and foreign exchange options which establish the foreign exchange rate for the cash flows from the related purchase and sale transactions. RISK MANAGEMENT Risk Management Overview TCPL and its subsidiaries are exposed to market, financial and counterparty risks in the normal course of their business activities. The risk management function assists in managing these various business activities and the risks associated with them. A strong commitment to a risk management culture by TCPL's management supports this function. TCPL's primary risk management objective is to protect earnings and cash flow. The risk management function is guided by the following principles that are applied to all businesses and risk types: * Board Oversight Risk strategies, policies and limits are subject to review and approval by TCPL's Board of Directors. * Independent Review Risk-taking activities are subject to independent review, separate from the business lines that initiate the activity. * Assessment Processes are in place to ensure that risks are properly assessed at the transaction and counterparty levels. * Review and Reporting Market positions and exposures, and the creditworthiness of counterparties are subject to ongoing review and reporting to executive management. M-40 * Accountability Business lines are accountable for all risks and the related returns for their particular businesses. * Audit Review Individual risks are subject to internal audit review, with independent reporting to the Audit Committee of TCPL's Board of Directors. The processes within TCPL's risk management function are designed to ensure that risks are properly identified, quantified, reported and managed. Risk management strategies, policies and limits are designed to ensure TCPL's risk taking is consistent with the company's business objectives and risk tolerance. Risks are managed within limits ultimately established by the company's Board of Directors and implemented by senior management, monitored by risk management personnel and audited by internal audit personnel. TCPL manages market risk exposures in accordance with the company's corporate market risk policies and position limits. The company's primary market risks result from volatility in commodity prices, interest rates and foreign currency exchange rates. Senior management reviews these exposures and reports on a regular basis to the Audit Committee of TCPL's Board of Directors. Market Risk Management In order to manage market risk exposures created by fixed and variable pricing arrangements at different pricing indices and delivery points, the company enters into offsetting physical positions and derivative financial instruments. Market risks are quantified using value-at-risk methodology and are reviewed weekly by senior management. Financial Risk Management TCPL monitors the financial market risk exposures relating to the company's investments in foreign currency denominated net assets, regulated and non-regulated long-term debt portfolios and foreign currency exposure on transactions. The market risk exposures created by these business activities are managed by establishing offsetting positions or through the use of derivative financial instruments. Counterparty Risk Management Counterparty risk is the financial loss that the company would experience if the counterparty failed to meet its obligations in accordance with the terms and conditions of its contracts with the company. Counterparty risk is mitigated by conducting financial and other assessments to establish a counterparty's creditworthiness, setting exposure limits and monitoring exposures against these limits, and, where warranted, obtaining financial assurances. The company's counterparty risk management practices and positions are further described in Note 15 to the consolidated financial statements. Risks and Risk Management Related to the Kyoto Protocol TCPL believes that the natural gas that is transported and the electricity that is generated by its facilities play a critical role in meeting continental energy demand. The company also recognizes, however, that its facilities produce emissions that can also contribute to climate change and air related issues. For this reason, the management of air emissions and climate change issues is a key area of the company's environmental stewardship work. Climate change policy development is well under way in North America. In December 2002, the Canadian government registered its instrument of ratification with the United Nations, making Canada the 100th country to ratify the Kyoto Protocol. Following ratification, the federal government initiated discussions with industry regarding emissions reductions from sources in three broad categories: the oil and gas sector, the electricity sector and the mining/ manufacturing sector. The mechanism that is proposed for achieving the reduction is a domestic emissions trading system that would cap emissions from sectors at predetermined emissions intensity levels. As direct emitters of greenhouse gas emissions, TCPL's facilities will be impacted by climate change policy developments in Canada. The fossil-fired power plants, pipeline systems and carbon black facilities are expected to be captured under the proposed federal government plan for industrial emitters. At present, however, the details of the target allocation within sectors and allowable compliance options have not been finalized. Until the allocation of targets within the sector are set and until compliance options are fully developed, it is difficult to determine the level of impact to the company's Canadian asset base. M-41 Over the next year, TCPL will continue to participate in climate change policy discussions in the jurisdictions where the company has assets and business interests. Climate change is a strategic issue for TCPL and management of this important environmental concern has been ongoing for several years. TCPL has a comprehensive climate change strategy in place that includes five key areas of activities: * participation in policy forums; * implementation of direct emissions reduction programs; * assessment of new technology; * evaluation of emissions trading mechanisms; and * assessment of business opportunities. Activities are ongoing in each of these areas and the company is committed to sharing its progress on key activities publicly. Over the past several years, TCPL has documented its technical activities and research and development work in yearly reports to Canada's Climate Change Voluntary Challenge & Registry Inc. The Canadian government has legislated mandatory greenhouse gas emissions reporting beginning in 2005. TCPL will continue to report on the activities that are under way to manage greenhouse gas emissions. Disclosure Controls and Procedures and Internal Controls Pursuant to regulations adopted by the U.S. Securities and Exchange Commission (SEC), under the Sarbanes-Oxley Act of 2002, TCPL's management evaluates the effectiveness of the design and operation of the company's disclosure controls and procedures (disclosure controls). This evaluation is done under the supervision of, and with the participation of, the President and Chief Executive Officer and the Chief Financial Officer. As of the end of the period covered by this report, TCPL's management evaluated the effectiveness of its disclosure controls. Based on that evaluation, the President and Chief Executive Officer and the Chief Financial Officer have concluded that TCPL's disclosure controls are effective in ensuring that material information relating to TCPL is made known to management on a timely basis, and is included in this report. To the best of these officers' knowledge and belief, there have been no significant changes in internal controls over financial reporting or in other factors that could significantly affect internal controls over financial reporting subsequent to the date on which such evaluation was completed in connection with this report. CEO and CFO Certifications With respect to the year ending December 31, 2004, TCPL's President and Chief Executive Officer has provided the New York Stock Exchange the annual CEO certification regarding TCPL's compliance with the New York Stock Exchange's corporate governance listing standards applicable to foreign issuers. In addition, TCPL's President and Chief Executive Officer and Chief Financial Officer have filed with the SEC certifications regarding the quality of TCPL's public disclosures relating to its fiscal 2004 reports filed with the SEC. CRITICAL ACCOUNTING POLICY The company accounts for the impacts of rate regulation in accordance with generally accepted accounting principles (GAAP) as outlined in Note 1 to the consolidated financial statements. Three criteria must be met to use these accounting principles: the rates for regulated services or activities must be subject to approval by a regulator; the regulated rates must be designed to recover the cost of providing the services or products; and it must be reasonable to assume that rates set at levels to recover the cost can be charged to and will be collected from customers in view of the demand for services or products and the level of direct and indirect competition. The company's management believes that all three of these criteria have been met. The most significant impact from the use of these accounting principles is that in order to appropriately reflect the economic impact of the regulators' decisions regarding the company's revenues and tolls, and to thereby achieve a proper matching of revenues and expenses, the timing of recognition of certain expenses and revenues in the regulated businesses may differ from that otherwise expected under GAAP. The most significant example of this relates to the recording of income taxes on the taxes payable basis as outlined in Note 16 to the consolidated financial statements. M-42 CRITICAL ACCOUNTING ESTIMATE Since a determination of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of the company's consolidated financial statements requires the use of estimates and assumptions which have been made using careful judgment. TCPL's critical accounting estimate is depreciation expense. TCPL's plant, property and equipment are depreciated on a straight-line basis over their estimated useful lives. Depreciation expense for the year ended December 31, 2004 was $945 million. Depreciation expense impacts the Gas Transmission and Power segments of the company. In the Gas Transmission business, depreciation rates are approved by the regulators and recoverable based on the cost of providing the services or products. A change in the estimation of the useful lives of the plant, property and equipment in the Gas Transmission segment would, if recovery through rates is permitted by the regulators, have no material impact on TCPL's net income but would directly impact funds generated from operations. In 2004, TCPL recognized in income the remaining amount related to the critical accounting estimate of the after-tax deferred gain recorded on the 2001 sale of the Gas Marketing business, which is further described in Discontinued Operations. ACCOUNTING CHANGES Asset Retirement Obligations In January 2003, the Canadian Institute of Chartered Accountants (CICA) issued a new Handbook Section "Asset Retirement Obligations". The new section focuses on the recognition and measurement of liabilities for obligations associated with the retirement of property, plant and equipment when those obligations result from the acquisition, construction, development or normal operation of the assets. The section requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset. The liability is accreted at the end of each period through charges to operating expenses. This section was effective for TCPL as of January 1, 2004 and was applied retroactively with restatement of prior periods. See Note 2 to the consolidated financial statements for the impact of this accounting change. Hedging Relationships Effective January 1, 2004, the company adopted the provisions of the CICA's new Accounting Guideline "Hedging Relationships" that specifies the circumstances in which hedge accounting is appropriate, including the identification, documentation, designation and effectiveness of hedges, and the discontinuance of hedge accounting. See Note 2 to the consolidated financial statements for the impact of this accounting change. Generally Accepted Accounting Principles Effective January 1, 2004, the company adopted the new Handbook Section "Generally Accepted Accounting Principles" which establishes standards for financial reporting in accordance with GAAP. It defines primary sources of GAAP and requires that an entity apply every relevant primary source, therefore eliminating the ability to rely on industry practice to support a particular accounting policy and provides an exemption for rate-regulated operations. This section was applied prospectively. See Note 2 to the consolidated financial statements for the impact of this accounting change. General Standards of Financial Statement Presentation Effective January 1, 2004, the company adopted the new Handbook Section "General Standards of Financial Statement Presentation" which clarifies what constitutes "fair presentation in accordance with GAAP". The adoption of this section did not have an impact on the company's consolidated financial statements. Employee Future Benefits In March 2004, the CICA amended the existing Handbook Section "Employee Future Benefits". The amendments expand the disclosure requirements for employee future benefits and are effective for fiscal years ending on or after June 30, 2004. The company adopted these provisions effective December 31, 2004. The impacts of the amendments have been included in Note 19 to the consolidated financial statements. Impairment of Long-Lived Assets Effective January 1, 2004, the company adopted the new Handbook Section "Impairment of Long-Lived Assets". This section establishes new standards for the recognition, measurement and disclosure of the impairment of long-lived assets and establishes new write-down provisions. The adoption of this section did not have an impact on the company's consolidated financial statements. M-43 Consolidation of Variable Interest Entities In June 2003, the Accounting Standards Board of the CICA issued a new Accounting Guideline "Consolidation of Variable Interest Entities" which requires enterprises to identify variable interest entities in which they have an interest, determine whether they are the primary beneficiary of such entities and, if so, to consolidate them. For TCPL, the guideline's requirements are effective as of January 1, 2005. Adopting the provisions of this guideline is not expected to impact the company's consolidated financial statements. Financial Instruments - Disclosure and Presentation In November 2004, the CICA amended the existing Handbook Section "Financial Instruments - Disclosure and Presentation" to provide guidance for classifying certain financial instruments that embody obligations that may be settled by the issuance of the issuer's equity shares as debt when the instrument that embodies the obligations does not establish an ownership relationship. This amendment is effective for fiscal years beginning on or after November 1, 2004. As a result, the equity component of preferred securities will be classified as debt effective January 1, 2005. DISCONTINUED OPERATIONS TCPL's Board of Directors approved plans in previous years to dispose of the company's International, Canadian Midstream, Gas Marketing and certain other businesses. As of December 31, 2003, TCPL's investments in Gasoducto del Pacifico (Gas Pacifico), INNERGY Holdings S.A. (INNERGY) and P.T. Paiton Energy Company (Paiton), which were previously approved for disposal, were accounted for as part of continuing operations due to the length of time it had taken the company to dispose of these assets. Gas Pacifico and INNERGY are included in the Gas Transmission segment and Paiton is included in the Power segment. It is the intention of the company to continue with its plan to dispose of these investments. In 2004, the company reviewed the provision for loss on discontinued operations and the after-tax deferred gain. As a result of this review, TCPL recognized in income in 2004 the remaining $52 million of the original $102 million after-tax deferred gain. In 2003, TCPL recognized in income $50 million of the original $102 million after-tax deferred gain. The company's net income/(loss) from discontinued operations in 2002 was nil. SUBSIDIARIES AND INVESTMENTS TCPL and its subsidiaries and investments that hold significant operating assets are noted below. Subsidiary/Investment Major Operating Organized Effective Assets under the Percentage Laws of Ownership by TCPL TransCanada PipeLines Limited Canadian Mainline, Canada BC System NOVA Gas Transmission Ltd. Alberta System Alberta 100 TransCanada Pipeline Ventures Ltd. Ventures LP Alberta 100 Foothills Pipe Lines Ltd. Foothills System Canada 100 TransCanada Pipeline USA Ltd. Nevada 100 Gas Transmission Northwest Corporation GTN California 100 TransCanada Power Marketing Ltd. U.S. power Delaware 100 operations Great Lakes Gas Transmission Limited Great Lakes Delaware 50 Partnership Iroquois Gas Transmission System L.P. Iroquois Delaware 41 Portland Natural Gas Transmission Portland Maine 61.7 System Partnership TC PipeLines, LP TC PipeLines, LP's Delaware 33.4 assets Northern Border Pipeline Company Northern Border Texas 10 Tuscarora Gas Transmission Company Tuscarora Nevada 17.4 TransCanada Energy Ltd. Canadian power Canada 100 operations TransCanada Power, L.P. Power LP assets Ontario 30.6 Bruce Power L.P. Bruce Power Ontario 31.6 Trans Quebec & Maritimes Pipeline Inc. TQM Canada 50 CrossAlta Gas Storage & Services Ltd. CrossAlta Alberta 60 TransGas de Occidente S.A. TransGas Colombia 46.5 M-44 SELECTED THREE YEAR CONSOLIDATED FINANCIAL DATA(1) (millions of dollars except per share amounts) 2004 2003 2002 Income Statement Revenues 5,107 5,357 5,214 Net income Continuing operations 978 801 747 Discontinued operations 52 50 - 1,030 851 747 Balance Sheet Total assets 22,129 20,698 20,172 Long-term debt 9,713 9,465 8,815 Non-recourse debt of joint ventures 779 761 1,222 Preferred securities (liability component) 19 22 238 Per Common Share Data Net income - Basic Continuing operations $2.03 $1.66 $1.56 Discontinued operations 0.11 0.11 - $2.14 $1.77 $1.56 Net income - Diluted Continuing operations $2.03 $1.66 $1.55 Discontinued operations 0.11 0.11 - $2.14 $1.77 $1.55 Dividends declared(2) $1.17 $1.08 $1.00 (1) The selected three year consolidated financial data has been prepared in accordance with Canadian GAAP. Certain comparative figures have been reclassified to conform with the current year's presentation. For a discussion on the factors affecting the comparability of the financial data, including discontinued operations, refer to Note 1 and Note 22 of TCPL's 2004 audited consolidated financial statements. (2) Effective May 15, 2003, TCPL dividends have been declared in an amount equal to the aggregate dividend paid by TransCanada. The amounts presented reflect the aggregate amount divided by total outstanding common shares of TCPL. M-45 SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA(1) (millions of dollars except per share amounts) Fourth Third Second First 2004 Revenues 1,394 1,224 1,256 1,233 Net income applicable to common shares Continuing operations 184 192 388 214 Discontinued operations - 52 - - 184 244 388 214 SHARE STATISTICS Net income per share - Basic and Diluted Continuing operations $0.38 $0.40 $0.81 $0.44 Discontinued operations - 0.11 - - $0.38 $0.51 $0.81 $0.44 Fourth Third Second First 2003 Revenues 1,319 1,391 1,311 1,336 Net income applicable to common shares Continuing operations 193 198 202 208 Discontinued operations - 50 - - 193 248 202 208 SHARE STATISTICS Net income per share - Basic and Diluted Continuing operations $0.40 $0.41 $0.42 $0.43 Discontinued operations - 0.11 - - $0.40 $0.52 $0.42 $0.43 (1) The selected quarterly consolidated financial data has been prepared in accordance with Canadian GAAP. Certain comparative figures have been reclassified to conform with the current year's presentation. For a discussion on the factors affecting the comparability of the financial data, including discontinued operations, refer to Note 1 and Note 22 of TCPL's 2004 audited consolidated financial statements. Factors Impacting Quarterly Financial Information In the Gas Transmission business, which consists primarily of the company's investments in regulated pipelines, annual revenues and net earnings fluctuate over the long term based on regulators' decisions and negotiated settlements with shippers. Generally, quarter over quarter revenues and earnings during any particular fiscal year remain fairly stable with fluctuations arising as a result of adjustments being recorded due to regulatory decisions and negotiated settlements with shippers and due to items outside of the normal course of operations. In the Power business, which consists primarily of the company's investments in electrical power generation plants, quarter over quarter revenues and net earnings are affected by seasonal weather conditions, customer demand, market prices, planned and unplanned plant outages as well as items outside of the normal course of operations. Significant items which impacted 2004 and 2003 quarterly net earnings are as follows. * In first quarter 2003, TCPL completed the acquisition of a 31.6 per cent interest in Bruce Power, resulting in increased equity income in the Power business from thereon. * Second quarter 2003 net earnings included a $19 million positive after-tax earnings impact of a June 2003 settlement with a former counterparty that had previously defaulted under power forward contracts. M-46 * Third quarter 2003 net earnings included TCPL's $11 million share of a positive future income tax benefit adjustment recognized by TransGas. * First quarter 2004 net earnings included approximately $12 million of income tax refunds and related interest. * Second quarter 2004 net earnings included gains related to Power LP of $187 million, of which $132 million were previously deferred and were being amortized into income to 2017. * In third quarter 2004, the EUB's decisions on the GCOC and Phase I of the 2004 GRA resulted in lower earnings for the Alberta System compared to the previous quarters. In addition, third quarter 2004 included a $12 million after-tax adjustment related to the release of previously established restructuring provisions and recognition of $8 million of non-capital loss carryforwards. * In fourth quarter 2004, TCPL completed the acquisition of GTN, thereby recording $14 million of earnings from the November 1, 2004 acquisition date. Power recorded a $16 million pre-tax positive impact of a restructuring transaction related to power purchase contracts between OSP and Boston Edison in Eastern Operations. Fourth Quarter 2004 Highlights SEGMENT RESULTS-AT-A-GLANCE Three months ended December 31 (millions of dollars) 2004 2003 Gas Transmission 157 160 Power 31 44 Corporate (4 ) (11 ) Net Income Applicable to Common Shares 184 193 Net income applicable to common shares and net earnings for fourth quarter 2004 for TCPL were $184 million compared to $193 million for the same period in 2003. This decrease was primarily due to lower net earnings from the Power and Gas Transmission businesses, partially offset by lower net expenses in the Corporate segment. Power's net earnings in fourth quarter 2004 of $31 million decreased $13 million compared to $44 million in fourth quarter 2003 primarily due to lower earnings from Western Operations and Eastern Operations. Operating and other income from Western Operations in fourth quarter 2004 of $25 million was $6 million lower compared to the $31 million earned in the same period in 2003. The decrease was mainly due to a reduction in income from ManChief following the sale of the plant to Power LP in April 2004, cumulative operating cost adjustments settled in fourth quarter 2004 at the MacKay River cogeneration plant and reduced margins resulting from lower market heat rates on uncontracted volumes. Operating and other income from Eastern Operations in fourth quarter 2004 of $31 million was $5 million lower compared to $36 million earned in the same period in 2003. The decrease was primarily due to a reduction in income as a result of the sale of the Curtis Palmer hydroelectric facilities to Power LP in April 2004, the unfavourable impact of higher natural gas fuel costs at OSP, earnings recorded in 2003 on the Cobourg temporary generation facility and a weaker U.S. dollar in 2004 compared to 2003. Partially offsetting these reductions was a $16 million pre-tax positive impact of a restructuring transaction related to power purchase contracts between OSP and Boston Edison. In fourth quarter 2004, TCPL closed a transaction with Boston Edison resulting in TCPL assuming a 23.5 per cent share of the OSP power purchase contracts and recognized earnings from the effective date of April 1, 2004. For fourth quarter 2004, Gas Transmission's net earnings were $157 million compared to $160 million in fourth quarter 2003. The $3 million decrease was due to a $5 million reduction in earnings from Wholly-Owned Pipelines, partially offset by a $2 million increase in net earnings from the Other Gas Transmission businesses. The reduction in earnings from Wholly-Owned Pipelines was primarily due to a decline in the Canadian Mainline and the Alberta System net earnings. Regulatory decisions in 2004, as well as lower returns and investment bases, resulted in lower earnings for the Canadian Mainline and the Alberta System. These decreases were partially offset by net earnings of $14 million during the quarter from TCPL's investment in GTN which was acquired in November 2004. The increase in earnings from Other M-47 Gas Transmission was primarily due to higher earnings from CrossAlta as a result of favourable gas market storage conditions as well as higher earnings from Ventures LP. These increases were partially offset by the impact of a weaker U.S. dollar. Net expenses, after tax, in the Corporate segment for the quarter ended December 31, 2004 were $4 million compared to $11 million for the corresponding period in 2003. The $7 million decrease in Corporate net expenses for the three months ended December 31, 2004 compared to the same period in 2003 was primarily due to the positive impacts of income tax and foreign exchange related items. SHARE INFORMATION As at March 1, 2005, TCPL had 480,668,109 issued and oustanding common shares and there were no outstanding options to purchase common shares. OTHER INFORMATION Additional information relating to TCPL, including the company's Annual Information Form and continuous disclosure documents, is posted on SEDAR at www.sedar.com under TransCanada PipeLines Limited. Other selected consolidated financial information for the years ended December 31, 2004, 2003, 2002, 2001, and 2000 is found under the heading "Five-Year Financial Highlights" on pages F-48 and F-49 of this report. FORWARD-LOOKING INFORMATION Certain information in this Management's Discussion and Analysis is forward-looking and is subject to important risks and uncertainties. The results or events predicted in this information may differ from actual results or events. Factors which could cause actual results or events to differ materially from current expectations include, among other things, the ability of TCPL to successfully implement its strategic initiatives and whether such strategic initiatives will yield the expected benefits, the availability and price of energy commodities, regulatory decisions, competitive factors in the pipeline and power industry sectors and the prevailing economic conditions in North America. For additional information on these and other factors, see the reports filed by TCPL with Canadian securities regulators and with the SEC. TCPL disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. M-48 GLOSSARY OF TERMS 2004 Application 2004 Canadian Mainline Tolls and Tariff Application APG Aboriginal Pipeline Group ATCO ATCO Pipelines B.C. British Columbia Bcf/d Billion cubic feet per day Boston Edison Boston Edison Company Bruce Power Bruce Power L.P. Cameco Cameco Corporation CAPP Canadian Association of Petroleum Producers Cartier Wind Cartier Wind Energy CBM Coalbed methane CICA Canadian Institute of Chartered Accountants CrossAlta CrossAlta Gas Storage & Services Ltd. DBRS Dominion Bond Rating Service Limited Disclosure controls Disclosure controls and procedures EUB Alberta Energy and Utilities Board FCA Federal Court of Appeal FERC U. S. Federal Energy Regulatory Commission Foothills Foothills Pipe Lines Ltd. FT Firm transportation FT-NR Non-renewable firm transportation FT-RAM Firm transportation service enhancement GAAP Generally accepted accounting principles Gas Pacifico Gasoducto del Pacifico GCOC Generic Cost of Capital GRA General Rate Application Great Lakes Great Lakes Gas Transmission System GTN Gas Transmission Northwest System and the North Baja System, collectively GUA Gas Utilities Act (Alberta) GWh Gigawatt hours Hydro-Quebec Hydro-Quebec Distribution INNERGY INNERGY Holdings S.A. Iroquois Iroquois Gas Transmission System Keystone Keystone Pipeline Km Kilometres LNG Liquefied natural gas Millennium Millennium Pipeline project MMcf/d Million cubic feet per day Moody's Moody's Investors Service MW Megawatts MWh Megawatt hour NBJ North Bay Junction NEB National Energy Board Net earnings Net income from continuing operations Northern Border Northern Border Pipeline NPA Northern Pipeline Act of Canada OM&A Operating, maintenance and administration OPG Ontario Power Generation OSP Ocean State Power Paiton P.T. Paiton Energy Company Portland Portland Natural Gas Transmission System Portlands Energy Portlands Energy Centre L.P. Power LP TransCanada Power, L.P. PPAs Power purchase arrangements M-49 ROE Rate of return on common equity SEC U.S. Securities and Exchange Commission Shell Shell US Gas & Power LLC Simmons Simmons Pipeline System TCPL or the company TransCanada PipeLines Limited TCPM TransCanada Power Marketing Limited The Consortium The consortium that includes Cameco and BPC Generation Infrastructure Trust TQM Trans Quebec & Maritimes System TransCanada TransCanada Corporation TransGas TransGas de Occidente S.A. Tuscarora Tuscarora Gas Transmission System U.S. United States USGen USGen New England Ventures LP TransCanada Pipeline Ventures Limited Partnership Vermont Hydroelectric Vermont Hydroelectric Power Authority WCSB Western Canada Sedimentary Basin M-50 TransCanada PipeLines Limited Consolidated Financial Statements December 31, 2004 F-1 REPORT OF MANAGEMENT The consolidated financial statements included in this report are the responsibility of Management and have been approved by the Board of Directors of the Company. These consolidated financial statements have been prepared by Management in accordance with generally accepted accounting principles (GAAP) in Canada and include amounts that are based on estimates and judgments. Financial information contained elsewhere in this report is consistent with the consolidated financial statements. Management has prepared Management's Discussion and Analysis which is based on the Company's financial results prepared in accordance with Canadian GAAP. It compares the Company's financial performance in 2004 to 2003 and should be read in conjunction with the consolidated financial statements and accompanying notes. In addition, significant changes between 2003 and 2002 are highlighted. Note 23 to the consolidated financial statements describes the impact on the consolidated financial statements of significant differences between Canadian and United States GAAP. Management has developed and maintains a system of internal accounting controls, including a program of internal audits. Management believes that these controls provide reasonable assurance that financial records are reliable and form a proper basis for preparation of financial statements. The internal accounting control process includes Management's communication to employees of policies which govern ethical business conduct. The Board of Directors has appointed an Audit Committee consisting of unrelated, non-management directors which meets at least five times during the year with Management and independently with each of the internal and external auditors and as a group to review any significant accounting, internal control and auditing matters. The Audit Committee reviews the consolidated financial statements before the consolidated financial statements are submitted to the Board of Directors for approval. The internal and external auditors have free access to the Audit Committee without obtaining prior Management approval. With respect to the external auditors, KPMG LLP, the Audit Committee approves the terms of engagement and reviews the annual audit plan, the Auditors' Report and results of the audit. It also recommends to the Board of Directors the firm of external auditors to be appointed by the shareholders. The independent external auditors, KPMG LLP, have been appointed by the shareholders to express an opinion as to whether the consolidated financial statements present fairly, in all material respects, the Company's financial position, results of operations and cash flows in accordance with Canadian GAAP. The report of KPMG LLP on page F-3 outlines the scope of their examination and their opinion on the consolidated financial statements. Harold N. Kvisle Russell K. Girling President and Executive Vice-President, Corporate Chief Executive Officer Development and Chief Financial Officer February 28, 2005 F-2 AUDITORS' REPORT To the Shareholder of TransCanada PipeLines Limited We have audited the consolidated balance sheets of TransCanada PipeLines Limited as at December 31, 2004 and 2003 and the statements of consolidated income, consolidated retained earnings and consolidated cash flows for each of the years in the three-year period ended December 31, 2004. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 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. Chartered Accountants Calgary, Canada February 28, 2005 F-3 TRANSCANADA PIPELINES LIMITED CONSOLIDATED INCOME Year ended December 31 (millions of dollars) 2004 2003 2002 Revenues 5,107 5,357 5,214 Operating Expenses Cost of sales 539 692 627 Other costs and expenses 1,635 1,682 1,546 Depreciation 945 914 848 3,119 3,288 3,021 Operating Income 1,988 2,069 2,193 Other Expenses/(Income) Financial charges (Note 9) 812 821 867 Financial charges of joint ventures 60 77 90 Equity income (Note 7) (171 ) (165 ) (33 ) Interest income and other (65 ) (60 ) (53 ) Gains related to Power LP (Note 8) (197 ) - - 439 673 871 Income from Continuing Operations before Income Taxes and 1,549 1,396 1,322 Non- Controlling Interests Income Taxes (Note 16) Current 431 305 270 Future 77 230 247 508 535 517 Non-Controlling Interests 10 2 - Net Income from Continuing Operations 1,031 859 805 Net Income from Discontinued Operations (Note 22) 52 50 - Net Income 1,083 909 805 Preferred Securities Charges 31 36 36 Preferred Share Dividends 22 22 22 Net Income Applicable to Common Shares 1,030 851 747 Net Income Applicable to Common Shares Continuing operations 978 801 747 Discontinued operations 52 50 - 1,030 851 747 The accompanying notes to the consolidated financial statements are an integral part of these statements. F-4 TRANSCANADA PIPELINES LIMITED CONSOLIDATED CASH FLOWS Year ended December 31 (millions of dollars) 2004 2003 2002 Cash Generated from Operations Net income from continuing operations 1,031 859 805 Depreciation 945 914 848 Future income taxes 77 230 247 Gains related to Power LP (197 ) - - Equity income in excess of distributions received (Note 7) (123 ) (119 ) (6 ) Pension funding in excess of expense (29 ) (65 ) (33 ) Other (32 ) (9 ) (34 ) Funds generated from continuing operations 1,672 1,810 1,827 Decrease in operating working capital (Note 20) 33 112 33 Net cash provided by continuing operations 1,705 1,922 1,860 Net cash (used in)/provided by discontinued operations (6 ) (17 ) 59 1,699 1,905 1,919 Investing Activities Capital expenditures (476 ) (391 ) (599 ) Acquisitions, net of cash acquired (Note 8) (1,516 ) (570 ) (228 ) Disposition of assets (Note 8) 410 - - Deferred amounts and other (24 ) (138 ) (112 ) Net cash used in investing activities (1,606 ) (1,099 ) (939 ) Financing Activities Dividends and preferred securities charges (623 ) (588 ) (546 ) Advances from parent 35 46 - Notes payable issued/(repaid), net 179 (62 ) (46 ) Long-term debt issued 1,042 930 - Reduction of long-term debt (997 ) (744 ) (486 ) Non-recourse debt of joint ventures issued 233 60 44 Reduction of non-recourse debt of joint ventures (113 ) (71 ) (80 ) Partnership units of joint ventures issued 88 - - Common shares issued - 18 50 Redemption of junior subordinated debentures - (218 ) - Net cash used in financing activities (156 ) (629 ) (1,064 ) Effect of Foreign Exchange Rate Changes on Cash and Short-Term Investments (87 ) (52 ) (3 ) (Decrease)/Increase in Cash and Short-Term Investments (150 ) 125 (87 ) Cash and Short-Term Investments Beginning of year 337 212 299 Cash and Short-Term Investments End of year 187 337 212 The accompanying notes to the consolidated financial statements are an integral part of these statements. F-5 TRANSCANADA PIPELINES LIMITED CONSOLIDATED BALANCE SHEET December 31 (millions of dollars) 2004 2003 ASSETS Current Assets Cash and short-term investments 187 337 Accounts receivable 627 603 Inventories 174 165 Other 120 88 1,108 1,193 Long-Term Investments (Note 7) 840 733 Plant, Property and Equipment (Notes 4, 9 and 10) 18,704 17,415 Other Assets (Note 5) 1,477 1,357 22,129 20,698 LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities Notes payable (Note 17) 546 367 Accounts payable 1,215 1,131 Accrued interest 214 208 Current portion of long-term debt (Note 9) 766 550 Current portion of non-recourse debt of joint ventures (Note 10) 83 19 2,824 2,275 Deferred Amounts (Note 11) 666 561 Long-Term Debt (Note 9) 9,713 9,465 Future Income Taxes (Note 16) 509 427 Non-Recourse Debt of Joint Ventures (Note 10) 779 761 Preferred Securities (Note 12) 19 22 14,510 13,511 Non-Controlling Interests 76 82 Shareholders' Equity Preferred securities (Note 12) 670 672 Preferred shares (Note 13) 389 389 Common shares (Note 14) 4,632 4,632 Contributed surplus 270 267 Retained earnings 1,653 1,185 Foreign exchange adjustment (Note 15) (71 ) (40 ) 7,543 7,105 Commitments, Contingencies and Guarantees (Note 21) 22,129 20,698 The accompanying notes to the consolidated financial statements are an integral part of these statements. On behalf of the Board: Harold N. Kvisle Harry G. Schaefer Director Director F-6 TRANSCANADA PIPELINES LIMITED CONSOLIDATED RETAINED EARNINGS Year ended December 31 (millions of dollars) 2004 2003 2002 Balance at beginning of year 1,185 854 586 Net income 1,083 909 805 Preferred securities charges (31 ) (36 ) (36 ) Preferred share dividends (22 ) (22 ) (22 ) Common share dividends (562 ) (520 ) (479 ) 1,653 1,185 854 The accompanying notes to the consolidated financial statements are an integral part of these statements. F-7 TRANSCANADA PIPELINES LIMITED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS TransCanada PipeLines Limited (the Company or TCPL) is a leading North American energy company. TCPL operates in two business segments, Gas Transmission and Power, each of which offers different products and services. Gas Transmission The Gas Transmission segment owns and operates the following natural gas pipelines: * a natural gas transmission system extending from the Alberta border east into Quebec (the Canadian Mainline); * a natural gas transmission system in Alberta (the Alberta System); * a natural gas transmission system extending from the British Columbia/ Idaho border to the Oregon/California border, traversing Idaho, Washington and Oregon (the Gas Transmission Northwest System); * a natural gas transmission system extending from central Alberta to the B.C., Saskatchewan and the United States borders (the Foothills System); * a natural gas transmission system extending from the Alberta border west into southeastern B.C. (the BC System); * a natural gas transmission system extending from a point near Ehrenberg, Arizona to the Baja California, Mexico/California border (the North Baja System); and * natural gas transmission systems in Alberta which supply natural gas to the oil sands region of northern Alberta and to a petrochemical complex at Joffre, Alberta (Ventures LP). Gas Transmission also holds the Company's investments in other natural gas pipelines and natural gas storage facilities located primarily in Canada and the U.S. In addition, Gas Transmission investigates and develops new natural gas transmission, natural gas storage and liquefied natural gas regasification facilities in Canada and the U.S. Power The Power segment builds, owns and operates electrical power generation plants, and markets electricity. Power also holds the Company's investments in other electrical power generation plants. This business operates in Canada and the U.S. NOTE 1 ACCOUNTING POLICIES The consolidated financial statements of the Company have been prepared by Management in accordance with Canadian generally accepted accounting principles (GAAP). These accounting principles are different in some respects from U.S. GAAP and the significant differences are described in Note 23. Amounts are stated in Canadian dollars unless otherwise indicated. Certain 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 Pursuant to a plan of arrangement, effective May 15, 2003, common shares of TCPL were exchanged on a one-to-one basis for common shares of TransCanada Corporation (TransCanada). As a result, TCPL became a wholly-owned subsidiary of TransCanada. The consolidated financial statements include the accounts of TCPL, the consolidated accounts of all subsidiaries and TCPL's proportionate share of the accounts of the Company's joint venture investments. F-8 On November 1, 2004, the Company acquired a 100 per cent interest in the Gas Transmission Northwest System and the North Baja System (collectively GTN) and, as a result, GTN was consolidated subsequent to that date. In December 2003, TCPL increased its ownership interest in Portland Natural Gas Transmission System Partnership (Portland) to 61.7 per cent from 43.4 per cent. Subsequent to the acquisition, Portland was consolidated in the Company's financial statements with 38.3 per cent reflected in non-controlling interests. In August 2003, the Company acquired the remaining interests in Foothills Pipe Lines Ltd. and its subsidiaries (Foothills) previously not held by TCPL, and Foothills was consolidated subsequent to that date. TCPL uses the equity method of accounting for investments over which the Company is able to exercise significant influence. Regulation The Canadian Mainline, the BC System, the Foothills System, and Trans Quebec & Maritimes Pipeline Inc. (Trans Quebec & Maritimes) are subject to the authority of the National Energy Board (NEB) and the Alberta System is regulated by the Alberta Energy and Utilities Board (EUB). These Canadian natural gas transmission operations are regulated with respect to the determination of revenues, tolls, construction and operations. The NEB approved interim tolls for 2004 for the Canadian Mainline. The tolls will remain interim pending a decision on Phase II of the 2004 Tolls and Tariff Application, which will address capital structure, for the Canadian Mainline. Any adjustments to the interim tolls will be recorded in accordance with the NEB decision. The Gas Transmission Northwest System, the North Baja System and the other natural gas pipelines in the U.S. are subject to the authority of the Federal Energy Regulatory Commission (FERC). In order to appropriately reflect the economic impact of the regulators' decisions regarding the Company's revenues and tolls, and to thereby achieve a proper matching of revenues and expenses, the timing of recognition of certain revenues and expenses in these regulated businesses may differ from that otherwise expected under GAAP. Cash and Short-Term Investments The Company's short-term investments with original maturities of three months or less are considered to be cash equivalents and are recorded at cost, which approximates market value. Inventories Inventories are carried at the lower of average cost or net realizable value and primarily consist of materials and supplies including spare parts and storage gas. Plant, Property and Equipment Gas Transmission Plant, property and equipment of natural gas transmission operations are carried at cost. Depreciation is calculated on a straight-line basis. Pipeline and compression equipment are depreciated at annual rates ranging from two to six per cent and metering and other plant are depreciated at various rates. 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 Plant, property and equipment in the Power business are recorded at cost and depreciated on a straight-line basis over estimated service lives at average annual rates generally ranging from two to four per cent. The cost of major overhauls of equipment is capitalized and depreciated over the estimated service lives. Interest is capitalized on capital projects. F-9 Corporate Corporate 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 three to 20 per cent. Power Purchase Arrangements Power purchase arrangements (PPAs) are long-term contracts to purchase or sell power on a predetermined basis. The initial payments for PPAs acquired by TCPL are deferred and amortized over the terms of the contracts, from the dates of acquisition, which range from eight to 23 years. Certain PPAs under which TCPL sells power are accounted for as operating leases and, accordingly, the related plant, property and equipment are accounted for as assets under operating leases. Income Taxes 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. As permitted by Canadian GAAP, 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 as the Company does not intend to repatriate these earnings in the foreseeable future. Foreign Currency Translation Most of the Company's foreign operations are self-sustaining and are translated into Canadian dollars using the current rate method. Under this method, assets and liabilities are translated at period end exchange rates and items included in the statements of consolidated income, consolidated retained earnings and consolidated cash flows are translated at the exchange rates in effect at the time of the transaction. Translation adjustments are reflected in the foreign exchange adjustment in Shareholders' Equity. Certain foreign operations included in TCPL's investment in TransCanada Power, L.P. (Power LP) are integrated and are translated into Canadian dollars using the temporal method. Under this method, monetary assets and liabilities are translated at period end exchange rates, non-monetary assets and liabilities are translated at historical exchange rates, revenues and expenses are translated at the exchange rate in effect at the time of the transaction and depreciation of assets translated at historical rates is translated at the same rate as the asset to which it relates. Gains and losses on translation are reflected in income when incurred. Exchange gains or losses on the principal amounts of foreign currency debt and preferred securities related to the Alberta System and the Canadian Mainline are deferred until they are recovered in tolls. Derivative Financial Instruments The Company utilizes derivative and other financial instruments to manage its exposure to changes in foreign currency exchange rates, interest rates and energy commodity prices. Gains or losses relating to derivatives that are hedges are F-10 deferred and recognized in the same period and in the same financial statement category as the corresponding hedged transactions. The recognition of gains and losses on derivatives used as hedges for Canadian Mainline, Alberta System, GTN and the Foothills System 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 changes in the fair value of the derivative substantially offset changes in the fair value attributable to the hedged item. In the event that a derivative does not meet the designation or effectiveness criterion, the derivative is accounted for at fair value and realized and unrealized gains and losses on the derivative are 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 corresponding 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. Employee Benefit and Other Plans The Company sponsors defined benefit pension plans (DB 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 based on a five-year moving average value for all plan assets. 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. When the restructuring of a benefit plan gives rise to both a curtailment and a settlement, the curtailment is accounted for prior to the settlement. The Company previously sponsored two additional plans, a defined contribution plan and a combination of the defined benefit and defined contribution plans, which were effectively terminated at December 31, 2002. NOTE 2 ACCOUNTING CHANGES Asset Retirement Obligations Effective January 1, 2004, the Company adopted the new standard of the Canadian Institute of Chartered Accountants (CICA) Handbook Section "Asset Retirement Obligations", which addresses financial accounting and reporting for obligations associated with asset retirement costs. This section requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset. The liability is accreted at the end of each period through charges to operating expenses. This accounting change was applied retroactively with restatement of prior periods. The plant, property and equipment of the regulated natural gas transmission operations consists primarily of underground pipelines and above ground compression equipment and other facilities. No amount has been recorded for asset retirement obligations relating to these assets as it is not possible to make a reasonable estimate of the fair value of the liability due to the indeterminate timing and scope of the asset retirements. Management believes it is reasonable to assume that all retirement costs associated with the regulated pipelines will be recovered through tolls in future periods. For Gas Transmission, excluding regulated natural gas transmission operations, the impact of this accounting change resulted in an increase of $2 million in plant, property and equipment and in the estimated fair value of the liability as at January 1, 2003 and December 31, 2003. F-11 The plant, property and equipment in the Power business consists primarily of power plants in Canada and the U.S. The impact of this accounting change resulted in an increase of $6 million and $7 million in plant, property and equipment and in the estimated fair value of the liability as at January 1, 2003 and December 31, 2003, respectively. The asset retirement cost, net of accumulated depreciation that would have been recorded if the cost had been recorded in the period in which it arose, is recorded as an additional cost of the assets as at January 1, 2003. The impact of this change on TCPL's net income in prior years was nil. The impact of this accounting change on the Company's financial statements as at and for the year ended December 31, 2004 is disclosed in Note 18. Hedging Relationships Effective January 1, 2004, the Company adopted the provisions of the CICA's new Accounting Guideline "Hedging Relationships" that specifies the circumstances in which hedge accounting is appropriate, including the identification, documentation, designation and effectiveness of hedges, and the discontinuance of hedge accounting. The adoption of the new guideline, which TCPL applied prospectively, had no significant impact on net income for the year ended December 31, 2004. Generally Accepted Accounting Principles Effective January 1, 2004, the Company adopted the new standard of the CICA Handbook Section "Generally Accepted Accounting Principles" that defines primary sources of GAAP and the other sources that need to be considered in the application of GAAP. The new standard eliminates the ability to rely on industry practice to support a particular accounting policy and provides an exemption for rate-regulated operations. This accounting change was applied prospectively and there was no impact on net income in the year ended December 31, 2004. In prior years, in accordance with industry practice, certain assets and liabilities related to the Company's regulated activities, and offsetting deferral accounts, were not recognized on the balance sheet. The impact of the change on the consolidated balance sheet as at January 1, 2004 is as follows. (millions of dollars) Increase/ (Decrease) Other assets 153 Deferred amounts 80 Long-term debt 76 Preferred securities (3 ) Total liabilities 153 F-12 NOTE 3 SEGMENTED INFORMATION NET INCOME/(LOSS)(1) Year ended December 31, 2004 (millions of Gas Power Corporate Total dollars) Transmission Revenues 3,917 1,190 - 5,107 Cost of sales(2) - (539 ) - (539 ) Other costs and expenses (1,225 ) (407 ) (3 ) (1,635 ) Depreciation (873 ) (72 ) - (945 ) Operating income/(loss) 1,819 172 (3 ) 1,988 Financial and preferred equity charges (785 ) (9 ) (81 ) (875 ) and non-controlling interests Financial charges of joint ventures (56 ) (4 ) - (60 ) Equity income 41 130 - 171 Interest income and other 14 14 37 65 Gains related to Power LP - 197 - 197 Income taxes (447 ) (104 ) 43 (508 ) Continuing operations 586 396 (4 ) 978 Discontinued operations 52 Net Income Applicable to Common Shares 1,030 Year ended December 31, 2003 (millions of dollars) Revenues 3,956 1,401 - 5,357 Cost of sales(2) - (692 ) - (692 ) Other costs and expenses (1,270 ) (405 ) (7 ) (1,682 ) Depreciation (831 ) (82 ) (1 ) (914 ) Operating income/(loss) 1,855 222 (8 ) 2,069 Financial and preferred equity charges (781 ) (11 ) (89 ) (881 ) and non-controlling interests Financial charges of joint ventures (76 ) (1 ) - (77 ) Equity income 66 99 - 165 Interest income and other 17 14 29 60 Income taxes (459 ) (103 ) 27 (535 ) Continuing operations 622 220 (41 ) 801 Discontinued operations 50 Net Income Applicable to Common Shares 851 F-13 Year ended December 31, 2002 (millions of Gas Power Corporate Total dollars) Transmission Revenues 3,921 1,293 - 5,214 Cost of sales(2) - (627 ) - (627 ) Other costs and expenses (1,166 ) (371 ) (9 ) (1,546 ) Depreciation (783 ) (65 ) - (848 ) Operating income/(loss) 1,972 230 (9 ) 2,193 Financial and preferred equity charges (821 ) (13 ) (91 ) (925 ) and non-controlling interests Financial charges of joint ventures (90 ) - - (90 ) Equity income 33 - - 33 Interest income and other 17 13 23 53 Income taxes (458 ) (84 ) 25 (517 ) Continuing operations 653 146 (52 ) 747 Discontinued operations - Net Income Applicable to Common Shares 747 (1) In determining the net income of each segment, certain expenses such as indirect financial charges and related income taxes are not allocated to business segments. (2) Cost of sales is comprised of commodity purchases for resale. TOTAL ASSETS December 31 (millions of dollars) 2004 2003 Gas Transmission 18,428 17,064 Power 2,802 2,753 Corporate 892 870 Continuing operations 22,122 20,687 Discontinued operations 7 11 22,129 20,698 GEOGRAPHIC INFORMATION Year ended December 31 (millions of dollars) 2004 2003 2002(4) Revenues(3) Canada - domestic 3,147 3,257 2,731 Canada - export 1,261 1,293 1,641 United States 699 807 842 5,107 5,357 5,214 (3) Revenues are attributed to countries based on country of origin of product or service. (4) Canada - domestic revenues were reduced in 2002 as a result of transportation service credits of $662 million. These services were discontinued in 2003. F-14 PLANT, PROPERTY AND EQUIPMENT December 31 (millions of dollars) 2004 2003 Canada 14,757 15,156 United States 3,947 2,259 18,704 17,415 CAPITAL EXPENDITURES Year ended December 31 (millions of dollars) 2004 2003 2002 Gas Transmission 187 256 382 Power 285 132 193 Corporate and Other 4 3 24 476 391 599 F-15 NOTE 4 PLANT, PROPERTY AND EQUIPMENT December 31 2004 2003 (millions of dollars) Cost Accumulated Net Book Cost Accumulated Net Book Depreciation Value Depreciation Value Gas Transmission Canadian Mainline Pipeline 8,695 3,421 5,274 8,683 3,176 5,507 Compression 3,322 947 2,375 3,318 832 2,486 Metering and other 366 125 241 404 132 272 12,383 4,493 7,890 12,405 4,140 8,265 Under construction 16 - 16 12 - 12 12,399 4,493 7,906 12,417 4,140 8,277 Alberta System Pipeline 4,978 2,055 2,923 4,934 1,908 3,026 Compression 1,496 599 897 1,507 549 958 Metering and other 861 262 599 862 211 651 7,335 2,916 4,419 7,303 2,668 4,635 Under construction 20 - 20 13 - 13 7,355 2,916 4,439 7,316 2,668 4,648 GTN(1) Pipeline 1,131 9 1,122 Compression 726 2 724 Metering and other 187 1 186 2,044 12 2,032 Under construction 17 - 17 2,061 12 2,049 Foothills System Pipeline 815 346 469 834 317 517 Compression 373 114 259 378 99 279 Metering and other 78 35 43 60 35 25 1,266 495 771 1,272 451 821 Joint Ventures and 3,213 1,053 2,160 3,361 1,052 2,309 other 26,294 8,969 17,325 24,366 8,311 16,055 Power(2) Power generation 1,397 375 1,022 1,439 381 1,058 facilities Other 77 45 32 84 41 43 1,474 420 1,054 1,523 422 1,101 Under construction 288 - 288 209 - 209 1,762 420 1,342 1,732 422 1,310 Corporate 124 87 37 122 72 50 28,180 9,476 18,704 26,220 8,805 17,415 (1) TCPL acquired GTN on November 1, 2004. (2) Certain Power generation facilities are accounted for as assets under operating leases. At December 31, 2004, the net book value of these facilities was $70 million. Revenues of $7 million were attributed to the PPAs of these facilities in 2004. F-16 NOTE 5 OTHER ASSETS December 31 (millions of dollars) 2004 2003 Derivative contracts 253 118 PPAs - Canada(1) 274 278 PPAs - U.S.(1) 98 248 Pension and other benefit plans 209 201 Regulatory deferrals 199 212 Loans and advances(2) 135 111 Goodwill 58 - Other 251 189 1,477 1,357 (1) The following amounts related to the PPAs are included in the consolidated financial statements. December 31 2004 2003 (millions of dollars) Cost Accumulated Net Cost Accumulated Net Amortization Book Amortization Book Value Value PPAs - Canada 345 71 274 329 51 278 PPAs - U.S. 102 4 98 276 28 248 The aggregate amortization expense with respect to the PPAs was $24 million for the year ended December 31, 2004 (2003 - $37 million; 2002 - $28 million). The amortization expense with respect to the Company's PPAs approximate: 2005 - $26 million; 2006 - $26 million; 2007 - $26 million; 2008 - $26 million; and 2009 - $26 million. In April 2004, the Company disposed of all its PPAs - U.S. to Power LP and, as a result of its joint venture investment in Power LP, recorded US$74 million of PPAs - U.S. In 2004, TransCanada also recorded $16 million of PPAs - Canada. (2) Includes a $75 million unsecured note receivable from Bruce Power L.P. (Bruce Power) bearing interest at 10.5 per cent per annum, due February 14, 2008. NOTE 6 JOINT VENTURE INVESTMENTS TCPL's Proportionate Share Income Before Income Taxes Net Assets Year ended December 31 December 31 (millions of dollars) Ownership 2004 2003 2002 2004 2003 Interest Gas Transmission Great Lakes 50.0% (1) 86 81 102 379 419 Iroquois 41.0% (1) 28 31 30 175 169 TC PipeLines, LP 33.4% 22 21 24 124 130 Trans Quebec & Maritimes 50.0% 13 14 13 75 77 CrossAlta 60.0% (1) 20 11 21 24 25 Foothills (2) - 19 29 - - Other Various 6 7 7 27 22 Power Power LP 30.6% (3) 32 25 26 289 234 ASTC Power Partnership 50.0% (4) - - - 93 99 207 209 252 1,186 1,175 (1) Great Lakes Gas Transmission Limited Partnership (Great Lakes); Iroquois Gas Transmission System, L.P. (Iroquois); CrossAlta Gas Storage & Services Ltd. (CrossAlta). (2) In August 2003, the Company acquired the remaining interests in Foothills previously not held by TCPL, and Foothills was consolidated subsequent to that date. F-17 (3) In April 2004, the Company's interest in Power LP decreased to 30.6 per cent from 35.6 per cent. (4) The Company has a 50.0 per cent ownership interest in ASTC Power Partnership, which is located in Alberta and holds a PPA. The underlying power volumes related to the 50.0 per cent ownership interest in the Partnership are effectively transferred to TCPL. Consolidated retained earnings at December 31, 2004 include undistributed earnings from these joint ventures of $509 million (2003 - $509 million). Summarized Financial Information of Joint Ventures Year ended December 31 (millions of dollars) 2004 2003 2002 Income Revenues 559 623 680 Other costs and expenses (238 ) (275 ) (251 ) Depreciation (88 ) (96 ) (119 ) Financial charges and other (26 ) (43 ) (58 ) Proportionate share of income before income taxes of joint 207 209 252 ventures Year ended December 31 (millions of dollars) 2004 2003 2002 Cash Flows Operations 269 272 323 Investing activities (179 ) (114 ) (124 ) Financing activities (76 ) (156 ) (210 ) Effect of foreign exchange rate changes on cash and (5 ) (10 ) (1 ) short-term investments Proportionate share of increase/(decrease) in cash and 9 (8 ) (12 ) short-term investments of joint ventures December 31 (millions of dollars) 2004 2003 Balance Sheet Cash and short-term investments 64 55 Other current assets 133 106 Long-term investments 105 118 Plant, property and equipment 1,644 1,693 Other assets and deferred amounts (net) 221 109 Current liabilities (153 ) (94 ) Non-recourse debt (779 ) (761 ) Future income taxes (49 ) (51 ) Proportionate share of net assets of joint ventures 1,186 1,175 F-18 NOTE 7 LONG-TERM INVESTMENTS TCPL's Share Distributions from Income from Equity Equity Equity Investments Investments Investments Year ended December 31 Year ended December 31 December 31 (millions of Ownership 2004 2003 2002 2004 2003 2002 2004 2003 dollars) Interest Power Bruce Power 31.6% - - - 130 99 - 642 513 Gas Transmission Northern Border 10.0% (1) 27 22 26 23 22 25 91 103 TransGas de 46.5% 8 8 - 11 27 5 78 80 Occidente S.A. Portland 61.7% (2) - 10 - - 14 2 - - Other Various 13 6 1 7 3 1 29 37 48 46 27 171 165 33 840 733 (1) The Northern Border equity investment effective ownership interest of 10.0 per cent is the result of the Company holding a 33.4 per cent interest in TC PipeLines, LP, which holds a 30.0 per cent interest in Northern Border Pipeline Company (Northern Border). (2) In September 2003, the Company increased its ownership interest in Portland to 43.4 per cent from 33.3 per cent. In December 2003, the Company increased its ownership interest to 61.7 per cent and the investment was fully consolidated subsequent to that date. Consolidated retained earnings at December 31, 2004 include undistributed earnings from these equity investments of $285 million (2003 - $166 million). NOTE 8 ACQUISITIONS AND DISPOSITIONS Acquisitions GTN On November 1, 2004, TCPL acquired GTN for approximately US$1,730 million, including US$528 million of assumed debt and closing adjustments. The purchase price was allocated on a preliminary basis as follows using an estimate of fair values of the net assets at the date of acquisition. Purchase Price Allocation (millions of U.S. dollars) Current assets 45 Plant, property and equipment 1,712 Other non-current assets 30 Goodwill 48 Current liabilities (54 ) Long-term debt (528 ) Other non-current liabilities (51 ) 1,202 Goodwill, which is attributable to the North Baja System, will be re-evaluated on an annual basis for impairment. Factors that contributed to goodwill include opportunities for expansion, a strong competitive position, strong demand for gas F-19 in the western markets and access to an ample supply of relatively low-cost gas. The goodwill recognized on this transaction is expected to be fully deductible for tax purposes. The acquisition was accounted for using the purchase method of accounting. The financial results of GTN have been consolidated with those of TCPL subsequent to the acquisition date and included in the Gas Transmission segment. Bruce Power On February 14, 2003, the Company acquired a 31.6 per cent interest in Bruce Power for $409 million, including closing adjustments. As part of the acquisition, the Company also funded a one-third share ($75 million) of a $225 million accelerated deferred rent payment made by Bruce Power to Ontario Power Generation. The resulting note receivable from Bruce Power is recorded in other assets. The purchase price of the Company's 31.6 per cent interest in Bruce Power was allocated as follows. Purchase Price Allocation (millions of dollars) Net book value of assets acquired 281 Capital lease 301 Power sales agreements (131 ) Pension liability and other (42 ) 409 The amount allocated to the investment in Bruce Power includes a purchase price allocation of $301 million to the capital lease of the Bruce Power plant which is being amortized on a straight-line basis over the lease term which extends to 2018, resulting in an annual amortization expense of $19 million. The amount allocated to the power sales agreements is being amortized to income over the remaining term of the underlying sales contracts. The amortization of the fair value allocated to these contracts is: 2003 - $38 million; 2004 - $37 million; 2005 - $25 million; 2006 - $29 million; and 2007 - $2 million. Dispositions Power LP On April 30, 2004, TCPL sold the ManChief and Curtis Palmer power facilities to Power LP for US$402.6 million, plus closing adjustments of US$12.8 million, and recognized a gain of $25 million pre tax ($15 million after tax). Power LP funded the purchase through an issue of 8.1 million subscription receipts and third party debt. As part of the subscription receipts offering, TCPL purchased 540,000 subscription receipts for an aggregate purchase price of $20 million. The subscription receipts were subsequently converted into partnership units. The net impact of this issue reduced TCPL's ownership interest in Power LP to 30.6 per cent from 35.6 per cent. At a special meeting held on April 29, 2004, Power LP's unitholders approved an amendment to the terms of the Power LP Partnership Agreement to remove Power LP's obligation to redeem all units not owned by TCPL at June 30, 2017. TCPL was required to fund this redemption, thus the removal of Power LP's obligation eliminates this requirement. The removal of the obligation and the reduction in TCPL's ownership interest in Power LP resulted in a gain of $172 million. This amount includes the recognition of unamortized gains of $132 million on previous Power LP transactions. F-20 NOTE 9 LONG-TERM DEBT 2003 2004 Weighted Maturity Outstanding Weighted Outstanding Average Dates December 31 Average December 31 Interest (1) Interest (1) Rate(2) Rate(2) CANADIAN MAINLINE(3) First Mortgage Pipe Line Bonds Pounds Sterling (2004 and 2007 58 16.5% 58 16.5% 2003 - #25) Debentures Canadian dollars 2008 to 2020 1,354 10.9% 1,354 10.9% U.S. dollars (2004 - 2012 to 2021 722 9.5% 1,034 9.2% US$600; 2003 - US$800) Medium-Term Notes Canadian dollars 2005 to 2031 2,167 6.9% 2,312 6.9% U.S. dollars (2004 and 2003 2010 144 6.1% 155 6.1% - US$120) Foreign exchange differential - (60 ) recoverable through the tollmaking process(8) 4,445 4,853 ALBERTA SYSTEM(4) Debentures and Notes Canadian dollars 2007 to 2024 607 11.6% 627 11.6% U.S. dollars (2004 - 2012 to 2023 451 8.2% 646 8.3% US$375; 2003 - US$500) Medium-Term Notes Canadian dollars 2005 to 2030 767 7.4% 767 7.4% U.S. dollars (2004 and 2003 2026 to 2029 280 7.7% 301 7.7% - US$233) Foreign exchange differential - (16 ) recoverable through the tollmaking process(8) 2,105 2,325 GTN(5) Unsecured Debentures and Notes 2005 to 2025 632 7.2% - (2004 - US$525) FOOTHILLS SYSTEM(3) Senior Secured Notes - 80 4.3% Senior Unsecured Notes 2009 to 2014 400 4.9% 300 4.7% 400 380 PORTLAND(6) Senior Secured Notes U.S. dollars (2004 - 2018 308 5.9% 350 5.9% US$256; 2003 - US$271) OTHER Medium-Term Notes(3) Canadian dollars 2005 to 2030 592 6.2% 592 6.2% U.S. dollars (2004 - 2006 to 2025 627 6.9% 859 6.8% US$521; 2003 - US$665) Subordinated Debentures(3) U.S. dollars (2004 and 2003 2006 68 9.1% 74 9.1% - US$57) Unsecured Loans, Debentures and Notes(7) U.S. dollars (2004 - 2005 to 2034 1,302 5.1% 582 4.9% US$1,082; 2003 - US$446) 2,589 2,107 10,479 10,015 Less: Current Portion of 766 550 Long-Term Debt 9,713 9,465 (1) Amounts outstanding are stated in millions of Canadian dollars; amounts denominated in currencies other than Canadian dollars are stated in millions. (2) Weighted average interest rates are stated as at the respective outstanding dates. The effective weighted average interest rates resulting from swap agreements are as follows: Foothills senior unsecured notes in 2003 - 5.8 per cent; Portland senior secured notes in F-21 2003 - 6.2 per cent; Other U.S. dollar subordinated debentures - 9.0 per cent (2003 - 9.0 per cent); and Other U.S. dollar unsecured loans, debentures and notes - 5.2 per cent (2003 - 5.2 per cent). (3) Long-term debt of TCPL. (4) Long-term debt of NOVA Gas Transmission Ltd. excluding a $241 million note held by TCPL (2003 - $258 million). (5) Long-term debt of Gas Transmission Northwest Corporation. (6) Long-term debt of Portland. (7) Long-term debt of TCPL, excluding $85 million held by OSP Finance Company and $14 million held by TC Ocean State Corporation. (8) See Note 2, Accounting Changes - "Generally Accepted Accounting Principles". Principal Repayments Principal repayments on the long-term debt of the Company approximate: 2005 - $766 million; 2006 - $387 million; 2007 - $615 million; 2008 - $545 million; and 2009 - $753 million. Debt Shelf Programs At December 31, 2004, $1.5 billion of medium-term note debentures could be issued under a base shelf program in Canada and US$1 billion of debt securities could be issued under a debt shelf program in the U.S. In January 2005, the Company issued $300 million of 12-year medium-term notes bearing interest of 5.1 per cent under the Canadian base shelf program. CANADIAN MAINLINE First Mortgage Pipe Line Bonds The Deed of Trust and Mortgage securing the Company's First Mortgage Pipe Line Bonds limits the specific and floating charges to those assets comprising the present and future Canadian Mainline and TCPL's present and future gas transportation contracts. ALBERTA SYSTEM Debentures Debentures amounting to $225 million have retraction provisions which entitle the holders to require redemption of up to 8 per cent of the then outstanding principal plus accrued and unpaid interest on specified repayment dates. No redemptions have been made to December 31, 2004. Medium-Term Notes Medium-term notes amounting to $50 million have a provision entitling the holders to extend the maturity of the medium-term notes from the initial repayment date of 2007 to 2027. If extended, the interest rate would increase from 6.1 per cent to 7.0 per cent and the medium-term notes would become redeemable at the option of the Company. GAS TRANSMISSION NORTHWEST CORPORATION Senior Unsecured Notes Senior unsecured notes amounting to US$250 million are redeemable by the Company at any time on or after June 1, 2005. F-22 OTHER Medium-Term Notes Medium-term notes amounting to $150 million have retraction provisions which entitle the holders to require redemption of the principal plus accrued and unpaid interest in 2005. Financial Charges Year ended December 31 (millions of dollars) 2004 2003 2002 Interest on long-term debt 805 801 850 Regulatory deferrals and amortizations (31 ) (14 ) (17 ) Short-term interest and other financial charges 38 34 34 812 821 867 The Company made interest payments of $816 million for the year ended December 31, 2004 (2003 - $846 million; 2002 - $866 million). The Company capitalized $11 million of interest for the year ended December 31, 2004 (2003 - $9 million; 2002 - nil). NOTE 10 NON-RECOURSE DEBT OF JOINT VENTURES 2004 2003 Maturity Outstanding Weighted Outstanding Weighted Dates December 31 Average December 31 Average (1) Interest (1) Interest Rate(2) Rate(2) Great Lakes Senior Unsecured Notes (2004 - US$235; 2003 - 2011 to 2030 283 7.9% 310 7.9% US$240) Iroquois Senior Unsecured Notes (2004 and 2003 - US$151) 2010 to 2027 182 7.5% 196 7.5% Bank Loan (2004 - US$36; 2003 - 2008 43 2.5% 56 2.3% US$43) Trans Quebec & Maritimes Bonds 2005 to 2010 143 7.3% 143 7.3% Term Loan 2006 29 3.2% 34 3.5% F-23 TransCanada Power, L.P. Senior Unsecured Notes (2004 - US$58) 2014 70 5.9% - Credit Facility 2009 64 3.2% - Term Loan 2010 2 11.3% - Other 2005 to 2012 46 4.9% 41 5.4% 862 780 Less: Current Portion of Non- Recourse Debt of Joint Ventures 83 19 779 761 (1) Amounts outstanding represent TCPL's proportionate share and are stated in millions of Canadian dollars; amounts denominated in U.S. dollars are stated in millions. (2) Weighted average interest rates are stated as at the respective outstanding dates. At December 31, 2004, the effective weighted average interest rates resulting from swap agreements are as follows: Iroquois bank loan - 4.1 per cent (2003 - 4.5 per cent) and Power, L.P. Credit Facility - 5.2 per cent. The debt of joint ventures is non-recourse to TCPL. The security provided by each joint venture is limited to the rights and assets of that joint venture and does not extend to the rights and assets of TCPL, except to the extent of TCPL's investment. The Company's proportionate share of principal repayments resulting from maturities and sinking fund obligations of the non-recourse joint venture debt approximates: 2005 - $83 million; 2006 - $49 million; 2007 - $18 million; 2008 - $18 million; and 2009 - $141 million. The Company's proportionate share of the interest payments of joint ventures was $55 million for the year ended December 31, 2004 (2003 - $67 million; 2002 - $88 million). NOTE 11 DEFERRED AMOUNTS December 31 (millions of dollars) 2004 2003 Derivative contracts 209 40 Regulatory deferrals 229 131 Other benefit plans 63 32 Deferred revenue 58 215 Asset retirement obligation 36 9 Other 71 134 666 561 F-24 NOTE 12 PREFERRED SECURITIES The US$460 million 8.25 per cent preferred securities are redeemable by the Company at par at any time. The Company may elect to defer interest payments on the preferred securities and settle the deferred interest in either cash or common shares. Since the deferred interest may be settled through the issuance of common shares at the option of the Company, the preferred securities are classified into their respective debt and equity components. At December 31, 2004, the debt component of the preferred securities is $19 million (US$16 million) (2003 - $22 million (US$14 million)) and the equity component of the preferred securities is $670 million (US$444 million) (2003 - $672 million (US$446 million)). Effective January 1, 2005, under new Canadian accounting standards, the equity component of preferred securities will be classified as debt. NOTE 13 PREFERRED SHARES December 31 Number of Dividend Redemption 2004 2003 Shares Rate Per Price Per (millions (millions (thousands) Share Share of of dollars) dollars) Cumulative First Preferred Shares Series U 4,000 $2.80 $50.00 195 195 Series Y 4,000 $2.80 $50.00 194 194 389 389 The authorized number of preferred shares issuable in series is unlimited. All of the cumulative first preferred shares are without par value. On or after October 15, 2013, for the Series U shares, and on or after March 5, 2014, for the Series Y shares, the Company may redeem the shares at $50 per share. NOTE 14 COMMON SHARES Number of Amount Shares (millions (thousands) of dollars) Outstanding at January 1, 2002 476,631 4,564 Exercise of options 2,871 50 Outstanding at December 31, 2002 479,502 4,614 Exercise of options 1,166 18 Outstanding at December 31, 2003 and 2004 480,668 4,632 Common Shares Issued and Outstanding The Company is authorized to issue an unlimited number of common shares of no par value. F-25 Restriction on Dividends Certain terms of the Company's preferred shares, preferred securities, and debt instruments could restrict the Company's ability to declare dividends on preferred and common shares. At December 31, 2004, under the most restrictive provisions, approximately $1.4 billion was available for the payment of dividends on common shares. NOTE 15 RISK MANAGEMENT AND FINANCIAL INSTRUMENTS The Company issues short-term and long-term debt, including amounts in foreign currencies, purchases and sells energy commodities and invests in foreign operations. These activities result in exposures to interest rates, energy commodity prices and foreign currency exchange rates. The Company uses derivatives to manage the risk that results from these activities. Carrying Values of Derivatives The carrying amounts of derivatives, which hedge the price risk of foreign currency denominated assets and liabilities of self-sustaining foreign operations, are recorded on the balance sheet at their fair value. Gains and losses on these derivatives, realized and unrealized, are included in the foreign exchange adjustment account in Shareholders' Equity as an offset to the corresponding gains and losses on the translation of the assets and liabilities of the foreign subsidiaries. As of January 1, 2004, carrying amounts for interest rate swaps are recorded on the balance sheet at their fair value. Foreign currency transactions hedged by foreign exchange contracts are recorded at the contract rate. Power, natural gas and heat rate derivatives are recorded on the balance sheet at their fair value. The carrying amounts shown in the tables that follow are recorded in the consolidated balance sheet. Fair Values of Financial Instruments Cash and short-term investments and notes payable are valued at their carrying amounts due to the short period to maturity. The fair values of long-term debt, non-recourse long-term debt of joint ventures and junior subordinated debentures are determined using market prices for the same or similar issues. The fair values of foreign exchange and interest rate derivatives have been estimated using year-end market rates. The fair values of power, natural gas and heat rate derivatives have been calculated using estimated forward prices for the relevant period. Credit Risk Credit risk results from the possibility that a counterparty to a derivative in which the Company has an unrealized gain fails to perform according to the terms of the contract. Credit exposure is minimized through the use of established credit management techniques, including formal assessment processes, contractual and collateral requirements, master netting arrangements and credit exposure limits. At December 31, 2004, for foreign currency and interest rate derivatives, total credit risk and the largest credit exposure to a single counterparty were $127 million and $40 million, respectively. At December 31, 2004, for power, natural gas and heat rate derivatives, total credit risk and the largest credit exposure to a single counterparty were $19 million and $7 million, respectively. Notional or Notional Principal Amounts Notional principal amounts are not recorded in the financial statements because these amounts are not exchanged by the Company and its counterparties and are not a measure of the Company's exposure. Notional amounts are used only as the basis for calculating payments for certain derivatives. F-26 Foreign Investments At December 31, 2004 and 2003, the Company had foreign currency denominated assets and liabilities which created an exposure to changes in exchange rates. The Company uses foreign currency derivatives to hedge this net exposure on an after-tax basis. The foreign currency derivatives have a floating interest rate exposure which the Company partially hedges by entering into interest rate swaps and forward rate agreements. The fair values shown in the table below for those derivatives that have been designated as and are effective as hedges for foreign exchange risk are offset by translation gains or losses on the net assets and are recorded in the foreign exchange adjustment account in Shareholders' Equity. Net Investment in Foreign Assets Asset/(Liability) 2004 2003 December 31 (millions of dollars) Accounting Fair Notional Fair Notional Treatment Value or Value or Notional Notional Principal Principal Amount Amount (U.S.) (U.S.) U.S. dollar cross-currency swaps (maturing 2006 to 2009) Hedge 95 400 65 250 U.S. dollar forward foreign exchange contracts (maturing 2005) Hedge (1 ) 305 3 125 U.S. dollar options (maturing 2005) Non-hedge 1 100 - - In accordance with the Company's accounting policy, each of the above derivatives is recorded on the consolidated balance sheet at its fair value in 2004. For derivatives that have been designated as and are effective as hedges of the net investment in foreign operations, the offsetting amounts are included in the foreign exchange adjustment account. In addition, at December 31, 2004, the Company had interest rate swaps associated with the cross-currency swaps with notional principal amounts of $375 million (2003 - $311 million) and US$250 million (2003 - US$200 million). The carrying amount and fair value of these interest rate swaps was $4 million (2003 - $3 million) and $4 million (2003 - $1 million), respectively. Reconciliation of Foreign Exchange Adjustment Gains/(Losses) December 31 (millions of dollars) 2004 2003 Balance at beginning of year (40 ) 14 Translation losses on foreign currency denominated net (64 ) (136 ) assets Foreign exchange gains on derivatives, net of income taxes 33 82 (71 ) (40 ) Foreign Exchange Gains/(Losses) Foreign exchange gains/(losses) included in Other Expenses/(Income) for the year ended December 31, 2004 are $4 million (2003 - nil; 2002 - $(11) million). F-27 Foreign Exchange and Interest Rate Management Activity The Company manages certain of the foreign exchange risk of U.S. dollar debt, U.S. dollar expenses and the interest rate exposures of the Canadian Mainline, the Alberta System, GTN and the Foothills System through the use of foreign currency and interest rate derivatives. Certain of the realized gains and losses on these derivatives are shared with shippers on predetermined terms. The details of the foreign exchange and interest rate derivatives are shown in the table below. Asset/(Liability) 2004 2003 December 31 (millions of dollars) Accounting Fair Notional Fair Notional Treatment Value or Value or Notional Notional Principal Principal Amount Amount Foreign Exchange Cross-currency swaps (maturing 2010 to 2012) Hedge (39 ) U.S. 157 (26 ) U.S. 282 Interest Rate Interest rate swaps Canadian dollars (maturing 2005 to 2008) Hedge 7 145 (1 ) 340 (maturing 2006 to 2009) Non-hedge 9 374 10 624 16 9 U.S. dollars (maturing 2010 to 2015) Hedge (2 ) U.S. 275 11 U.S. 50 (maturing 2007 to 2009) Non-hedge 7 U.S. 100 (3 ) U.S. 50 5 8 In accordance with the Company's accounting policy, each of the above derivatives is recorded on the consolidated balance sheet at its fair value in 2004. At December 31, 2004, the Company also had interest rate swaps associated with the cross-currency swaps with notional principal amounts of $227 million (2003 - $390 million) and US$157 million (2003 - US$282 million). The carrying amount and fair value of these interest rate swaps was $(4) million (2003 - nil) and $(4) million (2003 - $6 million), respectively. F-28 The Company manages the foreign exchange and interest rate exposures of its other businesses through the use of foreign currency and interest rate derivatives. The details of these foreign currency and interest rate derivatives are shown in the table below. Asset/(Liability) 2004 2003 December 31 (millions of dollars) Accounting Fair Notional Fair Notional Treatment Value or Value or Notional Notional Principal Principal Amount Amount Foreign Exchange Options (maturing 2005) Non-hedge 2 U.S. 225 1 U.S. 25 Forward foreign exchange contracts (maturing 2005) Non-hedge 1 U.S. 29 1 U.S. 19 Cross-currency swaps (maturing 2013) Hedge (16 ) U.S. 100 (7 ) U.S. 100 Interest Rate Options (maturing 2005) Non-hedge - U.S. 50 (2 ) U.S. 50 Interest rate swaps Canadian dollar (maturing 2007 to 2009) Hedge 4 100 2 50 (maturing 2005 to 2011) Non-hedge 1 110 2 100 5 4 U.S. dollar (maturing 2006 to 2013) Hedge 5 U.S. 100 40 U.S. 250 (maturing 2006 to 2010) Non-hedge 22 U.S. 250 (3 ) U.S. 200 27 37 In accordance with the Company's accounting policy, each of the above derivatives is recorded on the consolidated balance sheet at its fair value in 2004. At December 31, 2004, the Company also had interest rate swaps associated with the cross-currency swaps with notional principal amounts of $136 million (2003 - $136 million) and US$100 million (2003 - US$100 million). The carrying amount and fair value of these interest rate swaps was $(10) million (2003 - nil) and $(10) million (2003 - $(7) million), respectively. Certain of the Company's joint ventures use interest rate derivatives to manage interest rate exposures. The Company's proportionate share of the fair value of the outstanding derivatives at December 31, 2004 was $1 million (2003 - $(1) million). Energy Price Risk Management The Company executes power, natural gas and heat rate derivatives for overall management of its asset portfolio. Heat rate contracts are contracts for the sale or purchase of power that are priced based on a natural gas index. The fair values and notional volumes of the swap, option, forward and heat rate contracts are shown in the tables below. In accordance with the Company's accounting policy, each of the derivatives in the table below is recorded on the balance sheet at its fair value in 2004 and 2003. F-29 Power Asset/(Liability) 2004 2003 December 31 (millions of dollars) Accounting Fair Fair Treatment Value Value Power - swaps (maturing 2005 to 2011) Hedge 7 (5 ) (maturing 2005) Non-hedge (2 ) - Gas - swaps, forwards and options (maturing 2005 to 2016) Hedge (39 ) (34 ) (maturing 2005) Non-hedge (2 ) (1 ) Heat rate contracts (maturing 2005 to 2006) Hedge (1 ) (1 ) Notional Volumes Power (GWh)(1) Gas (Bcf)(1) December 31, 2004 Accounting Purchases Sales Purchases Sales Treatment Power - swaps (maturing 2005 to 2011) Hedge 3,314 7,029 - - (maturing 2005) Non-hedge 438 - - - Gas - swaps, forwards and options (maturing 2005 to 2016) Hedge - - 80 84 (maturing 2005) Non-hedge - - 5 8 Heat rate contracts (maturing 2005 to 2006) Hedge - 229 2 - December 31, 2003 Power - swaps Hedge 1,331 4,787 - - Non-hedge 59 77 - - Gas - swaps, forwards and options Hedge - - 79 81 Non-hedge - - - 7 Heat rate contracts Hedge - 735 1 - (1) Gigawatt hours (GWh); billion cubic feet (Bcf). U.S. Dollar Transaction Hedges To reduce risk and protect margins when purchase and sale contracts are denominated in different currencies, the Company may enter into forward foreign exchange contracts and foreign exchange options which establish the foreign exchange rate for the cash flows from the related purchase and sale transactions. F-30 Other Fair Values 2004 2003 December 31 (millions of dollars) Carrying Fair Carrying Fair Amount Value Amount Value Long-Term Debt Canadian Mainline 4,445 5,473 4,853 5,922 Alberta System 2,105 2,668 2,325 2,893 GTN(1) 632 627 Foothills System 400 413 380 382 Portland 308 328 350 348 Other 2,589 2,687 2,107 2,214 Non-Recourse Debt of Joint Ventures 862 967 780 889 Preferred Securities 19 19 19 19 (1) TCPL acquired GTN on November 1, 2004. These fair values are provided solely for information purposes and are not recorded in the consolidated balance sheet. NOTE 16 INCOME TAXES Provision for Income Taxes Year ended December 31 (millions of dollars) 2004 2003 2002 Current Canada 390 264 229 Foreign 41 41 41 431 305 270 Future Canada 34 183 193 Foreign 43 47 54 77 230 247 508 535 517 Geographic Components of Income Year ended December 31 (millions of dollars) 2004 2003 2002 Canada 1,253 1,115 1,042 Foreign 296 281 280 Income from continuing operations before income taxes and 1,549 1,396 1,322 non-controlling interests F-31 Reconciliation of Income Tax Expense Year ended December 31 (millions of dollars) 2004 2003 2002 Income from continuing operations before income taxes and 1,549 1,396 1,322 non-controlling interests Federal and provincial statutory tax rate 33.9 % 36.7 % 39.2 % Expected income tax expense 525 512 518 Income tax differential related to regulated operations 62 29 (8 ) Higher (lower) effective foreign tax rates 2 (2 ) (13 ) Large corporations tax 21 28 30 Lower effective tax rate on equity in earnings of (9 ) (11 ) (2 ) affiliates Non-taxable portion of gains related to Power LP (66 ) - - Change in valuation allowance (7 ) (3 ) 8 Other (20 ) (18 ) (16 ) Actual income tax expense 508 535 517 Future Income Tax Assets and Liabilities December 31 (millions of dollars) 2004 2003 Deferred costs 71 50 Deferred revenue 18 29 Alternative minimum tax credits 10 29 Net operating and capital loss carryforwards 7 28 Other 72 24 178 160 Less: Valuation allowance 17 24 Future income tax assets, net of valuation allowance 161 136 Difference in accounting and tax bases of plant, equipment 456 396 and PPAs Investments in subsidiaries and partnerships 114 108 Unrealized foreign exchange gains on long-term debt 45 15 Other 55 44 Future income tax liabilities 670 563 Net future income tax liabilities 509 427 As permitted by Canadian GAAP, the Company follows the taxes payable method of accounting for income taxes related to the operations of the Canadian natural gas transmission operations. If the liability method of accounting had been used, additional future income tax liabilities in the amount of $1,692 million at December 31, 2004 (2003 - $1,758 million) would have been recorded and would be recoverable from future revenues. Unremitted Earnings of Foreign Investments Income taxes have not been provided on the unremitted earnings of foreign investments which the Company does not intend to repatriate in the foreseeable future. If provision for these taxes had been made, future income tax liabilities would increase by approximately $57 million at December 31, 2004 (2003 - $54 million). Income Tax Payments Income tax payments of $419 million were made during the year ended December 31, 2004 (2003 - $220 million; 2002 - $257 million). F-32 NOTE 17 NOTES PAYABLE 2004 2003 Outstanding Weighted Outstanding Weighted December 31 Average December 31 Average (millions of Interest Rate (millions of Interest Rate dollars) Per Annum at dollars) Per Annum at December 31 December 31 Commercial Paper Canadian dollars 546 2.6% 367 2.7% Total credit facilities of $2.0 billion at December 31, 2004, were available to support the Company's commercial paper programs and for general corporate purposes. Of this total, $1.5 billion is a committed syndicated credit facility established in December 2002. This facility is comprised of a $1.0 billion tranche with a five year term and a $500 million tranche with a 364 day term with a two year term out option. Both tranches are extendible on an annual basis and are revolving unless during a term out period. Both tranches were extended in December 2004, the $1.0 billion tranche to December 2009 and the $500 million tranche to December 2005. The remaining amounts are either demand or non-extendible facilities. At December 31, 2004, the Company had used approximately $61 million of its total lines of credit for letters of credit and to support its ongoing commercial arrangements. If drawn, interest on the lines of credit would be charged at prime rates of Canadian chartered and U.S. banks and at other negotiated financial bases. The cost to maintain the unused portion of the lines of credit is approximately $2 million for the year ended December 31, 2004 (2003 - $2 million). NOTE 18 ASSET RETIREMENT OBLIGATIONS At December 31, 2004, the estimated undiscounted cash flows required to settle the asset retirement obligation with respect to Gas Transmission were $48 million, calculated using an inflation rate of 3 per cent per annum, and the estimated fair value of this liability was $12 million (2003 - $2 million). The estimated cash flows have been discounted at rates ranging from 6.0 per cent to 6.6 per cent. At December 31, 2004, the expected timing of payment for settlement of the obligations ranges from 13 to 25 years. No amount has been recorded for asset retirement obligations relating to the regulated natural gas transmission operation assets as it is not possible to make a reasonable estimate of the fair value of the liability due to the indeterminate timing and scope of the asset retirements. Management believes it is reasonable to assume that all retirement costs associated with the regulated pipelines will be recovered through tolls in future periods. At December 31, 2004, the estimated undiscounted cash flows required to settle the asset retirement obligation with respect to the Power business were $128 million, calculated using an inflation rate of 3 per cent per annum, and the estimated fair value of this liability was $24 million (2003 - $7 million). The estimated cash flows have been discounted at rates ranging from 6.0 per cent to 6.6 per cent. At December 31, 2004, the expected timing of payment for settlement of the obligations ranges from 17 to 29 years. F-33 Reconciliation of Asset Retirement Obligations (millions of dollars) Gas Power Total Transmission Balance at December 31, 2002 2 6 8 Revisions in estimated cash flows - 1 1 Balance at December 31, 2003 2 7 9 New obligations and revisions in estimated cash flows 9 21 30 Removal of Power LP redemption obligations - (5 ) (5 ) Accretion expense 1 1 2 Balance at December 31, 2004 12 24 36 NOTE 19 EMPLOYEE FUTURE BENEFITS The Company sponsors DB Plans that cover substantially all employees and sponsored a defined contribution pension plan (DC Plan) which was effectively terminated at December 31, 2002. Benefits provided under the DB Plans are based on years of service and highest average earnings over three consecutive years of employment, and increase annually by a portion of the increase in the Consumer Products Index. Under the DC Plan, Company contributions were based on the participating employees' pensionable earnings. As a result of the termination of the DC Plan, members of this plan were awarded retroactive service credit under the DB Plans for all years of service. In exchange for past service credit, members surrendered the accumulated assets in their DC Plan accounts to the DB Plans as at December 31, 2002. This plan amendment resulted in unamortized past service costs of $44 million. Past service costs are amortized over the expected average remaining service life of employees, which is approximately 11 years. The Company also provides its employees with other post-employment benefits other than pensions, including termination benefits and defined life insurance and medical benefits beyond those provided by government-sponsored plans. Effective January 1, 2003, the Company combined its previously existing other post-employment benefit plans into one plan for active employees and provided existing retirees the option of adopting the provisions of the new plan. This plan amendment resulted in unamortized past service costs of $7 million. Past service costs are amortized over the expected average remaining life expectancy of former employees, which is approximately 19 years. The expense for the DC Plan was nil for the year ended December 31, 2004 (2003 - nil; 2002 - $6 million). In 2004, the Company also expensed $1 million (2003 - $1 million; 2002 - nil) related to retirement savings plans for its U.S. employees. Total cash payments for employee future benefits for 2004, consisting of cash contributed by the Company to the DB Plans and other benefit plans was $88 million (2003 - $114 million). F-34 The Company measures its accrued benefit obligations and the fair value of plan assets for accounting purposes as at December 31 of each year. The most recent actuarial valuation of the pension plans for funding purposes was as of January 1, 2005, and the next required valuation will be as of January 1, 2006. Pension Benefit Other Benefit Plans Plans (millions of dollars) 2004 2003 2004 2003 Change in Benefit Obligation Benefit obligation - beginning of year 960 841 106 95 Current service cost 28 25 3 2 Interest cost 58 52 7 6 Employee contributions 2 2 - - Benefits paid (66 ) (45 ) (4 ) (4 ) Actuarial loss 46 66 (12 ) 7 Acquisition of subsidiary 72 19 23 - Benefit obligation - end of year 1,100 960 123 106 Change in Plan Assets Plan assets at fair value - beginning of year 799 621 - - Actual return on plan assets 97 89 1 - Employer contributions 84 110 4 4 Employee contributions 2 2 - - Benefits paid (66 ) (45 ) (4 ) (4 ) Acquisition of subsidiary 54 22 25 - Plan assets at fair value - end of year 970 799 26 - Funded status - plan deficit (130 ) (161 ) (97 ) (106 ) Unamortized net actuarial loss 255 263 25 39 Unamortized past service costs 39 41 7 6 Unamortized transitional obligation related to - - - 25 regulated business Accrued benefit asset/(liability), net of 164 143 (65 ) (36 ) valuation allowance of nil F-35 The accrued benefit (asset)/liability, net of valuation allowance, is included in the Company's balance sheet as follows. Pension Benefit Other Benefit Plans Plans 2004 2003 2004 2003 Other assets 206 201 3 - Accounts payable (42 ) (58 ) (5 ) (4 ) Deferred amounts - - (63 ) (32 ) Total 164 143 (65 ) (36 ) Included in the above accrued benefit obligation and fair value of plan assets at year end are the following amounts in respect of plans that are not fully funded. Pension Benefit Other Benefit Plans Plans 2004 2003 2004 2003 Accrued benefit obligation (1,084 ) (942 ) (100 ) (106 ) Fair value of plan assets 952 778 - - Funded status - plan deficit (132 ) (164 ) (100 ) (106 ) The Company's expected contributions for the year ended December 31, 2005 are approximately $67 million for the pension benefit plans and approximately $6 million for the other benefit plans. The following are estimated future benefit payments, which reflect expected future service. (millions of dollars) Pension Other Benefits Benefits 2005 52 6 2006 53 6 2007 56 7 2008 58 7 2009 60 7 Years 2010 to 2014 343 40 The significant weighted average actuarial assumptions adopted in measuring the Company's benefit obligations at December 31 are as follows. Pension Benefit Other Benefit Plans Plans 2004 2003 2004 2003 Discount rate 5.75% 6.00% 6.00% 6.25% Rate of compensation increase 3.50% 3.50% F-36 The significant weighted average actuarial assumptions adopted in measuring the Company's net benefit plan cost for years ended December 31 are as follows. Pension Benefit Plans Other Benefit Plans 2004 2003 2002 2004 2003 2002 Discount rate 6.00% 6.25% 6.75% 6.25% 6.50% 6.85% Expected long-term rate of 6.90% 7.25% 7.52% return on plan assets Rate of compensation 3.50% 3.75% 3.50% increase The overall expected long-term rate of return on plan assets is based on historical and projected rates of return for both the portfolio in aggregate and for each asset class in the portfolio. Assumed projected rates of return are selected after analyzing historical experience and future expectations of the level and volatility of returns. Asset class benchmark returns, asset mix and anticipated benefit payments from plan assets are also considered in the determination of the overall expected rate of return. For measurement purposes, a 9.0 per cent annual rate of increase in the per capita cost of covered health care benefits was assumed for 2005. The rate was assumed to decrease gradually to 5.0 per cent for 2014 and remain at that level thereafter. A one percentage point increase or decrease in assumed health care cost trend rates would have the following effects. (millions of dollars) Increase Decrease Effect on total of service and interest cost components 2 (1 ) Effect on post-employment benefit obligation 12 (11 ) F-37 The Company's net benefit cost is as follows. Pension Benefit Plans Other Benefit Plans Year ended December 31 2004 2003 2002 2004 2003 2002 (millions of dollars) Current service cost 28 25 11 3 2 2 Interest cost 58 52 43 7 6 4 Actual return on plan (97 ) (89 ) (9 ) 1 - - assets Actuarial loss 46 66 93 (12 ) 7 26 Plan amendment - - 92 - - 7 Elements of net benefit 35 54 230 (1 ) 15 39 cost prior to adjustments to recognize the long-term nature of net benefit cost Difference between expected 39 38 (36 ) (1 ) - - and actual return on plan assets Difference between (32 ) (58 ) (91 ) 13 (6 ) (26 ) actuarial loss recognized and actual actuarial loss on accrued benefit obligation Difference between 3 3 (92 ) - 1 (7 ) amortization of past service costs and actual plan amendments Amortization of - - - 2 2 2 transitional obligation related to regulated business Net benefit cost recognized 45 37 11 13 12 8 The Company's pension plan weighted average asset allocation at December 31, by asset category, and weighted average target allocation at December 31, by asset category, is as follows. Percentage of Target Plan Assets Allocation Asset Category 2004 2003 2004 Debt securities 44% 47% 35% to 60% Equity securities 56% 53% 40% to 65% 100% 100% The assets of the pension plan are managed on a going concern basis subject to legislative restrictions. The plan's investment policy is to maximize returns within an acceptable risk tolerance. Pension assets are invested in a diversified manner with consideration given to the demographics of the plan participants. F-38 NOTE 20 CHANGES IN OPERATING WORKING CAPITAL Year ended December 31 (millions of dollars) 2004 2003 2002 Decrease/(increase) in accounts receivable 7 26 (45 ) Decrease/(increase) in inventories - 15 (3 ) Decrease/(increase) in other current assets 33 21 (53 ) (Decrease)/increase in accounts payable - 52 120 (Decrease)/increase in accrued interest (7 ) (2 ) 14 33 112 33 NOTE 21 COMMITMENTS, CONTINGENCIES AND GUARANTEES Commitments Future annual payments, net of sub-lease receipts, under the Company's operating leases for various premises and a natural gas storage facility are approximately as follows. Year ended December 31 (millions of dollars) Minimum Amounts Net Lease Recoverable Payments Payments under Sub-Leases 2005 37 (9 ) 28 2006 45 (10 ) 35 2007 51 (9 ) 42 2008 53 (9 ) 44 2009 53 (9 ) 44 The operating lease agreements for premises expire at various dates through 2011, with an option to renew certain lease agreements for five years. The operating lease agreement for the natural gas storage facility expires in 2030 with lessee termination rights every fifth anniversary commencing in 2010 and with the lessor having the right to terminate the agreement every five years commencing in 2015. Net rental expense on operating leases for the year ended December 31, 2004 was $7 million (2003 - $2 million; 2002 - $7 million). On June 18, 2003, the Mackenzie Delta gas producers, the Aboriginal Pipeline Group (APG) and TCPL reached an agreement which governs TCPL's role in the Mackenzie Gas Pipeline Project. The project would result in a natural gas pipeline being constructed from Inuvik, Northwest Territories, to the northern border of Alberta, where it would connect with the Alberta System. Under the agreement, TCPL agreed to finance the APG for its one-third share of project development costs. This share is currently estimated to be approximately $90 million. As at December 31, 2004, TCPL had funded $60 million of this loan (2003 - $34 million) which is included in other assets. The ability to recover this investment is dependent upon the outcome of the project. Contingencies The Canadian Alliance of Pipeline Landowners' Associations and two individual landowners commenced an action in 2003 under Ontario's Class Proceedings Act, 1992, against TCPL and Enbridge Inc. for damages of $500 million alleged to arise from the creation of a control zone within 30 metres of the pipeline pursuant to Section 112 of the NEB Act. The Company believes the claim is without merit and will vigorously defend the action. The Company has made no provision for any potential liability. A liability, if any, would be dealt with through the regulatory process. F-39 The Company and its subsidiaries are subject to various other legal proceedings and actions arising in the normal course of business. While the final outcome of such legal proceedings and actions cannot be predicted with certainty, it is the opinion of Management that the resolution of such proceedings and actions will not have a material impact on the Company's consolidated financial position or results of operations. Guarantees Upon acquisition of Bruce Power, the Company, together with Cameco Corporation and BPC Generation Infrastructure Trust, guaranteed on a several pro-rata basis certain contingent financial obligations of Bruce Power related to operator licenses, the lease agreement, power sales agreements and contractor services. TCPL's share of the net exposure under these guarantees at December 31, 2004 was estimated to be approximately $158 million of a maximum of $293 million. The terms of the guarantees range from 2005 to 2018. The current carrying amount of the liability related to these guarantees is nil and the fair value is approximately $9 million. TCPL has guaranteed the equity undertaking of a subsidiary which supports the payment, under certain conditions, of principal and interest on US$161 million of public debt obligations of TransGas de Occidente, S.A. (TransGas). The Company has a 46.5 per cent interest in TransGas. Under the terms of the agreement, the Company severally with another major multinational company may be required to fund more than their proportionate share of debt obligations of TransGas in the event that the minority shareholders fail to contribute. Any payments made by TCPL under this agreement convert into share capital of TransGas. The potential exposure is contingent on the impact of any change of law on TransGas' ability to service the debt. From the issuance of the debt in 1995 to date, there has been no change in applicable law and thus no exposure to TCPL. The debt matures in 2010. The Company has made no provision related to this guarantee. In connection with the acquisition of GTN, US$241 million of the purchase price was deposited into an escrow account. The escrowed funds represent the full face amount of the potential liability under certain GTN guarantees and are to be used to satisfy the liability under these designated guarantees. NOTE 22 DISCONTINUED OPERATIONS The Board of Directors approved plans in previous years to dispose of the Company's International, Canadian Midstream, Gas Marketing and certain other businesses. Revenues from discontinued operations for the year ended December 31, 2004 were nil (2003 - $2 million; 2002 - $36 million). Net income from discontinued operations for the year ended December 31, 2004 was $52 million, net of $27 million of income taxes (2003 - $50 million, net of $29 million of income taxes; 2002 - nil). The net income from discontinued operations recognized in 2003 and 2004 represents the original $102 million after-tax deferred gain on the disposition of certain of the Gas Marketing operations. Included in accounts payable at December 31, 2004 was the remaining $55 million provision for loss on discontinued operations. F-40 NOTE 23 U.S. GAAP The Company's consolidated financial statements have been prepared in accordance with Canadian GAAP, which, in some respects, differ from U.S. GAAP. The effects of these differences on the Company's financial statements are as follows. Condensed Statement of Consolidated Income and Comprehensive Income in Accordance with U.S. GAAP(1) Year ended December 31 (millions of dollars) 2004 2003 2002 Revenues 4,700 4,919 4,565 Cost of sales 440 592 441 Other costs and expenses 1,638 1,663 1,532 Depreciation 857 819 729 2,935 3,074 2,702 Operating income 1,765 1,845 1,863 Other (income)/expenses Equity income(1) (353 ) (334 ) (260 ) Other expenses(2) 631 841 850 Income taxes 490 515 499 768 1,022 1,089 Income from continuing operations - U.S. GAAP 997 823 774 Net income from discontinued operations - U.S. GAAP 52 50 - Income before cumulative effect of the application of 1,049 873 774 accounting changes in accordance with U.S. GAAP Cumulative effect of the application of accounting changes, - (13 ) - net of tax(3) Net Income in Accordance with U.S. GAAP 1,049 860 774 Adjustments affecting comprehensive income under U.S. GAAP Foreign currency translation adjustment, net of tax (31 ) (54 ) 1 Changes in minimum pension liability, net of tax(4) 72 (2 ) (40 ) Unrealized gain/(loss) on derivatives, net of tax(5) 1 8 (4 ) Comprehensive Income in Accordance with U.S. GAAP 1,091 812 731 F-41 Reconciliation of Income from Continuing Operations Year ended December 31 (millions of dollars) 2004 2003 2002 Net Income from Continuing Operations in Accordance with 1,031 859 805 Canadian GAAP U.S. GAAP adjustments Preferred securities charges(6) (48 ) (57 ) (58 ) Tax impact of preferred securities charges 17 21 22 Unrealized (loss)/gain on foreign exchange and interest (12 ) (9 ) 30 rate derivatives(5) Tax impact of (loss)/gain on foreign exchange and 4 3 (12 ) interest rate derivatives Unrealized gain/(loss) on energy marketing contracts(3) 10 28 (21 ) Tax impact of unrealized gain/(loss) on energy marketing (3 ) (10 ) 8 contracts Equity loss(7) (2 ) (18 ) - Tax impact of equity loss - 6 - Income from Continuing Operations in Accordance with U.S. 997 823 774 GAAP Condensed Statement of Consolidated Cash Flows in Accordance with U.S. GAAP Year ended December 31 (millions of dollars) 2004 2003 2002 Cash Generated from Operations Funds generated from continuing operations 1,527 1,619 1,610 Decrease in operating working capital 44 108 40 Net cash provided by continuing operations 1,571 1,727 1,650 Net cash (used in)/provided by discontinued operations (6 ) (17 ) 59 1,565 1,710 1,709 Investing Activities Net cash used in investing activities (1,304 ) (943 ) (796 ) Financing Activities Net cash used in financing activities (333 ) (582 ) (990 ) Effect of Foreign Exchange Rate Changes on Cash and (87 ) (52 ) (3 ) Short-Term Investments (Decrease)/Increase in Cash and Short-Term Investments (159 ) 133 (80 ) Cash and Short-Term Investments Beginning of year 282 149 229 Cash and Short-Term Investments End of year 123 282 149 F-42 Condensed Balance Sheet in Accordance with U.S. GAAP(1) December 31 (millions of dollars) 2004 2003 Current assets 907 1,017 Long-term investments(7)(8) 1,887 1,760 Plant, property and equipment 17,083 15,753 Regulatory asset(9) 2,606 2,721 Other assets 1,235 1,385 23,718 22,636 Current liabilities(10) 2,653 2,179 Deferred amounts(3)(5)(8) 803 827 Long-term debt(5) 9,753 9,494 Deferred income taxes(9) 3,048 3,039 Preferred securities(11) 554 694 Non-controlling interests 76 82 Shareholders' equity 6,831 6,321 23,718 22,636 F-43 Statement of Other Comprehensive Income in Accordance with U.S. GAAP (millions of dollars) Cumulative Minimum Cash Flow Total Translation Pension Hedges (SFAS Account Liability No. 133) (SFAS No. 87) Balance at January 1, 2002 13 (56 ) (9 ) (52 ) Changes in minimum pension liability, net - (40 ) - (40 ) of tax of $22(4) Unrealized loss on derivatives, net of - - (4 ) (4 ) tax of $(1)(5) Foreign currency translation adjustment, 1 - - 1 net of tax of nil Balance at December 31, 2002 14 (96 ) (13 ) (95 ) Changes in minimum pension liability, net - (2 ) - (2 ) of tax of $1(4) Unrealized gain on derivatives, net of - - 8 8 tax of nil(5) Foreign currency translation adjustment, (54 ) - - (54 ) net of tax of $(64) Balance at December 31, 2003 (40 ) (98 ) (5 ) (143 ) Changes in minimum pension liability, net - 72 - 72 of tax of $(39)(4) Unrealized gain on derivatives, net of - - 1 1 tax of $(3)(5) Foreign currency translation adjustment, (31 ) - - (31 ) net of tax of $(44) Balance at December 31, 2004 (71 ) (26 ) (4 ) (101 ) (1) In accordance with U.S. GAAP, the Condensed Statement of Consolidated Income and Balance Sheet are prepared using the equity method of accounting for joint ventures. Excluding the impact of other U.S. GAAP adjustments, the use of the proportionate consolidation method of accounting for joint ventures, as required under Canadian GAAP, results in the same net income and shareholders' equity. (2) Other expenses included an allowance for funds used during construction of $3 million for the year ended December 31, 2004 (2003 - $2 million; 2002 - $4 million). (3) Subsequent to October 1, 2003, the energy contracts that were accounted for as hedges under the provisions of Statement of Financial Accounting Standards (SFAS) No. 133 qualified as hedges. Substantially all derivative energy contracts are now accounted for as hedges under both U.S. and Canadian GAAP. All gains or losses on the contracts that did not qualify as hedges under SFAS No. 133, and the amounts of any ineffectiveness on the hedging contracts, are included in income each period. Substantially all of the amounts recorded in 2004 and 2003 as differences between U.S. and Canadian GAAP relate to gains and losses on contracts for periods before they were documented as hedges for purposes of U.S. GAAP and to differences in accounting with respect to physical energy trading contracts in the U.S. and Canada. (4) Under U.S. GAAP, a net loss recognized pursuant to SFAS No. 87 "Employers' Accounting for Pensions" as an additional pension liability not yet recognized as net period pension cost, must be recorded as a component of comprehensive income. The net amount recognized at December 31 is as follows. December 31 (millions of dollars) 2004 2003 Prepaid benefit cost 206 201 Accounts payable (42 ) (58 ) Intangible assets (1 ) (41 ) Accumulated other comprehensive income (40 ) (151 ) Net amount recognized 123 (49 ) F-44 The accumulated benefit obligation for the Company's DB Plans was $943 million at December 31, 2004 (2003 - $819 million). (5) Effective January 1, 2004, all foreign exchange and interest rate derivatives are recorded in the Company's consolidated financial statements at fair value under Canadian GAAP. Under the provisions of SFAS No. 133 "Accounting for Derivatives and Hedging Activities", all derivatives are recognized as assets and liabilities on the balance sheet and measured at fair value. For derivatives designated as fair value hedges, changes in the fair value are recognized in earnings together with an equal or lesser amount of changes in the fair value of the hedged item attributable to the hedged risk. For derivatives designated as cash flow hedges, changes in the fair value of the derivative that are effective in offsetting the hedged risk are recognized in other comprehensive income until the hedged item is recognized in earnings. Any ineffective portion of the change in fair value is recognized in earnings each period. Substantially all of the amounts recorded in 2004 as differences between U.S. and Canadian GAAP, for income from continuing operations, relate to the differences in accounting treatment with respect to the hedged item and, for comprehensive income, relate to cash flow hedges. During 2004, under the provisions of SFAS 133, net gains of $10 million (2003 - $47 million; 2002 - $38 million) from the hedges of changes in the fair value of long-term debt, and net losses of $18 million (2003 - $53 million; 2002 - $20 million) in the fair value of the hedged item were included in earnings for U.S. GAAP purposes as an adjustment to interest expense and foreign exchange losses. No amounts of the derivatives' gains or losses were excluded from the assessment of hedge effectiveness in fair value hedging relationships. No amounts were included in income in 2004, 2003 and 2002 with respect to ineffectiveness of cash flow hedges. For amounts included in other comprehensive income at December 31, 2004, $2 million (2003 - $9 million; 2002 - $(5) million) relates to the hedging of interest rate risk, $(3) million (2003 - $5 million; 2002 - $1 million) relates to the hedging of foreign exchange rate risk, and $2 million (2003 - $(6) million; 2002 - nil) relates to the hedging of energy price risk. Of these amounts, $2 million is expected to be recorded in earnings during 2005. At December 31, 2004, assets of $(29) million (2003 - $91 million) and liabilities of $(27) million (2003 - $93 million) were (reduced)/added for U.S. GAAP purposes to reflect the fair value of derivatives and the corresponding change in the fair value of hedged items. (6) Under U.S. GAAP, the financial charges related to preferred securities are recognized as an expense, rather than dividends. (7) Under Canadian GAAP, pre-operating costs incurred during the commissioning phase of a new project are deferred until commercial production levels are achieved. After such time, those costs are amortized over the estimated life of the project. Under U.S. GAAP, such costs are expensed as incurred. Certain start-up costs incurred by Bruce Power, L.P. (an equity investment) are required to be expensed under U.S. GAAP. Under both Canadian GAAP and U.S. GAAP, interest is capitalized on expenditures relating to construction of development projects actively being prepared for their intended use. In Bruce Power, L.P. under U.S. GAAP, the carrying value of development projects against which interest is capitalized is lower due to the expensing of pre-operating costs. (8) Effective January 1, 2003, the Company adopted the provisions of Financial Interpretation (FIN) 45 that require the recognition of a liability for the fair value of certain guarantees that require payments contingent on specified types of future events. The measurement standards of FIN 45 are applicable to guarantees entered into after January 1, 2003. For U.S. GAAP purposes, the fair value of guarantees recorded as a liability at December 31, 2004 was $9 million (2003 - $4 million) and relates to the Company's equity interest in Bruce Power. (9) Under U.S. GAAP, the Company is required to record a deferred income tax liability for its cost-of-service regulated businesses. As these deferred income taxes are recoverable through future revenues, a corresponding regulatory asset is recorded for U.S. GAAP purposes. (10) Current liabilities at December 31, 2004 include dividends payable of $146 million (2003 - $136 million) and current taxes payable of $260 million (2003 - $271 million). (11) The fair value of the preferred securities at December 31, 2004 was $572 million (2003 - $612 million). The Company made preferred securities charges payments of $48 million for the year ended December 31, 2004 (2003 - $57 million; 2002 - $58 million). F-45 Income Taxes The tax effects of differences between the accounting value and the tax value of assets and liabilities are as follows. December 31 (millions of dollars) 2004 2003 Deferred Tax Liabilities Difference in accounting and tax bases of plant, equipment 1,741 1,813 and PPAs Taxes on future revenue requirement 914 962 Investments in subsidiaries and partnerships 438 373 Other 140 87 3,233 3,235 Deferred Tax Assets Net operating and capital loss carryforwards 7 28 Deferred amounts 89 79 Other 106 113 202 220 Less: Valuation allowance 17 24 185 196 Net deferred tax liabilities 3,048 3,039 Other Effective December 31, 2003, the Company adopted the provisions of FIN 46 (Revised) "Consolidation of Variable Interest Entities" that requires the consolidation of certain entities that are controlled through financial interests that indicate control (referred to as 'variable interests'). Adopting these provisions has had no impact on the U.S. GAAP financial statements of the Company. In May 2003, the FASB issued SFAS No. 150 "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity". This statement establishes standards for how an issuer classifies and measures in its statement of financial position certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances) because that financial instrument embodies an obligation of the issuer. Many of those instruments were previously classified as equity. Adopting the provisions of SFAS No. 150 has had no impact on the U.S. GAAP financial statements of the Company. F-46 Summarized Financial Information of Long-Term Investments The following summarized financial information of long-term investments includes those investments that are accounted for by the equity method under U.S. GAAP (including those that are accounted for by the proportionate consolidation method under Canadian GAAP). Year ended December 31 (millions of dollars) 2004 2003 2002 Income Revenues 1,149 1,063 798 Other costs and expenses (575 ) (528 ) (273 ) Depreciation (155 ) (141 ) (146 ) Financial charges and other (66 ) (60 ) (119 ) Proportionate share of income before income taxes of 353 334 260 long-term investments December 31 (millions of dollars) 2004 2003 Balance Sheet Current assets 361 385 Plant, property and equipment 3,020 2,944 Current liabilities (248 ) (204 ) Deferred amounts (net) (199 ) (286 ) Non-recourse debt (1,030 ) (1,060 ) Deferred income taxes (17 ) (19 ) Proportionate share of net assets of long-term investments 1,887 1,760 F-47 This information is provided by RNS The company news service from the London Stock Exchange MORE TO FOLLOW FR GGGMFFVRGKZZ
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