-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, KnMHgiUeGs12sTV2TrP7lDxhx1TKy/hPY/5ovc5nplZLeLvqQWNcXFoP6VN9ptf6 nDCy4HrL5+JBBfBWuzt2vw== 0001047469-05-020506.txt : 20050802 0001047469-05-020506.hdr.sgml : 20050802 20050802164039 ACCESSION NUMBER: 0001047469-05-020506 CONFORMED SUBMISSION TYPE: 40-F/A PUBLIC DOCUMENT COUNT: 7 CONFORMED PERIOD OF REPORT: 20041231 FILED AS OF DATE: 20050802 DATE AS OF CHANGE: 20050802 FILER: COMPANY DATA: COMPANY CONFORMED NAME: TRANSCANADA PIPELINES LTD CENTRAL INDEX KEY: 0000099070 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS TRANSMISSION [4922] IRS NUMBER: 522179728 FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 40-F/A SEC ACT: 1934 Act SEC FILE NUMBER: 001-08887 FILM NUMBER: 05992490 BUSINESS ADDRESS: STREET 1: 450 I STREET SW STREET 2: P O BOX 1000 STATION M CITY: CALGARY ALBERTA STATE: A0 ZIP: T2P 5H1 BUSINESS PHONE: 4039207669 MAIL ADDRESS: STREET 1: 450 I STREET SW CITY: CALGARY ALBERTA STATE: A0 ZIP: T2P 5H1 40-F/A 1 a2160607z40-fa.htm FORM 40-F/A
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U.S. Securities and Exchange Commission
Washington, D.C. 20549
Form 40-F/A
Amendment No. 1


o

REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT of 1934
OR

ý

ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended    December 31, 2004            

 

Commission File Number 1-8887

TRANSCANADA PIPELINES LIMITED
(Exact Name of Registrant as specified in its charter)

Canada
(Jurisdiction of incorporation or organization)

4922, 4923, 4924, 5172
(Primary Standard Industrial Classification Code Number (if applicable))

Not Applicable
(I.R.S. Employer Identification Number (if applicable))

TransCanada Tower, 450 - 1 Street S.W.
Calgary, Alberta, Canada, T2P 5H1
(403) 920-2000
(Address and telephone number of Registrant's principal executive offices)

CT Corporation, Suite 2610, 520 Pike Street
Seattle, Washington, 98101; (206) 622-4511; 1-800-456-4511
(Name, address (including zip code) and telephone number (including area code) of agent for service in the United States)

Securities registered pursuant to section 12(b) of the Act:


Title of each class

 

Name of each exchange on which registered
8.25% Preferred Securities due 2047   New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:    None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:    None

For annual reports, indicate by check mark the information filed with this Form:

o Annual Information Form                    ý Audited annual financial statements

Indicate the number of outstanding shares of each of the issuer's classes of capital or common stock as of the close of the period covered by the annual report.

At December 31, 2004, 4,000,000 Cumulative Redeemable First Preferred Shares Series U
and 4,000,000 Cumulative Redeemable First Preferred Shares Series Y
were issued and outstanding
All of the Registrant's common shares are owned by TransCanada Corporation.

Indicate by check mark whether the Registrant by filing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934 (the "Exchange Act"). If "Yes" is marked, indicate the file number assigned to the Registrant in connection with such Rule.


Yes

 

o

 

No

 

ý

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or such shorter period that the Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.


Yes

 

ý

 

No

 

o

        The documents (or portions thereof) forming part of this Form 40-F/A are incorporated by reference in Amendment No. 1 on Form F-9 to Registration Statement (Reg. No. 333-121265) under the Securities Act of 1933, as amended.





EXPLANATORY NOTE

        TransCanada PipeLines Limited ("TransCanada") is filing this Form 40-F/A Amendment No. 1 to its Annual Report on Form 40-F for the year ended December 31, 2004 which was filed with the Securities and Exchange Commission on March 15, 2005, to refile its 2004 Consolidated Financial Statements, which contains a restated Note 23 (U.S. GAAP). The restatement relates to the reporting of TransCanada's investment in TransCanada Power, L.P. For U.S. generally accepted accounting principles (GAAP) purposes, certain transactions involving TransCanada Power, L.P., in the period 1997 to 2001, should have been accounted for differently than under Canadian GAAP. This has been corrected on a retroactive basis. The restated Note 23 has no impact on TransCanada's 2004 financial statements as prepared under Canadian GAAP or on total shareholders' equity at December 31, 2004 as prepared under U.S. GAAP.

        Other than as expressly set forth above, this Form 40-F/A does not, and does not purport to, update, or restate the information in any Item of the Form 40-F or reflect any events that have occurred after the Form 40-F was filed.


UNDERTAKING

        The Registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an Annual Report on Form 40-F arises; or transactions in said securities.



SIGNATURES

        Pursuant to the requirements of the Exchange Act, the Registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this Annual Report to be signed on its behalf by the undersigned, thereto duly authorized, in the City of Calgary, Province of Alberta, Canada.

    TRANSCANADA PIPELINES LIMITED

 

 

By:

/s/  
RUSSELL K. GIRLING      
Russell K. Girling, Executive Vice-President,
Corporate Development and Chief Financial Officer

Date: August 2, 2005

 

 

 

DOCUMENTS FILED AS PART OF THIS REPORT

    13.1
    Restated 2004 Consolidated Audited Financial Statements included herein on pages F-2 through F-47.

    13.2
    U.S. GAAP reconciliation included herein on pages F-40 through F-47 of the Restated 2004 Consolidated Audited Financial Statements.

    99.1
    Comments by Auditors for U.S. Readers on Canada — U.S. Reporting Difference.

EXHIBITS

    23.1
    Consent of KPMG LLP, Chartered Accountants.

    31.1
    Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

    31.2
    Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

TransCanada PipeLines Limited

Restated Consolidated Financial Statements
December 31, 2004

F-1



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 consolidated statements of income, retained earnings and cash flows for 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 audit.

 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 revised 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.

 Our previous report dated February 28, 2005 has been withdrawn and the financial statements have been revised as explained in note 23 to the revised consolidated financial statements.

Chartered Accountants

SIGNATURE

Calgary, Canada

February 28, 2005, except
as to note 23 which is
as of July 28, 2005

F-2



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 Non- Controlling Interests   1,549   1,396   1,322  

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-3



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-4



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:

SIGNATURE   SIGNATURE
Harold N. Kvisle   Harry G. Schaefer
Director   Director

F-5



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-6



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 Québec (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-7


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 Québec & Maritimes Pipeline Inc. (Trans Québec & 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-8


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-9


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-10



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-11


NOTE 3    SEGMENTED INFORMATION

NET INCOME/(LOSS)(1)

Year ended December 31, 2004 (millions of dollars)

  Gas Transmission

  Power

  Corporate

  Total

 

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 and non-controlling interests   (785 ) (9 ) (81 ) (875 )
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 and non-controlling interests   (781 ) (11 ) (89 ) (881 )
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-12



Year ended December 31, 2002 (millions of dollars)


 

Gas Transmission


 

Power


 

Corporate


 

Total


 
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 and non-controlling interests   (821 ) (13 ) (91 ) (925 )
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-13


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-14


NOTE 4    PLANT, PROPERTY AND EQUIPMENT

December 31
(millions of dollars)


  2004

  2003

 
  Cost

  Accumulated Depreciation

  Net Book Value

  Cost

  Accumulated Depreciation

  Net Book 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 other   3,213   1,053   2,160   3,361   1,052   2,309
   
 
 
 
 
 
    26,294   8,969   17,325   24,366   8,311   16,055
   
 
 
 
 
 

Power(2)

 

 

 

 

 

 

 

 

 

 

 

 
  Power generation facilities   1,397   375   1,022   1,439   381   1,058
  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-15


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
(millions of dollars)


  2004

  2003

 
  Cost

  Accumulated Amortization

  Net Book Value

  Cost

  Accumulated Amortization

  Net Book 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
Year ended December 31

  Net Assets December 31

(millions of dollars)

  Ownership Interest

  2004

  2003

  2002

  2004

  2003

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 Québec & 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
       
 
 
 
 

F-16


(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.

(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 ventures   207   209   252  
   
 
 
 
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 short-term investments   (5 ) (10 ) (1 )
   
 
 
 
Proportionate share of increase/(decrease) in cash and short-term investments of joint ventures   9   (8 ) (12 )
   
 
 
 
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-17


NOTE 7    LONG-TERM INVESTMENTS

 
   
  TCPL's Share

 
   
  Distributions from Equity Investments
Year ended December 31

  Income from Equity Investments
Year ended December 31

  Equity Investments December 31

(millions of dollars)

  Ownership Interest

  2004

  2003

  2002

  2004

  2003

  2002

  2004

  2003

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 Occidente S.A.   46.5%   8   8     11   27   5   78   80
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-18



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-19



NOTE 9    LONG-TERM DEBT

 
   
  2004

  2003

 
  Maturity Dates

  Outstanding December 31(1)

  Weighted Average Interest Rate(2)

  Outstanding December 31(1)

  Weighted Average
Interest Rate(2)

CANADIAN MAINLINE(3)                    
First Mortgage Pipe Line Bonds                    
  Pounds Sterling (2004 and 2003 — £25)   2007   58   16.5%   58   16.5%
Debentures                    
  Canadian dollars   2008 to 2020   1,354   10.9%   1,354   10.9%
  U.S. dollars (2004 — US$600; 2003 —  US$800)   2012 to 2021   722   9.5%   1,034   9.2%
Medium-Term Notes                    
  Canadian dollars   2005 to 2031   2,167   6.9%   2,312   6.9%
  U.S. dollars (2004 and 2003 — US$120)   2010   144   6.1%   155   6.1%
Foreign exchange differential recoverable through the tollmaking process(8)             (60 )  
       
     
   
        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 — US$375; 2003 — US$500)   2012 to 2023   451   8.2%   646   8.3%
Medium-Term Notes                    
  Canadian dollars   2005 to 2030   767   7.4%   767   7.4%
  U.S. dollars (2004 and 2003 — US$233)   2026 to 2029   280   7.7%   301   7.7%
Foreign exchange differential recoverable through the tollmaking process(8)             (16 )  
       
     
   
        2,105       2,325    
       
     
   
GTN(5)                    
Unsecured Debentures and Notes (2004 —  US$525)   2005 to 2025   632   7.2%      
       
     
   
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 — US$256; 2003 —  US$271)   2018   308   5.9%   350   5.9%
       
     
   
OTHER                    
Medium-Term Notes(3)                    
  Canadian dollars   2005 to 2030   592   6.2%   592   6.2%
  U.S. dollars (2004 — US$521; 2003 —  US$665)   2006 to 2025   627   6.9%   859   6.8%
Subordinated Debentures(3)                    
  U.S. dollars (2004 and 2003 — US$57)   2006   68   9.1%   74   9.1%
Unsecured Loans, Debentures and Notes(7)                    
  U.S. dollars (2004 — US$1,082; 2003 —  US$446)   2005 to 2034   1,302   5.1%   582   4.9%
       
     
   
        2,589       2,107    
       
     
   
        10,479       10,015    
Less: Current Portion of Long-Term Debt       766       550    
       
     
   
        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-20


    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-21


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 Dates

  Outstanding December 31(1)

  Weighted Average Interest Rate(2)

  Outstanding December 31(1)

  Weighted Average
Interest Rate(2)

Great Lakes                    
Senior Unsecured Notes                    
  (2004 — US$235; 2003 — US$240)   2011 to 2030   283   7.9%   310   7.9%

Iroquois

 

 

 

 

 

 

 

 

 

 
Senior Unsecured Notes                    
  (2004 and 2003 — US$151)   2010 to 2027   182   7.5%   196   7.5%
Bank Loan                    
  (2004 — US$36; 2003 — US$43)   2008   43   2.5%   56   2.3%

Trans Québec & Maritimes

 

 

 

 

 

 

 

 

 

 
Bonds   2005 to 2010   143   7.3%   143   7.3%
Term Loan   2006   29   3.2%   34   3.5%
                     

F-22



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-23


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 Shares (thousands)

  Dividend Rate Per Share

  Redemption Price Per Share

  2004 (millions of dollars)

  2003 (millions of 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 Shares (thousands)

  Amount (millions 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-24


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-25


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 Treatment

  Fair
Value

  Notional or Notional Principal Amount (U.S.)

  Fair
Value

  Notional or Notional Principal Amount (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 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).

F-26


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 Treatment

  Fair Value

  Notional or Notional Principal Amount

  Fair Value

  Notional or Notional Principal 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-27



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 Treatment
  Fair Value
  Notional or Notional Principal Amount
  Fair Value
  Notional or Notional Principal 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-28


Power

Asset/(Liability)

 
   
  2004

  2003

 
December 31 (millions of dollars)

  Accounting Treatment

  Fair Value

  Fair 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 Treatment

  Purchases

  Sales

  Purchases

  Sales

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-29


Other Fair Values

 
  2004

  2003

December 31 (millions of dollars)

  Carrying Amount

  Fair Value

  Carrying Amount

  Fair 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 non-controlling interests   1,549   1,396   1,322
   
 
 

F-30


Reconciliation of Income Tax Expense

Year ended December 31 (millions of dollars)

  2004

  2003

  2002

 
Income from continuing operations before income taxes and non-controlling interests   1,549   1,396   1,322  
   
 
 
 
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 affiliates   (9 ) (11 ) (2 )
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 and PPAs   456   396
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-31


NOTE 17    NOTES PAYABLE

 
  2004
  2003
 
  Outstanding December 31 (millions of dollars)
  Weighted Average Interest Rate
Per Annum at December 31

  Outstanding December 31 (millions of dollars)
  Weighted Average Interest Rate
Per Annum at 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-32



Reconciliation of Asset Retirement Obligations

(millions of dollars)

  Gas Transmission

  Power

  Total

 
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-33



 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 Plans

  Other Benefit 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 regulated business         25  
   
 
 
 
 
Accrued benefit asset/(liability), net of valuation allowance of nil   164   143   (65 ) (36 )
   
 
 
 
 

F-34


 The accrued benefit (asset)/liability, net of valuation allowance, is included in the Company's balance sheet as follows.

 
  Pension Benefit Plans

  Other Benefit 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 Plans

  Other Benefit 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 Benefits
  Other 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 Plans

  Other Benefit Plans

 
  2004

  2003

  2004

  2003

Discount rate   5.75%   6.00%   6.00%   6.25%
Rate of compensation increase   3.50%   3.50%        

F-35


 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 return on plan assets   6.90%   7.25%   7.52%            
Rate of compensation increase   3.50%   3.75%   3.50%            

 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-36


 The Company's net benefit cost is as follows.

 
  Pension Benefit Plans

  Other Benefit Plans

 
Year ended December 31 (millions of dollars)

  2004

  2003

  2002

  2004

  2003

  2002

 
Current service cost   28   25   11   3   2   2  
Interest cost   58   52   43   7   6   4  
Actual return on plan assets   (97 ) (89 ) (9 ) 1      
Actuarial loss   46   66   93   (12 ) 7   26  
Plan amendment       92       7  
   
 
 
 
 
 
 
Elements of net benefit cost prior to adjustments to recognize the long-term nature of net benefit cost   35   54   230   (1 ) 15   39  
   
 
 
 
 
 
 
Difference between expected and actual return on plan assets   39   38   (36 ) (1 )    
Difference between actuarial loss recognized and actual actuarial loss on accrued benefit obligation   (32 ) (58 ) (91 ) 13   (6 ) (26 )
Difference between amortization of past service costs and actual plan amendments   3   3   (92 )   1   (7 )
Amortization of transitional obligation related to regulated business         2   2   2  
   
 
 
 
 
 
 
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
Plan Assets

  Target 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-37



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 Lease Payments

  Amounts Recoverable under Sub-Leases

  Net Payments

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-38



 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-39


NOTE 23    U.S. GAAP (Restated(13))

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)

  Restated 2004

  Restated 2003

  Restated 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)(12)(13)   806   851   860  
  Dilution gain(12)   (40 )    
  Income taxes   490   515   499  
   
 
 
 
    903   1,032   1,099  
   
 
 
 
Income from continuing operations — U.S. GAAP   862   813   764  
Net income from discontinued operations — U.S. GAAP   52   50    
   
 
 
 
Income before cumulative effect of the application of accounting changes in accordance with U.S. GAAP   914   863   764  
Cumulative effect of the application of accounting changes, net of tax(3)     (13 )  
   
 
 
 
Net Income in Accordance with U.S. GAAP   914   850   764  
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   956   802   721  
   
 
 
 

F-40


Reconciliation of Income from Continuing Operations

Year ended December 31 (millions of dollars)

  Restated 2004

  Restated 2003

  Restated 2002

 
Net Income from Continuing Operations in Accordance with Canadian GAAP   1,031   859   805  
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 rate derivatives(5)   (12 ) (9 ) 30  
  Tax impact of (loss)/gain on foreign exchange and interest rate derivatives   4   3   (12 )
  Unrealized gain/(loss) on energy marketing contracts(3)   10   28   (21 )
  Tax impact of unrealized gain/(loss) on energy marketing contracts   (3 ) (10 ) 8  
  Equity loss(7)   (2 ) (18 )  
  Tax impact of equity loss     6    
  Amortization of deferred gains related to Power LP(12)(13)   (3 ) (10 ) (10 )
  Deferred gains related to Power LP(12)(13)   (132 )    
   
 
 
 
Income from Continuing Operations in Accordance with U.S. GAAP   862   813   764  
   
 
 
 

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 Short-Term Investments

 

(87

)

(52

)

(3

)
   
 
 
 
(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-41


Condensed Balance Sheet in Accordance with U.S. GAAP(1)

December 31 (millions of dollars)

  2004

  Restated
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)(12)(13)   803   692
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(12)(13)   6,831   6,456
   
 
    23,718   22,636
   
 

F-42


Statement of Other Comprehensive Income in Accordance with U.S. GAAP

(millions of dollars)

  Cumulative Translation Account

  Minimum Pension Liability (SFAS No. 87)

  Cash Flow Hedges (SFAS No. 133)

  Total

 
Balance at January 1, 2002   13   (56 ) (9 ) (52 )
Changes in minimum pension liability, net of tax of $22(4)     (40 )   (40 )
Unrealized loss on derivatives, net of tax of $(1)(5)       (4 ) (4 )
Foreign currency translation adjustment, net of tax of nil   1       1  
   
 
 
 
 
Balance at December 31, 2002   14   (96 ) (13 ) (95 )

Changes in minimum pension liability, net of tax of $1(4)

 


 

(2

)


 

(2

)
Unrealized gain on derivatives, net of tax of nil(5)       8   8  
Foreign currency translation adjustment, net of tax of $(64)   (54 )     (54 )
   
 
 
 
 
Balance at December 31, 2003   (40 ) (98 ) (5 ) (143 )

Changes in minimum pension liability, net of tax of $(39)(4)

 


 

72

 


 

72

 
Unrealized gain on derivatives, net of tax of $(3)(5)       1   1  
Foreign currency translation adjustment, net of tax of $(44)   (31 )     (31 )
   
 
 
 
 
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.

F-43


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 )
   
 
 

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.

F-44


(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).

(12)
The Company records its investment in Power LP using the proportionate consolidation method for Canadian GAAP purposes and as an equity investment for U.S. GAAP purposes. During the period from 1997 to April 2004, the Company was obligated to fund the redemption of Power LP units in 2017. As a result, under Canadian GAAP, TCPL accounted for the issuance of units by Power LP to third parties as a sale of a future net revenue stream and the resulting gains were deferred and amortized to income over the period to 2017. The redemption obligation was removed in April 2004 and the unamortized gains were recognized as income. Under U.S. GAAP, any such gains in the period from 1997 to April 2004 are characterized as dilution gains and, because the Company was committed to fund the redemption of the units, the gains are recorded, on an after-tax basis, as equity transactions in shareholders' equity.

The Company's accounting policy for dilution gains is to record them as income for both Canadian and U.S. GAAP purposes, however, U.S. GAAP requires such gains to be recorded directly in equity if there is a contemplation of reacquisition of units. With the removal of the redemption obligation in April 2004, subsequent issuances of units by Power LP are accounted for as dilution gains in income for both Canadian and U.S. GAAP purposes (see Note 8).

F-45


(13)
Correction of Error:

In the period 1997 to 2001, the Company recorded certain transactions involving Power LP as sales of a revenue stream for both Canadian and U.S. GAAP purposes. For U.S. GAAP purposes, these transactions should have been accounted for as dilution gains (see footnote 12 above). This has been corrected on a retroactive basis. The impact on previously reported amounts for U.S. GAAP purposes is as follows:

December 31 (millions of dollars)

  2004

  2003

  2002

Decrease in:            
Income from continuing operations   135   10   10
Net income   135   10   10

    For U.S. GAAP purposes, the correction had no impact on the accumulated shareholders' equity at December 31, 2004 and the impact at December 31, 2003 was an increase of $135 million.

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 and PPAs   1,741   1,813
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 long-term investments   353   334   260  
   
 
 
 
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



COMMENTS BY AUDITORS FOR U.S. READERS ON CANADA-U.S. REPORTING DIFFERENCE

 In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when there is a change in accounting principles that has a material effect on the comparability of the Company's financial statements, such as the changes described in Note 2 — Accounting Changes — to the Company's revised consolidated financial statements as at December 31, 2004 and 2003, and for each of the years in the three-year period ended December 31, 2004 which are incorporated by reference herein. Our report to the shareholders dated February 28, 2005, except as to note 23 which is as of July 28, 2005, which is incorporated by reference herein, is expressed in accordance with Canadian reporting standards which do not require a reference to such a change in accounting principles in the auditors' report when the change is properly accounted for and adequately disclosed in the financial statements.

Chartered Accountants

SIGNATURE

Calgary, Canada

February 28, 2005, except
as to note 23 which is
as of July 28, 2005




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EXPLANATORY NOTE
UNDERTAKING
SIGNATURES
AUDITORS' REPORT
TRANSCANADA PIPELINES LIMITED CONSOLIDATED INCOME
TRANSCANADA PIPELINES LIMITED CONSOLIDATED CASH FLOWS
TRANSCANADA PIPELINES LIMITED CONSOLIDATED BALANCE SHEET
TRANSCANADA PIPELINES LIMITED CONSOLIDATED RETAINED EARNINGS
TRANSCANADA PIPELINES LIMITED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
COMMENTS BY AUDITORS FOR U.S. READERS ON CANADA-U.S. REPORTING DIFFERENCE
EX-23.1 2 a2160607zex-23_1.htm EXHIBIT 23.1
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Exhibit 23.1


ACCOUNTANTS' CONSENT

To:   The Board of Directors
TransCanada PipeLines Limited

 We consent to the use of our report dated February 28, 2005, except as to note 23 of the revised consolidated financial statements which is as of July 28, 2005, on the consolidated balance sheets of TransCanada PipeLines Limited (the "Company") 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 and our Comments for U.S. Readers on Canada — U.S. Reporting Difference, dated February 28, 2005, except as to note 23 of the revised consolidated financial statements which is as of July 28, 2005, both of which are incorporated by reference in this Annual Report on Form 40-F of the Company for the year ended December 31, 2004.

 We also consent to incorporation by reference of our report and Comments for U.S. Readers on Canada — U.S. Reporting Difference in the Amendment No. 1 on Form F-9 dated December 21, 2004 to the Registration Statement (No. 333-121265) on Form F-9 dated December 15, 2004 of TransCanada PipeLines Limited.

Chartered Accountants

SIGNATURE

Calgary, Canada

February 28, 2005, except
as to note 23 which is
as of July 28, 2005




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ACCOUNTANTS' CONSENT
EX-31.1 3 a2160607zex-31_1.htm EXHIBIT 31.1
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Exhibit 31.1


CERTIFICATIONS

I, Harold N. Kvisle, certify that:

1.
I have reviewed this annual report on Form 40-F/A of TransCanada PipeLines Limited;

2.
Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; and

3.
Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report.

Dated August 2, 2005

    By: /s/  HAROLD N. KVISLE      
Harold N. Kvisle
President and Chief Executive Officer



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CERTIFICATIONS
EX-31.2 4 a2160607zex-31_2.htm EXHIBIT 31.2
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Exhibit 31.2


CERTIFICATIONS

I, Russell K. Girling, certify that:

1.
I have reviewed this annual report on Form 40-F/A of TransCanada PipeLines Limited;

2.
Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; and

3.
Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report.

Dated August 2, 2005

    By: /s/  RUSSELL K. GIRLING      
Russell K. Girling
Executive Vice-President, Corporate Development
and Chief Financial Officer



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CERTIFICATIONS
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