U.S. Securities and Exchange CommissionWashington, 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    1-31690
|------------------------------------------------------ |  | ---------------------------------

TRANSCANADA CORPORATION(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 registeredCommon Shares (including Rights under Shareholder Rights Plan)

New York Stock Exchange


Securities
registered pursuant to Section 12(g) of the Act:NoneSecurities 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, 484,914,323 common shares
were issued and outstanding

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




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The documents (or portions thereof) forming part of this Form 40-F/A are incorporated by reference into the following registration statements under the
Securities Act of 1933, as amended:

|Form |  | Registration
No.
|---- |  | ----------------
|S-8  |  | 33-00958        
|S-8  |  | 333-5916        
|S-8  |  | 333-8470        
|S-8  |  | 333-9130        
|F-3  |  | 33-13564        
|F-3  |  | 333-6132        

EXPLANATORY NOTE

TransCanada Corporation ("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 14, 2005, to refile its 2004 Consolidated Financial Statements, which contains a restated Note 22 (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 22
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.

2

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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 CORPORATION
| |  | -----------------------
| |  | Per:                   
| |  |                        

3

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DOCUMENTS FILED AS PART OF THIS REPORT

|13.1 |  | Restated 2004 Consolidated Audited Financial Statements (included on pages 68 through 108 of the TransCanada 2004 Annual Report to Shareholders).                                 
|---- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|13.2 |  | U.S. GAAP reconciliation of the Restated 2004 Consolidated Audited Financial Statements (included on pages 101 through 108 of the TransCanada 2004 Annual Report to Shareholders).
|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.

4

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67


AUDITORS REPORT To the Shareholders of
TransCanada Corporation  We have audited the consolidated balance sheets of
TransCanada Corporation 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 audits. We conducted our audits in accordance with Canadian
generally accepted auditing standards. 
Those standards require that we plan and perform an audit to obtain
reasonable assurance whether the financial statements are free of material
misstatement.  An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements.  An audit also
includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. In our opinion, these 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
22 to the revised consolidated financial statements.   Chartered Accountants  /s/ KPMG LLP Calgary, Canada February 28, 2005, except as to note 22 which is as of July 28, 2005   68


CONSOLIDATED
INCOME  Year ended December 31 (millions of dollars except per share
  amounts)
  
  2004
  
  2003
  
  2002Revenues
  
  5,107
  
  5,357
  
  5,214Operating ExpensesCost of sales
  
  539
  
  692
  
  627Other costs and expenses
  
  1,635
  
  1,682
  
  1,546Depreciation
  
  945
  
  914
  
  8483,119
  
  3,288
  
  3,021Operating Income
  
  1,988
  
  2,069
  
  2,193Other Expenses/(Income)Financial charges (Note 9)
  
  810
  
  821
  
  867Financial charges of joint
  ventures
  
  60
  
  77
  
  90Equity income (Note 7)
  
  (171
  )
  (165
  )
  (33
  )Interest income and other
  
  (65
  )
  (60
  )
  (53
  )Gains related to Power LP
  (Note 8)
  
  (197
  )
  
  
  437
  
  673
  
  871Income from Continuing
  Operations before Income Taxes and
  Non-Controlling Interests
  
  1,551
  
  1,396
  
  1,322Income Taxes(Note 15)Current
  
  431
  
  305
  
  270Future
  
  77
  
  230
  
  247508
  
  535
  
  517Non-Controlling Interests(Note 12)
  
  63
  
  60
  
  58Net Income from Continuing
  Operations
  
  980
  
  801
  
  747Net Income from Discontinued
  Operations(Note
  21)
  
  52
  
  50
  
  Net Income
  
  1,032
  
  851
  
  747Net Income Per Share(Note 13)BasicContinuing operations
  
  $
  2.02
  
  $
  1.66
  
  $
  1.56Discontinued operations
  
  0.11
  
  0.10
  
  $
  2.13
  
  $
  1.76
  
  $
  1.56DilutedContinuing operations
  
  $
  2.01
  
  $
  1.66
  
  $
  1.55Discontinued operations
  
  0.11
  
  0.10
  
  $
  2.12
  
  $
  1.76
  
  $
  1.55  The accompanying notes to
the consolidated financial statements are an integral part of these statements.  69


CONSOLIDATED
CASH FLOWS  Year ended December 31 (millions of dollars)
  
  2004
  
  2003
  
  2002Cash Generated from OperationsNet income from continuing
  operations
  
  980
  
  801
  
  747Depreciation
  
  945
  
  914
  
  848Future income taxes
  
  77
  
  230
  
  247Gains related to Power LP
  
  (197
  )
  
  
  Equity income in excess of
  distributions received (Note 7)
  
  (123
  )
  (119
  )
  (6
  )Non-controlling interests
  
  63
  
  60
  
  58Pension funding in excess
  of expense
  
  (29
  )
  (65
  )
  (33
  )Other
  
  (42
  )
  (11
  )
  (34
  )Funds generated from
  continuing operations
  
  1,674
  
  1,810
  
  1,827Decrease in operating working
  capital (Note 19)
  
  34
  
  112
  
  33Net cash provided by
  continuing operations
  
  1,708
  
  1,922
  
  1,860Net cash (used
  in)/provided by discontinued operations
  
  (6
  )
  (17
  )
  591,702
  
  1,905
  
  1,919Investing ActivitiesCapital 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 ActivitiesDividends and preferred
  securities charges
  
  (623
  )
  (588
  )
  (546
  )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
  
  44Reduction of non-recourse
  debt of joint ventures
  
  (113
  )
  (71
  )
  (80
  )Partnership units of joint
  ventures issued
  
  88
  
  
  
  Common shares issued
  
  32
  
  65
  
  50Redemption of junior
  subordinated debentures
  
  
  
  (218
  )
  Net cash used in financing
  activities
  
  (159
  )
  (628
  )
  (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
  )
  126
  
  (87
  )Cash and Short-Term InvestmentsBeginning of year
  
  338
  
  212
  
  299Cash and Short-Term InvestmentsEnd of year
  
  188
  
  338
  
  212  The accompanying notes to
the consolidated financial statements are an integral part of these statements.  70


CONSOLIDATED
BALANCE SHEET  December 31 (millions of dollars)
  
  2004
  
  2003ASSETSCurrent AssetsCash and short-term
  investments
  
  188
  
  338Accounts receivable
  
  627
  
  605Inventories
  
  174
  
  165Other
  
  120
  
  881,109
  
  1,196Long-Term Investments(Note 7)
  
  840
  
  733Plant, Property and Equipment(Notes 4, 9 and 10)
  
  18,704
  
  17,415Other Assets(Note 5)
  
  1,477
  
  1,35722,130
  
  20,701LIABILITIES AND SHAREHOLDERS
  EQUITYCurrent LiabilitiesNotes payable (Note 16)
  
  546
  
  367Accounts payable
  
  1,135
  
  1,087Accrued interest
  
  214
  
  208Current portion of
  long-term debt (Note 9)
  
  766
  
  550Current portion of
  non-recourse debt of joint ventures (Note 10)
  
  83
  
  192,744
  
  2,231Deferred Amounts(Note 11)
  
  666
  
  561Long-Term Debt(Note 9)
  
  9,713
  
  9,465Future Income Taxes(Note 15)
  
  509
  
  427Non-Recourse Debt of Joint
  Ventures(Note 10)
  
  779
  
  761Preferred Securities(Note 12)
  
  19
  
  2214,430
  
  13,467Non-Controlling Interests(Note 12)
  
  1,135
  
  1,143Shareholders EquityCommon shares (Note 13)
  
  4,711
  
  4,679Contributed surplus
  
  270
  
  267Retained earnings
  
  1,655
  
  1,185Foreign exchange
  adjustment (Note 14)
  
  (71
  )
  (40
  )6,565
  
  6,091Commitments, Contingencies and
  Guarantees(Note
  20)
  
  22,130
  
  20,701  The accompanying notes to
the consolidated financial statements are an integral part of these statements.  On behalf of the Board:/s/ Harold N. Kvisle
  
  
  /s/ Harry G. SchaeferHarold N.
  Kvisle
  
  Harry G.
  SchaeferDirector
  
  Director  71


CONSOLIDATED
RETAINED EARNINGS  Year ended December 31 (millions of dollars)
  
  2004
  
  2003
  
  2002Balance at beginning of
  year
  
  1,185
  
  854
  
  586Net income
  
  1,032
  
  851
  
  747Common share dividends
  
  (562
  )
  (520
  )
  (479
  )1,655
  
  1,185
  
  854  The accompanying notes to
the consolidated financial statements are an integral part of these statements.  72


NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS  TransCanada Corporation (the
Company or TransCanada) is a leading North American energy company. TransCanada
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 22. 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
PresentationPursuant
to a plan of arrangement, effective May 15, 2003, common shares of
TransCanada PipeLines Limited (TCPL) were exchanged on a one-to-one basis for
common shares of TransCanada. As a result, TCPL became a wholly-owned
subsidiary of TransCanada. The consolidated financial statements for the years
ended December 31, 2004 and 2003 include the accounts of TransCanada, the
consolidated accounts of all subsidiaries, including TCPL, and TransCanadas
proportionate share of the accounts of the Companys joint venture investments.
Comparative information for the year ended December 31, 2002 is that of
TCPL, its subsidiaries and its proportionate share of the accounts of its joint
venture investments at that time.  73


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, TransCanada
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 TransCanada, and Foothills
was consolidated subsequent to that date.  TransCanada uses the equity
method of accounting for investments over which the Company is able to exercise
significant influence.  RegulationThe 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 InvestmentsThe 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.  InventoriesInventories 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 TransmissionPlant, 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.  PowerPlant,
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.  CorporateCorporate 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 ArrangementsPower purchase arrangements (PPAs) are long-term contracts to purchase
or sell power on a predetermined basis. The initial payments for PPAs acquired
by TransCanada 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 TransCanada sells power are accounted for as operating leases and,
accordingly, the related plant, property and equipment are accounted for as
assets under operating leases.  Stock
OptionsTransCanadas
Stock Option Plan permits the award of options to purchase the Companys common
shares to certain employees, some of whom are officers. The contractual life of
options granted prior to 2003 is ten years and for options granted in 2003 and
subsequently, the contractual life is seven years. Options may be exercised at
a price determined at the time the option is awarded. Generally, for awards
granted prior to 2003, 25 per cent of the options vest on the award date and 25
per cent on each of the three following award date anniversaries. For awards
granted subsequent to 2002, no options vest on the award date and 33.3 per cent
vest on each of the three following award date anniversaries. Effective
January 1, 2002, TransCanada adopted the fair value method of accounting
for stock options. The Company is recording compensation expense over the three
year vesting period. This charge is reflected in the Gas Transmission and Power
segments.  74


Income
TaxesAs
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 TranslationMost 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 TransCanada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 InstrumentsThe 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 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 PlansThe 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.  75


The Company has broad-based,
medium-term employee incentive plans, which grant units to each eligible
employee. Under these plans, units vest when certain conditions are met,
including the employees continued employment during a specified period and
achievement of specified corporate performance targets. The units under one of
these incentive plans vested at the end of 2004 and the Company recorded
compensation expense over the three year vesting period. The value of units
under this plan, net of income tax, will be paid in cash in 2005.  NOTE 2
 Accounting Changes  Asset
Retirement ObligationsEffective 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.  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
TransCanada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 17.  Hedging
RelationshipsEffective
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 TransCanada
applied prospectively, had no significant impact on net income for the year
ended December 31, 2004.  Generally
Accepted Accounting PrinciplesEffective 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
  
  153Deferred amounts
  
  80Long-term debt
  
  76Preferred securities
  
  (3
  )Total liabilities
  
  153  76


NOTE 3
 Segmented Information  Net
Income/(Loss)(1)  Year ended December 31, 2004 (millions of dollars)
  
  Gas
  Transmission
  
  Power
  
  Corporate
  
  TotalRevenues
  
  3,917
  
  1,190
  
  
  
  5,107Cost 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
  )
  1,988Financial charges and
  non-controlling interests
  
  (785
  )
  (9
  )
  (79
  )
  (873
  )Financial charges of joint
  ventures
  
  (56
  )
  (4
  )
  
  
  (60
  )Equity income
  
  41
  
  130
  
  
  
  171Interest income and other
  
  14
  
  14
  
  37
  
  65Gains related to Power LP
  
  
  
  197
  
  
  
  197Income taxes
  
  (447
  )
  (104
  )
  43
  
  (508
  )Continuing operations
  
  586
  
  396
  
  (2
  )
  980Discontinued operations
  
  
  
  
  
  
  
  52Net Income
  
  
  
  
  
  
  
  1,032Year ended December 31,
  2003 (millions of dollars)Revenues
  
  3,956
  
  1,401
  
  
  
  5,357Cost 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
  )
  2,069Financial charges and
  non-controlling interests
  
  (781
  )
  (11
  )
  (89
  )
  (881
  )Financial charges of joint
  ventures
  
  (76
  )
  (1
  )
  
  
  (77
  )Equity income
  
  66
  
  99
  
  
  
  165Interest income and other
  
  17
  
  14
  
  29
  
  60Income taxes
  
  (459
  )
  (103
  )
  27
  
  (535
  )Continuing operations
  
  622
  
  220
  
  (41
  )
  801Discontinued operations
  
  
  
  
  
  
  
  50Net Income
  
  
  
  
  
  
  
  851Year ended December 31,
  2002 (millions of dollars)Revenues
  
  3,921
  
  1,293
  
  
  
  5,214Cost 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
  )
  2,193Financial charges and
  non-controlling interests
  
  (821
  )
  (13
  )
  (91
  )
  (925
  )Financial charges of joint
  ventures
  
  (90
  )
  
  
  
  
  (90
  )Equity income
  
  33
  
  
  
  
  
  33Interest income and other
  
  17
  
  13
  
  23
  
  53Income taxes
  
  (458
  )
  (84
  )
  25
  
  (517
  )Continuing operations
  
  653
  
  146
  
  (52
  )
  747Discontinued operations
  
  
  
  
  
  
  
  Net Income
  
  
  
  
  
  
  
  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.  77


Total
Assets  December 31 (millions of dollars)
  
  2004
  
  2003Gas Transmission
  
  18,428
  
  17,064Power
  
  2,802
  
  2,753Corporate
  
  893
  
  873Continuing operations
  
  22,123
  
  20,690Discontinued operations
  
  7
  
  1122,130
  
  20,701  Geographic
Information  Year
  ended December 31 (millions of dollars)
  
  2004
  
  2003
  
  2002 (4)Revenues(3)Canada  domestic
  
  3,147
  
  3,257
  
  2,731Canada  export
  
  1,261
  
  1,293
  
  1,641United States
  
  699
  
  807
  
  8425,107
  
  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.  Plant,
Property and Equipment  December 31 (millions of dollars)
  
  2004
  
  2003Canada
  
  14,757
  
  15,156United States
  
  3,947
  
  2,25918,704
  
  17,415  Capital
Expenditures  Year ended December 31 (millions of dollars)
  
  2004
  
  2003
  
  2002Gas Transmission
  
  187
  
  256
  
  382Power
  
  285
  
  132
  
  193Corporate and Other
  
  4
  
  3
  
  24476
  
  391
  
  599  78


NOTE 4
 Plant, Property and Equipment  2004
  
  2003December 31 (millions of dollars)
  
  Cost
  
  Accumulated
  Depreciation
  
  Net
  Book Value
  
  Cost
  
  Accumulated
  Depreciation
  
  Net
  Book ValueGas TransmissionCanadian MainlinePipeline
  
  8,695
  
  3,421
  
  5,274
  
  8,683
  
  3,176
  
  5,507Compression
  
  3,322
  
  947
  
  2,375
  
  3,318
  
  832
  
  2,486Metering and other
  
  366
  
  125
  
  241
  
  404
  
  132
  
  27212,383
  
  4,493
  
  7,890
  
  12,405
  
  4,140
  
  8,265Under construction
  
  16
  
  
  
  16
  
  12
  
  
  
  1212,399
  
  4,493
  
  7,906
  
  12,417
  
  4,140
  
  8,277Alberta SystemPipeline
  
  4,978
  
  2,055
  
  2,923
  
  4,934
  
  1,908
  
  3,026Compression
  
  1,496
  
  599
  
  897
  
  1,507
  
  549
  
  958Metering and other
  
  861
  
  262
  
  599
  
  862
  
  211
  
  6517,335
  
  2,916
  
  4,419
  
  7,303
  
  2,668
  
  4,635Under construction
  
  20
  
  
  
  20
  
  13
  
  
  
  137,355
  
  2,916
  
  4,439
  
  7,316
  
  2,668
  
  4,648GTN (1)Pipeline
  
  1,131
  
  9
  
  1,122Compression
  
  726
  
  2
  
  724Metering and other
  
  187
  
  1
  
  1862,044
  
  12
  
  2,032Under construction
  
  17
  
  
  
  172,061
  
  12
  
  2,049Foothills SystemPipeline
  
  815
  
  346
  
  469
  
  834
  
  317
  
  517Compression
  
  373
  
  114
  
  259
  
  378
  
  99
  
  279Metering and other
  
  78
  
  35
  
  43
  
  60
  
  35
  
  251,266
  
  495
  
  771
  
  1,272
  
  451
  
  821Joint Ventures and other
  
  3,213
  
  1,053
  
  2,160
  
  3,361
  
  1,052
  
  2,30926,294
  
  8,969
  
  17,325
  
  24,366
  
  8,311
  
  16,055Power(2)Power generation
  facilities
  
  1,397
  
  375
  
  1,022
  
  1,439
  
  381
  
  1,058Other
  
  77
  
  45
  
  32
  
  84
  
  41
  
  431,474
  
  420
  
  1,054
  
  1,523
  
  422
  
  1,101Under construction
  
  288
  
  
  
  288
  
  209
  
  
  
  2091,762
  
  420
  
  1,342
  
  1,732
  
  422
  
  1,310Corporate
  
  124
  
  87
  
  37
  
  122
  
  72
  
  5028,180
  
  9,476
  
  18,704
  
  26,220
  
  8,805
  
  17,415  
 (1)     TransCanada 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.  79


NOTE 5
 Other Assets  December 31 (millions of dollars)
  
  2004
  
  2003Derivative contracts
  
  253
  
  118PPAs  Canada (1)
  
  274
  
  278PPAs  U.S. (1)
  
  98
  
  248Pension and other benefit
  plans
  
  209
  
  201Regulatory deferrals
  
  199
  
  212Loans and advances (2)
  
  135
  
  111Goodwill
  
  58
  
  Other
  
  251
  
  1891,477
  
  1,357  
 (1)     The following amounts related to the PPAs are included in the
consolidated financial statements.  2004
  
  2003December 31 (millions of
  dollars)
  
  Cost
  
  Accumulated
  Amortization
  
  Net
  Book Value
  
  Cost
  
  Accumulated
  Amortization
  
  Net
  Book ValuePPAs  Canada
  
  345
  
  71
  
  274
  
  329
  
  51
  
  278PPAs  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  TransCanadas Proportionate
  ShareIncome Before Income Taxes
  Year ended December 31
  
  Net Assets
  December 31(millions of dollars)
  
  Ownership Interest
  
  2004
  
  2003
  
  2002
  
  2004
  
  2003Gas TransmissionGreat Lakes
  
  50.0
  %(1)
  86
  
  81
  
  102
  
  379
  
  419Iroquois
  
  41.0
  %(1)
  28
  
  31
  
  30
  
  175
  
  169TC PipeLines, LP
  
  33.4
  %
  22
  
  21
  
  24
  
  124
  
  130Trans Québec &
  Maritimes
  
  50.0
  %
  13
  
  14
  
  13
  
  75
  
  77CrossAlta
  
  60.0
  %(1)
  20
  
  11
  
  21
  
  24
  
  25Foothills
  
  
  (2)
  
  
  19
  
  29
  
  
  
  Other
  
  Various
  
  6
  
  7
  
  7
  
  27
  
  22PowerPower LP
  
  30.6
  %(3)
  32
  
  25
  
  26
  
  289
  
  234ASTC Power Partnership
  
  50.0
  %(4)
  
  
  
  
  
  
  93
  
  99207
  
  209
  
  252
  
  1,186
  
  1,175  
 (1)     Great Lakes Gas Transmission Limited Partnership (Great Lakes);
Iroquois Gas Transmission System, L.P. (Iroquois); CrossAlta Gas
Storage & Services Ltd. (CrossAlta). (2)     In August 2003, the Company acquired the remaining
interests in Foothills previously not held by TransCanada, 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 TransCanada.  Consolidated retained
earnings at December 31, 2004 include undistributed earnings from these
joint ventures of $509 million (2003  $509 million).  80


Summarized Financial Information of Joint Ventures  Year ended December 31 (millions of
  dollars)
  
  2004
  
  2003
  
  2002IncomeRevenues
  
  559
  
  623
  
  680Other 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
  
  252Year
  ended December 31 (millions of dollars)
  
  2004
  
  2003
  
  2002Cash FlowsOperations
  
  269
  
  272
  
  323Investing 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
  
  2003Balance SheetCash and short-term
  investments
  
  64
  
  55Other current assets
  
  133
  
  106Long-term investments
  
  105
  
  118Plant, property and
  equipment
  
  1,644
  
  1,693Other assets and deferred
  amounts (net)
  
  221
  
  109Current 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  81


NOTE 7
 Long-Term Investments  TransCanadas ShareDistributions 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
  
  2003PowerBruce Power
  
  31.6
  %
  
  
  
  
  
  
  130
  
  99
  
  
  
  642
  
  513Gas TransmissionNorthern Border
  
  10.0
  %(1)
  27
  
  22
  
  26
  
  23
  
  22
  
  25
  
  91
  
  103TransGas de Occidente S.A.
  
  46.5
  %
  8
  
  8
  
  
  
  11
  
  27
  
  5
  
  78
  
  80Portland
  
  61.7
  %(2)
  
  
  10
  
  
  
  
  
  14
  
  2
  
  
  
  Other
  
  Various
  
  13
  
  6
  
  1
  
  7
  
  3
  
  1
  
  29
  
  3748
  
  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  GTNOn
November 1, 2004, TransCanada 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
  
  45Plant, property and
  equipment
  
  1,712Other non-current assets
  
  30Goodwill
  
  48Current 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 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 TransCanada subsequent to the
acquisition date and included in the Gas Transmission segment.  82


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
  
  281Capital lease
  
  301Power 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 LPOn April 30, 2004, TransCanada 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, TransCanada 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 TransCanada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 TransCanada at June 30, 2017. TransCanada 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
TransCanada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.  83


NOTE 9
 Long-Term Debt  2004
  
  2003Maturity
  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
  BondsPounds Sterling (2004 and
  2003  £25)
  
  2007
  
  58
  
  16.5
  %
  58
  
  16.5
  %DebenturesCanadian 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 NotesCanadian 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
  
  
  
  4,853Alberta System(4)Debentures and NotesCanadian 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 NotesCanadian 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
  
  
  
  2,325GTN(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
  
  
  
  380Portland(6)Senior Secured NotesU.S. dollars (2004 
  US$256; 2003  US$271)
  
  2018
  
  308
  
  5.9
  %
  350
  
  5.9
  %OtherMedium-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
  
  
  
  2,10710,479
  
  
  
  10,015Less: Current Portion of
  Long-Term Debt
  
  
  
  766
  
  
  
  5509,713
  
  
  
  9,465  84


(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
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
RepaymentsPrincipal
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
ProgramsAt
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 BondsThe 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  DebenturesDebentures 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
NotesMedium-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 NotesSenior
unsecured notes amounting to US$250 million are redeemable by the Company at
any time on or after June 1, 2005.  OTHER  Medium-Term
NotesMedium-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
  
  2002Interest on long-term debt
  
  805
  
  801
  
  850Regulatory deferrals and
  amortizations
  
  (31
  )
  (14
  )
  (17
  )Short-term interest and
  other financial charges
  
  36
  
  34
  
  34810
  
  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).  85


NOTE 10
Non-Recourse Debt of Joint Ventures  2004
  
  2003Maturity
  Dates
  
  Outstanding
  December 31 (1)
  
  Weighted
  Average
  Interest
  Rate (2)
  
  Outstanding
  December 31 (1)
  
  Weighted
  Average
  Interest
  Rate (2)Great LakesSenior Unsecured Notes(2004  US$235; 2003 
  US$240)
  
  2011 to 2030
  
  283
  
  7.9
  %
  310
  
  7.9
  %IroquoisSenior 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 &
  MaritimesBonds
  
  2005 to 2010
  
  143
  
  7.3
  %
  143
  
  7.3
  %Term Loan
  
  2006
  
  29
  
  3.2
  %
  34
  
  3.5
  %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
  
  
  
  780Less: Current Portion of
  Non-Recourse Debt of Joint Ventures
  
  
  
  83
  
  
  
  19779
  
  
  
  761  
 (1)     Amounts outstanding
represent TransCanada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 LP Credit Facility  5.2 per cent.  The debt of joint ventures
is non-recourse to TransCanada. 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 TransCanada, except to the extent of TransCanada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
  
  2003Derivative contracts
  
  209
  
  40Regulatory deferrals
  
  229
  
  131Other benefit plans
  
  63
  
  32Deferred revenue
  
  58
  
  215Asset retirement
  obligation
  
  36
  
  9Other
  
  71
  
  134666
  
  561  86


NOTE 12
Non-Controlling Interests and Preferred Securities  The Companys
non-controlling interests included in the consolidated balance sheet are as
follows.  December 31 (millions of dollars)
  
  2004
  
  2003Preferred securities of
  subsidiary
  
  670
  
  672Preferred shares of
  subsidiary
  
  389
  
  389Other
  
  76
  
  821,135
  
  1,143  The Companys
non-controlling interests included in the consolidated income statement are as
follows.  Year ended December 31 (millions of dollars)
  
  2004
  
  2003
  
  2002Preferred securities
  charges
  
  31
  
  36
  
  36Preferred share dividends
  
  22
  
  22
  
  22Other
  
  10
  
  2
  
  63
  
  60
  
  58  Preferred
Securities of Subsidiary  The US$460 million 8.25 per
cent preferred securities of TCPL (Preferred Securities) are redeemable by the
issuer at par at any time. The issuer 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
issuer, the Preferred Securities are classified into their respective debt and
non-controlling interest 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 non-controlling interest 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 non-controlling interest
component of Preferred Securities will be classified as debt.  Preferred
Shares of Subsidiary  December 31
  
  Number
  of Shares
  
  Dividend
  Rate
  Per Share
  
  Redemption
  Price
  Per Share
  
  2004
  
  2003(thousands)
  
  
  
  
  
  (millions of dollars)Cumulative First Preferred
  Shares of SubsidiarySeries U
  
  4,000
  
  $
  2.80
  
  $
  50.00
  
  195
  
  195Series Y
  
  4,000
  
  $
  2.80
  
  $
  50.00
  
  194
  
  194389
  
  389  The authorized number of
preferred shares of TCPL issuable in series is unlimited. All of the cumulative
first preferred shares of subsidiary 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 issuer may redeem the shares at $50 per share.  OtherOther non-controlling interests are primarily
comprised of the 38.3 per cent non-controlling interest in Portland. Revenues
received from Portland with respect to services provided by TransCanada for the
year ended December 31, 2004 were $4 million (2003 and 2002  nil).  87


NOTE 13
Common Shares  Numberof Shares
  
  Amount(thousands)
  
  (millions of dollars)Outstanding at
  January 1, 2002
  
  476,631
  
  4,564Exercise of options
  
  2,871
  
  50Outstanding at
  December 31, 2002
  
  479,502
  
  4,614Exercise of options
  
  3,698
  
  65Outstanding at
  December 31, 2003
  
  483,200
  
  4,679Exercise of options
  
  1,714
  
  32Outstanding at
  December 31, 2004
  
  484,914
  
  4,711  Common
Shares Issued and OutstandingThe Company is authorized to issue an unlimited number of common shares
of no par value.  Net Income
Per ShareBasic and
diluted earnings per share are calculated based on the weighted average number
of common shares outstanding during the year of 484.1 million and 486.7 million
(2003  481.5 million and 483.9 million; 2002  478.3 million and 480.7
million), respectively. The increase in the weighted average number of shares
for the diluted earnings per share calculation is due to the options
exercisable under TransCanadas Stock Option Plan.  Stock Options  Number
  of Options
  
  Weighted Average
  Exercise Prices
  
  Options
  Exercisable(thousands)
  
  
  
  (thousands)Outstanding at
  January 1, 2002
  
  14,450
  
  $
  18.42
  
  11,376Granted
  
  1,946
  
  $
  21.43Exercised
  
  (2,871
  )
  $
  17.18Cancelled or expired
  
  (633
  )
  $
  23.16Outstanding at
  December 31, 2002
  
  12,892
  
  $
  18.92
  
  10,258Granted
  
  1,503
  
  $
  22.42Exercised
  
  (3,698
  )
  $
  17.59Cancelled or expired
  
  (342
  )
  $
  24.07Outstanding at
  December 31, 2003
  
  10,355
  
  $
  19.73
  
  7,588Granted
  
  1,331
  
  $
  26.85Exercised
  
  (1,714
  )
  $
  18.42Cancelled or expired
  
  (7
  )
  $
  24.25Outstanding at
  December 31, 2004
  
  9,965
  
  $
  20.90
  
  7,239  88


The
following table summarizes information for stock options outstanding at
December 31, 2004.  Options Outstanding
  
  Options ExercisableRange of
  Exercise Prices
  
  Number
  of Options
  
  Weighted
  Average
  Remaining
  Contractual Life
  
  Weighted
  Average
  Exercise
  Price
  
  Number
  of Options
  
  Weighted
  Average
  Exercise
  Price(thousands)
  
  (years)
  
  
  
  (thousands)$10.03 to $17.08
  
  1,068
  
  5.0
  
  $
  11.68
  
  1,068
  
  $
  11.68$18.01 to $19.00
  
  1,508
  
  6.0
  
  $
  18.15
  
  1,508
  
  $
  18.15$19.16 to $20.58
  
  1,477
  
  4.0
  
  $
  20.11
  
  1,477
  
  $
  20.11$20.59 to $21.86
  
  1,980
  
  7.0
  
  $
  21.41
  
  1,550
  
  $
  21.41$22.33 to $22.85
  
  1,493
  
  5.1
  
  $
  22.35
  
  548
  
  $
  22.39$24.49 to $25.53
  
  1,108
  
  3.2
  
  $
  24.59
  
  1,080
  
  $
  24.56$26.85
  
  1,331
  
  6.2
  
  $
  26.85
  
  8
  
  $
  26.859,965
  
  5.2
  
  $
  20.90
  
  7,239
  
  $
  19.58  At December 31, 2004,
an additional five million common shares have been reserved for future issuance
under TransCanadas Stock Option Plan. In 2004, TransCanada issued 1,330,860
options to purchase common shares at an average price of $26.85 under the
Companys Stock Option Plan and the weighted average fair value of each option
was determined to be $2.85. The Company used the Black-Scholes model for these
calculations with the weighted average assumptions being four years of expected
life, 3.3 per cent interest rate, 18 per cent volatility and 4.3 per cent
dividend yield. The amount expensed for stock options, with a corresponding
increase in contributed surplus for the year ended December 31, 2004, was
$3 million (2003 and 2002  $2 million).  Shareholder
Rights PlanThe
Companys Shareholder Rights Plan is designed to encourage the fair treatment
of shareholders in connection with any takeover offer for the Company. Under
certain circumstances, each common share is entitled to one right which
entitles certain holders to purchase common shares of the Company at 50 per
cent of the then market price.  NOTE 14
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 DerivativesThe 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 InstrumentsCash 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 RiskCredit
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.  89


Notional or Notional Principal AmountsNotional 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.  Foreign
InvestmentsAt
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
  
  2003December 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
  
  250U.S. dollar forward
  foreign exchange contracts (maturing 2005)
  
  Hedge
  
  (1
  )
  305
  
  3
  
  125U.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
  
  2003Balance at beginning of
  year
  
  (40
  )
  14Translation 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).  90


Foreign
Exchange and Interest Rate Management ActivityThe 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
  
  2003December 31 (millions of dollars)
  
  Accounting
  Treatment
  
  Fair
  Value
  
  Notional
  or Notional
  Principal Amount
  
  Fair
  Value
  
  Notional
  or Notional
  Principal AmountForeign ExchangeCross-currency swaps(maturing 2010 to 2012)
  
  Hedge
  
  (39
  )
  U.S.
  157
  
  (26
  )
  U.S.
  282Interest RateInterest rate swapsCanadian dollars(maturing 2005 to 2008)
  
  Hedge
  
  7
  
  
  145
  
  (1
  )
  
  340(maturing 2006 to 2009)
  
  Non-hedge
  
  9
  
  
  374
  
  10
  
  
  62416
  
  
  
  
  9U.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.
  505
  
  
  
  
  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.  91


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
  
  2003December 31 (millions of dollars)
  
  Accounting
  Treatment
  
  Fair
  Value
  
  Notional
  or Notional
  Principal Amount
  
  Fair
  Value
  
  Notional
  or Notional
  Principal AmountForeign ExchangeOptions (maturing 2005)
  
  Non-hedge
  
  2
  
  U.S.
  225
  
  1
  
  U.S.
  25Forward foreign exchangecontracts (maturing 2005)
  
  Non-hedge
  
  1
  
  U.S.
  29
  
  1
  
  U.S.
  19Cross-currency swaps(maturing 2013)
  
  Hedge
  
  (16
  )
  U.S.
  100
  
  (7
  )
  U.S.
  100Interest RateOptions (maturing 2005)
  
  Non-hedge
  
  
  
  U.S.
  50
  
  (2
  )
  U.S.
  50Interest rate swapsCanadian dollar(maturing 2007 to 2009)
  
  Hedge
  
  4
  
  100
  
  2
  
  50(maturing 2005 to 2011)
  
  Non-hedge
  
  1
  
  110
  
  2
  
  1005
  
  
  
  4U.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.
  20027
  
  
  
  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 ManagementThe
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.  Power  Asset/(Liability)  2004
  
  2003December 31 (millions of dollars)
  
  Accounting
  Treatment
  
  Fair
  Value
  
  Fair
  ValuePower  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
  )  92


Notional
Volumes  Accounting
  
  Power (GWh) (1)
  
  Gas (Bcf) (1)December 31, 2004
  
  Treatment
  
  Purchases
  
  Sales
  
  Purchases
  
  SalesPower  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
  
  8Heat rate contracts(maturing 2005 to 2006)
  
  Hedge
  
  
  
  229
  
  2
  
    December 31, 2003Power  swaps
  
  Hedge
  
  1,331
  
  4,787
  
  
  
  Non-hedge
  
  59
  
  77
  
  
  
  Gas  swaps, forwards and
  options
  
  Hedge
  
  
  
  
  
  79
  
  81Non-hedge
  
  
  
  
  
  
  
  7Heat rate contracts
  
  Hedge
  
  
  
  735
  
  1
  
    
 (1)     Gigawatt hours (GWh); billion cubic feet (Bcf).  U.S. Dollar
Transaction HedgesTo
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.  Other Fair Values  2004
  
  2003December 31 (millions of dollars)
  
  Carrying
  Amount
  
  Fair
  Value
  
  Carrying
  Amount
  
  Fair
  ValueLong-Term DebtCanadian Mainline
  
  4,445
  
  5,473
  
  4,853
  
  5,922Alberta System
  
  2,105
  
  2,668
  
  2,325
  
  2,893GTN (1)
  
  632
  
  627Foothills System
  
  400
  
  413
  
  380
  
  382Portland
  
  308
  
  328
  
  350
  
  348Other
  
  2,589
  
  2,687
  
  2,107
  
  2,214Non-Recourse Debt of Joint
  Ventures
  
  862
  
  967
  
  780
  
  889Preferred Securities
  
  19
  
  19
  
  19
  
  19  
 (1)     TransCanada acquired GTN on November 1, 2004.  These fair values are
provided solely for information purposes and are not recorded in the
consolidated balance sheet.  93


NOTE 15
Income Taxes  Provision
for Income Taxes  Year ended December 31 (millions of dollars)
  
  2004
  
  2003
  
  2002CurrentCanada
  
  390
  
  264
  
  229Foreign
  
  41
  
  41
  
  41431
  
  305
  
  270FutureCanada
  
  34
  
  183
  
  193Foreign
  
  43
  
  47
  
  5477
  
  230
  
  247508
  
  535
  
  517  Geographic
Components of Income  Year ended December 31 (millions of dollars)
  
  2004
  
  2003
  
  2002Canada
  
  1,255
  
  1,115
  
  1,042Foreign
  
  296
  
  281
  
  280Income from continuing
  operations before income taxes and non-controlling interests
  
  1,551
  
  1,396
  
  1,322  Reconciliation
of Income Tax Expense  Year ended December 31 (millions of dollars)
  
  2004
  
  2003
  
  2002Income from continuing
  operations before income taxes and non-controlling interests
  
  1,551
  
  1,396
  
  1,322Federal and provincial
  statutory tax rate
  
  33.9
  %
  36.7
  %
  39.2
  %Expected income tax
  expense
  
  526
  
  512
  
  518Income tax differential
  related to regulated operations
  
  62
  
  29
  
  (8
  )Higher (lower) effective
  foreign tax rates
  
  2
  
  (2
  )
  (13
  )Large corporations tax
  
  21
  
  28
  
  30Lower 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
  )
  8Other
  
  (21
  )
  (18
  )
  (16
  )Actual income tax expense
  
  508
  
  535
  
  517  Future
Income Tax Assets and Liabilities  December 31 (millions of dollars)
  
  2004
  
  2003Deferred costs
  
  71
  
  50Deferred revenue
  
  18
  
  29Alternative minimum tax
  credits
  
  10
  
  29Net operating and capital
  loss carryforwards
  
  7
  
  28Other
  
  72
  
  24178
  
  160Less: Valuation allowance
  
  17
  
  24Future income tax assets,
  net of valuation allowance
  
  161
  
  136Difference in accounting
  and tax bases of plant, equipment and PPAs
  
  456
  
  396Investments in
  subsidiaries and partnerships
  
  114
  
  108Unrealized foreign
  exchange gains on long-term debt
  
  45
  
  15Other
  
  55
  
  44Future income tax
  liabilities
  
  670
  
  563Net future income tax
  liabilities
  
  509
  
  427  94


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 InvestmentsIncome 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
PaymentsIncome tax
payments of $419 million were made during the year ended December 31, 2004
(2003  $220 million; 2002  $257 million).  NOTE 16
Notes Payable  2004
  
  2003Outstanding
  December 31
  
  Weighted
  Average
  Interest Rate
  Per Annum at
  December 31
  
  Outstanding
  December 31
  
  Weighted
  Average
  Interest Rate
  Per Annum at
  December 31(millions of dollars)
  
  
  
  (millions of dollars)Commercial PaperCanadian 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 17
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.  95


Reconciliation
of Asset Retirement Obligations  (millions of dollars)
  
  Gas Transmission
  
  Power
  
  TotalBalance at
  December 31, 2002
  
  2
  
  6
  
  8Revisions in estimated
  cash flows
  
  
  
  1
  
  1Balance at December 31,
  2003
  
  2
  
  7
  
  9New obligations and
  revisions in estimated cash flows
  
  9
  
  21
  
  30Removal of Power LP
  redemption obligations
  
  
  
  (5
  )
  (5
  )Accretion expense
  
  1
  
  1
  
  2Balance at December 31,
  2004
  
  12
  
  24
  
  36  NOTE 18
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).  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.  96


Pension Benefit Plans
  
  Other Benefit Plans(millions of dollars)
  
  2004
  
  2003
  
  2004
  
  2003Change in Benefit ObligationBenefit obligation 
  beginning of year
  
  960
  
  841
  
  106
  
  95Current service cost
  
  28
  
  25
  
  3
  
  2Interest cost
  
  58
  
  52
  
  7
  
  6Employee contributions
  
  2
  
  2
  
  
  
  Benefits paid
  
  (66
  )
  (45
  )
  (4
  )
  (4
  )Actuarial loss
  
  46
  
  66
  
  (12
  )
  7Acquisition of subsidiary
  
  72
  
  19
  
  23
  
  Benefit obligation  end
  of year
  
  1,100
  
  960
  
  123
  
  106Change in Plan AssetsPlan assets at fair value
   beginning of year
  
  799
  
  621
  
  
  
  Actual return on plan
  assets
  
  97
  
  89
  
  1
  
  Employer contributions
  
  84
  
  110
  
  4
  
  4Employee 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
  
  39Unamortized past service
  costs
  
  39
  
  41
  
  7
  
  6Unamortized transitional
  obligation related to regulated business
  
  
  
  
  
  
  
  25Accrued benefit
  asset/(liability), net of valuation allowance of nil
  
  164
  
  143
  
  (65
  )
  (36
  )  The accrued benefit
(asset)/liability, net of valuation allowance, is included in the Companys
balance sheet as follows.  Pension Benefit Plans
  
  Other Benefit Plans2004
  
  2003
  
  2004
  
  2003Other 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 Plans2004
  
  2003
  
  2004
  
  2003Accrued 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 Benefits2005
  
  52
  
  62006
  
  53
  
  62007
  
  56
  
  72008
  
  58
  
  72009
  
  60
  
  7Years 2010 to 2014
  
  343
  
  40  97


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 Plans2004
  
  2003
  
  2004
  
  2003Discount rate
  
  5.75
  %
  6.00
  %
  6.00
  %
  6.25
  %Rate of compensation
  increase
  
  3.50
  %
  3.50
  %  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 Plans2004
  
  2003
  
  2002
  
  2004
  
  2003
  
  2002Discount 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
  
  DecreaseEffect on total of service
  and interest cost components
  
  2
  
  (1
  )Effect on post-employment
  benefit obligation
  
  12
  
  (11
  )  The Companys net benefit
cost is as follows.  Pension Benefit Plans
  
  Other Benefit PlansYear ended December 31 (millions of dollars)
  
  2004
  
  2003
  
  2002
  
  2004
  
  2003
  
  2002Current service cost
  
  28
  
  25
  
  11
  
  3
  
  2
  
  2Interest cost
  
  58
  
  52
  
  43
  
  7
  
  6
  
  4Actual return on plan
  assets
  
  (97
  )
  (89
  )
  (9
  )
  1
  
  
  
  Actuarial loss
  
  46
  
  66
  
  93
  
  (12
  )
  7
  
  26Plan amendment
  
  
  
  
  
  92
  
  
  
  
  
  7Elements of net benefit
  cost prior to adjustments to recognize the long-term nature of net benefit
  cost
  
  35
  
  54
  
  230
  
  (1
  )
  15
  
  39Difference 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
  
  2Net benefit cost
  recognized
  
  45
  
  37
  
  11
  
  13
  
  12
  
  8  98


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 AllocationAsset Category
  
  2004
  
  2003
  
  2004Debt 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.  NOTE 19
Changes in Operating Working Capital  Year ended December 31 (millions of dollars)
  
  2004
  
  2003
  
  2002Decrease/(increase) in
  accounts receivable
  
  9
  
  26
  
  (45
  )Decrease/(increase) in
  inventories
  
  
  
  15
  
  (3
  )Decrease/(increase) in
  other current assets
  
  33
  
  21
  
  (53
  )(Decrease)/increase in
  accounts payable
  
  (1
  )
  52
  
  120(Decrease)/increase in
  accrued interest
  
  (7
  )
  (2
  )
  1434
  
  112
  
  33  NOTE 20
Commitments, Contingencies and Guarantees  CommitmentsFuture 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
  Payments2005
  
  37
  
  (9
  )
  282006
  
  45
  
  (10
  )
  352007
  
  51
  
  (9
  )
  422008
  
  53
  
  (9
  )
  442009
  
  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
TransCanada reached an agreement which governs TransCanada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, TransCanada 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, TransCanada 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.  99


ContingenciesThe Canadian Alliance
of Pipeline Landowners Associations and two individual landowners commenced an
action in 2003 under Ontarios Class Proceedings Act, 1992, against
TransCanada 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.  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.  GuaranteesUpon 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. TransCanada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.  TransCanada 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
TransCanada 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 TransCanada. 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 21
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.  100


NOTE 22    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 except
  
  Restated
  
  Restated
  
  Restatedper share amounts)
  
  2004
  
  2003
  
  2002Revenues
  
  4,700
  
  4,919
  
  4,565Cost of
  sales
  
  440
  
  592
  
  441Other costs
  and expenses
  
  1,638
  
  1,663
  
  1,532Depreciation
  
  857
  
  819
  
  7292,935
  
  3,074
  
  2,702Operating
  income
  
  1,765
  
  1,845
  
  1,863Other
  (income)/expensesEquity income(1)
  
  (353
  )
  (334
  )
  (260
  )Other
  expenses(2)(12)(13)
  
  826
  
  873
  
  882Dilution
  gain(12)
  
  (40
  )
  
  
  Income taxes
  
  490
  
  515
  
  499923
  
  1,054
  
  1,121Income from
  continuing operations - U.S. GAAP
  
  842
  
  791
  
  742Net 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
  
  894
  
  841
  
  742Cumulative
  effect of the application of accounting changes, net of tax(3)
  
  
  
  (13
  )
  Net
  Income in Accordance with U.S. GAAP
  
  894
  
  828
  
  742Adjustments
  affecting comprehensive income under U.S. GAAPForeign
  currency translation adjustment, net of tax
  
  (31
  )
  (54
  )
  1Changes 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
  
  936
  
  780
  
  699Net
  Income Per Share in Accordance with U.S. GAAPContinuing
  operations
  
  $
  1.74
  
  $
  1.65
  
  $
  1.55Discontinued
  operations
  
  0.11
  
  0.10
  
  Income
  before cumulative effect of the application of accounting changes in
  accordance with U.S. GAAP
  
  $
  1.85
  
  $
  1.75
  
  $
  1.55Cumulative
  effect of the application of accounting changes, net of tax(3)
  
  
  
  (0.03
  )
  Basic
  
  $
  1.85
  
  $
  1.72
  
  $
  1.55Diluted(6)
  
  $
  1.84
  
  $
  1.71
  
  $
  1.54Net
  Income Per Share in Accordance with Canadian GAAPBasic
  
  $
  2.13
  
  $
  1.76
  
  $
  1.56Diluted
  
  $
  2.12
  
  $
  1.76
  
  $
  1.55Dividends
  per common share
  
  $
  1.16
  
  $
  1.08
  
  $
  1.00   101


Reconciliation
of Income from Continuing Operations  Restated
  
  Restated
  
  RestatedYear ended December 31 (millions of dollars)
  
  2004
  
  2003
  
  2002Net
  Income from Continuing Operations in Accordance with Canadian GAAP
  
  980
  
  801
  
  747U.S. GAAP
  adjustmentsUnrealized
  (loss)/gain on foreign exchange and interest rate derivatives(5)
  
  (12
  )
  (9
  )
  30Tax 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
  )
  8Equity
  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
  
  842
  
  791
  
  742  Condensed
Statement of Consolidated Cash Flows in Accordance with U.S. GAAP  Year ended December 31 (millions of dollars)
  
  2004
  
  2003
  
  2002Cash
  Generated from OperationsFunds
  generated from continuing operations
  
  1,529
  
  1,619
  
  1,610Decrease in
  operating working capital
  
  45
  
  108
  
  40Net cash
  provided by continuing operations
  
  1,574
  
  1,727
  
  1,650Net cash
  (used in)/provided by discontinued operations
  
  (6
  )
  (17
  )
  591,568
  
  1,710
  
  1,709Investing
  ActivitiesNet cash
  used in investing activities
  
  (1,304
  )
  (943
  )
  (796
  )Financing
  ActivitiesNet cash
  used in financing activities
  
  (336
  )
  (581
  )
  (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
  )
  134
  
  (80
  )Cash and
  Short-Term InvestmentsBeginning of
  year
  
  283
  
  149
  
  229Cash and
  Short-Term InvestmentsEnd of year
  
  124
  
  283
  
  149  102


Condensed
Balance Sheet in Accordance with U.S. GAAP(1)  RestatedDecember 31 (millions of dollars)
  
  2004
  
  2003Current
  assets
  
  908
  
  1,020Long-term
  investments(7)(8)
  
  1,887
  
  1,760Plant,
  property and equipment
  
  17,083
  
  15,753Regulatory
  asset(9)
  
  2,606
  
  2,721Other assets
  
  1,235
  
  1,38523,719
  
  22,639Current
  liabilities(10)
  
  2,573
  
  2,135Deferred
  amounts(3)(5)(8)(12)(13)
  
  803
  
  692Long-term
  debt(5)
  
  9,753
  
  9,494Deferred
  income taxes(9)
  
  3,048
  
  3,039Preferred
  securities(11)
  
  554
  
  694Non-controlling
  interests
  
  465
  
  471Shareholders
  equity(12)(13)
  
  6,523
  
  6,11423,719
  
  22,639  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)
  
  TotalBalance 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
  
  
  
  
  
  1Balance 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
  
  8Foreign
  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
  
  
  
  72Unrealized
  gain on derivatives, net of tax of $(3)(5)
  
  
  
  
  
  1
  
  1Foreign
  currency translation adjustment, net of tax of $(44)
  
  (31
  )
  
  
  
  
  (31
  )Balance
  at December 31, 2004
  
  (71
  )
  (26
  )
  (4
  )
  (101
  )  103


(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.  104


(2)Other expenses included an allowance for funds
used during construction of $3 million for the year ended December 31,
2004 (2003 - $2 million; 2002 - $4 million).  (3)Subsequent to October 1, 2003, the energy
contracts that were accounted for as hedges under the provisions of Statement
of Financial Accounting Standards (SFAS) No. 133 qualified as hedges.  Substantially all derivative energy contracts
are now accounted for as hedges under both U.S. and Canadian GAAP.  All gains or losses on the contracts that did
not qualify as hedges under SFAS No. 133, and the amounts of any
ineffectiveness on the hedging contracts, are included in income each
period.  Substantially all of the amounts
recorded in 2004 and 2003 as differences between U.S. and Canadian GAAP relate
to gains and losses on contracts for periods before they were documented as
hedges for purposes of U.S. GAAP and to differences in accounting with respect
to physical energy trading contracts in the U.S. and Canada.  (4)Under U.S. GAAP, a net loss recognized
pursuant to SFAS No. 87 Employers Accounting for Pensions as an
additional pension liability not yet recognized as net period pension cost,
must be recorded as a component of comprehensive income.  The net amount recognized at December 31
is as follows.  December 31 (millions of
  dollars)
  
  2004
  
  2003Prepaid
  benefit cost
  
  206
  
  201Accounts
  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  105


the
fair value of derivatives and the corresponding change in the fair value of
hedged items.  (6)Diluted net income per share in accordance
with U.S. GAAP for the year ended December 31, 2004 consists of continuing
operations - $1.73 per share (2003 - $1.61 per share; 2002 - $1.54 per share),
and discontinued operations - $0.11 per share (2003 - $0.10 per share; 2002 
nil).  (7)Under Canadian GAAP, pre-operating costs
incurred during the commissioning phase of a new project are deferred until
commercial production levels are achieved. 
After such time, those costs are amortized over the estimated life of
the project.  Under U.S. GAAP, such costs
are expensed as incurred.  Certain
start-up costs incurred by Bruce Power, L.P. (an equity investment) are
required to be expensed under U.S. GAAP.  Under both Canadian GAAP and U.S. GAAP, interest is capitalized on
expenditures relating to construction of development projects actively being
prepared for their intended use.  In
Bruce Power, L.P. under U.S. GAAP, the carrying value of development projects
against which interest is capitalized is lower due to the expensing of
pre-operating costs.  (8)Effective January 1, 2003, the Company
adopted the provisions of Financial Interpretation (FIN) 45 that require the
recognition of a liability for the fair value of certain guarantees that
require payments contingent on specified types of future events.  The measurement standards of FIN 45 are
applicable to guarantees entered into after January 1, 2003.  For U.S. GAAP purposes, the fair value of
guarantees recorded as a liability at December 31, 2004 was $9 million
(2003 - $4 million) and relates to the Companys equity interest in Bruce
Power.  (9)Under U.S. GAAP, the Company is required to
record a deferred income tax liability for its cost-of-service regulated
businesses. As these deferred income taxes are recoverable through future
revenues, a corresponding regulatory asset is recorded for U.S. GAAP
purposes.  (10)Current liabilities at December 31, 2004 include dividends payable
of $146 million (2003 - $136 million) and current taxes payable of $260 million
(2003 - $271 million).  (11)The fair value of the preferred securities at December 31, 2004 was
$572 million (2003 - $612 million).  The
Company made preferred securities charges payments of $48 million for the year
ended December 31, 2004 (2003 - $57 million; 2002 - $58 million).  (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, TransCanada 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).  (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:  106


(millions of dollars except per share amounts)
  
  2004
  
  2003
  
  2002Decrease in:Income from
  continuing operations
  
  135
  
  10
  
  10Net income
  
  135
  
  10
  
  10Net income
  per share in accordance with U.S. GAAPContinuing
  operations
  
  $
  0.28
  
  $
  0.02
  
  $
  0.02Discontinued
  operations
  
  
  
  
  
  Basic
  
  $
  0.28
  
  $
  0.02
  
  $
  0.02Diluted
  
  $
  0.28
  
  $
  0.02
  
  $
  0.02  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
  
  2003Deferred
  Tax LiabilitiesDifference
  in accounting and tax bases of plant, equipment and PPAs
  
  1,741
  
  1,813Taxes on
  future revenue requirement
  
  914
  
  962Investments
  in subsidiaries and partnerships
  
  438
  
  373Other
  
  140
  
  873,233
  
  3,235Deferred
  Tax AssetsNet
  operating and capital loss carryforwards
  
  7
  
  28Deferred
  amounts
  
  89
  
  79Other
  
  106
  
  113202
  
  220Less:
  Valuation allowance
  
  17
  
  24185
  
  196Net deferred
  tax liabilities
  
  3,048
  
  3,039  107


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.  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
  
  2002IncomeRevenues
  
  1,149
  
  1,063
  
  798Other 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
  
  260December 31 (millions of dollars)
  
  2004
  
  2003Balance
  SheetCurrent
  assets
  
  361
  
  385Plant,
  property and equipment
  
  3,020
  
  2,944Current
  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  108


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 22 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  /s/ KPMG LLP Calgary, Canada February 28, 2005, except as to note 22 which is as of July 28, 2005   109


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