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U.S. Securities and Exchange Commission
Washington, D.C. 20549

Form 40-F


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 registered
Common Shares (including Rights under Shareholder Rights Plan)   New York Stock Exchange

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

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

ý 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

        The documents (or portions thereof) forming part of this Form 40-F 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

CONSOLIDATED AUDITED ANNUAL FINANCIAL STATEMENTS AND
MANAGEMENT'S DISCUSSION & ANALYSIS

A.    Audited Annual Financial Statements

        For consolidated audited financial statements, including the report of independent chartered accountants with respect thereto, see pages 69 through 106 of the TransCanada Corporation ("TransCanada") 2004 Annual Report to Shareholders included herein. See Note 22 of the Notes to Consolidated Financial Statements on pages 102 through 106 of the TransCanada 2004 Annual Report to Shareholders, reconciling the important differences between Canadian and United States generally accepted accounting principles.

B.    Management's Discussion & Analysis

        For management's discussion and analysis, see pages 10 through 66 of the TransCanada 2004 Annual Report to Shareholders included herein under the heading "Management's Discussion & Analysis".

        For the purposes of this Report, only pages 10 through 66 and 69 through 106 of the TransCanada 2004 Annual Report to Shareholders as referred to above shall be deemed incorporated herein by reference and filed, and the balance of such 2004 Annual Report, except as otherwise specifically incorporated by reference in the TransCanada Annual Information Form, shall be deemed not filed with the Securities and Exchange Commission as part of this Report under the Exchange Act.

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.

DISCLOSURE CONTROLS AND PROCEDURES

        Pursuant to the Sarbanes-Oxley Act of 2002 as adopted by the U.S. Securities and Exchange Commission, the Registrant's management evaluates the effectiveness of the design and operation of the company's disclosure controls and procedures (disclosure controls). This evaluation is done under the supervision of, and with the participation of, the President and Chief Executive Officer and the Chief Financial Officer.

        As of the end of the period covered by this Annual Report, the Registrant's management evaluated the effectiveness of its disclosure controls. Based on that evaluation, the President and Chief Executive Officer and the Chief Financial Officer have concluded that the Registrant's disclosure controls are effective in ensuring that material information relating to the Registrant is made known to management on a timely basis, and is included in this Form 40-F.

        No change in the Registrant's internal control over financial reporting occurred during the period covered by this annual report that has materially affected, or is reasonably likely to materially affect, the Registrant's internal control over financial reporting.

2

AUDIT COMMITTEE FINANCIAL EXPERT

        The Registrant's board of directors has determined that it has at least one audit committee financial expert serving on its audit committee. Mr. Harry G. Schaefer has been determined to be such audit committee financial expert and is independent, as that term is defined by the New York Stock Exchange's listing standards applicable to the Registrant. The SEC has indicated that the designation of Mr. Schaefer as an audit committee financial expert does not make Mr. Schaefer an "expert" for any purpose, impose any duties, obligations or liability on Mr. Schaefer that are greater than those imposed on members of the audit committee and board of directors who do not carry this designation or affect the duties, obligations or liability of any other member of the audit committee.

CODE OF ETHICS

        The Registrant has adopted codes of business ethics for its employees and officers, its principal executive officer, principal financial officer and controller and its directors. The Registrant's codes are available on its website at www.transcanada.com. There has been no waiver of the codes granted during the 2004 fiscal year.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

        The aggregate fees for professional services rendered by KPMG LLP for the TransCanada group of companies for the 2004 and 2003 fiscal years are shown in the table below:

Fees in millions of dollars
   2004
   2003
Audit Fees   $ 2.50   $ 1.80
Audit-Related Fees     0.06     0.05
Tax Fees     0.06     0.06
All Other Fees     0.05     0.05
   
 
Total   $ 2.67   $ 1.96
   
 

        The nature of each category of fees is described below.

Audit Fees

        Audit fees were incurred for professional services rendered by the auditors for the audit of the Registrant's and its subsidiaries' annual financial statements or services provided in connection with statutory and regulatory filings or engagements, the review of interim consolidated financial statements and information contained in various prospectuses and other offering documents.

Audit-Related Fees

        Audit-related fees were incurred for the audit of the financial statements of the Registrant's various pension plans.

Tax Fees

        Tax fees were incurred for tax compliance and tax advice. These services consisted of: tax compliance including the review of original and amended tax returns, assistance with questions regarding tax audits and assistance in completing routine tax schedules and calculations; and tax services relating to common forms of domestic and international taxation (i.e., income tax, capital tax, Goods and Services Tax and Value Added Tax).

All Other Fees

        Fees disclosed in the table above under the item "all other fees" were incurred for services other than the audit fees, audit-related fees and tax fees described above. These services consisted of advice with regards to compliance with the Sarbanes-Oxley Act of 2002.

Pre-Approval Policies and Procedures

        TransCanada's Audit Committee has adopted a pre-approval policy with respect to permitted non-audit services. Under the policy, the Audit Committee has granted pre-approval for specified non-audit services of $25,000 CDN or less that are within the annual pre-approved limit for non-audit services. For engagements of $25,000 CDN or less which are not within the annual pre-approved limit, and for engagements between $25,000 CDN and $100,000 CDN, approval of the Audit Committee chair is required and the Audit Committee is to be informed of the engagement at the next scheduled Audit Committee meeting. For all engagements of $100,000 or more, pre-approval of the Audit Committee is required. In all cases, regardless of dollar amount involved, where there is a potential for conflict of interest for the external auditor to arise on an engagement, the Audit Committee chair must pre-approve the assignment.

        To date, TransCanada has not approved any non-audit services on the basis of the de-minimis exemptions. All non-audit services are pre-approved by the Audit Committee in accordance with the pre-approval policy referenced herein.

3

OFF-BALANCE SHEET ARRANGEMENTS

        The Registrant has no off-balance sheet arrangements, as defined in this Form, other than the guarantees described in Notes 20 and 22 of the Notes to the Consolidated Financial Statements. The disclosure relating to guarantees in Notes 20 and 22 to the Consolidated Financial Statements is incorporated herein by reference.

TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

Contractual Obligations
   Total
   Less than 1 year
   1-3
years
   3-5
years
   More than
5 years
Long-Term Debt Obligations   11,341   849   1,069   1,457   7,966
Capital (Finance) Lease Obligations                    
Operating Lease Obligations   869   28   77   88   676
Purchase Obligations(1)   6,351   1,099   1,196   974   3,082
   
 
 
 
 
Other Long-Term Liabilities Reflected on the Registrant's Balance Sheet under the GAAP of the primary financial statements                    
Total   18,561   1,976   2,342   2,519   11,724
   
 
 
 
 
(1)
The amounts in this table exclude expected funding contributions of approximately $67 million and $6 million, in 2005, to the Registrant's pension plans and other benefit plans, respectively.

        For further information on purchase obligations see"Management's Discussion and Analysis — Contractual Obligations — Purchase Obligations", which is incorporated herein by reference.

IDENTIFICATION OF THE AUDIT COMMITTEE

        The Registrant has a separately-designated standing Audit Committee. The members of the Audit Committee are:

    Chair:   H.G. Schaefer
    Members:   D.D. Baldwin
P. Gauthier
S.B. Jackson
P.L. Joskow

FORWARD-LOOKING INFORMATION

        This document, documents incorporated herein by reference, and other reports and filings made with the securities regulatory authorities, include forward-looking statements. All forward looking statements are based on TransCanada's beliefs as well as assumptions based on information available at the time the assumption was made. Forward-looking statements relate to, among other things, anticipated financial performance, business prospects, strategies, regulatory developments, new services, market forces, commitments and technological developments. By its nature, such forward-looking information is subject to various risks and uncertainties, including those discussed herein, which could cause TransCanada's actual results and experience to differ materially from the anticipated results or other expectations expressed. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date hereof or otherwise, and TransCanada undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise.

4


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

 
 
 
Date: March 14, 2005

5

DOCUMENTS FILED AS PART OF THIS REPORT

13.1   TransCanada Corporation Annual Information Form for the year endedl December 31, 2004.

13.2
 
Management's Discussion and Analysis (included on pages 10 through 66 of the TransCanada 2004 Annual Report to Shareholders).

13.3
 
2004 Consolidated Audited Financial Statements (included on pages 69 through 106 of the TransCanada 2004 Annual Report to Shareholders).

13.4
 
U.S. GAAP reconciliation of the 2004 Consolidated Audited Financial Statements (included on pages 102 through 106 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.

32.1
 
Certification of Chief Executive Officer regarding Periodic Report containing Financial Statements.

32.2
 
Certification of Chief Financial Officer regarding Periodic Report containing Financial Statements.

6

LOGO

TRANSCANADA CORPORATION

ANNUAL INFORMATION FORM

March 7, 2005


TABLE OF CONTENTS

 
   Page
TABLE OF CONTENTS   i
PRESENTATION OF INFORMATION   ii
FORWARD-LOOKING INFORMATION   ii
REFERENCE INFORMATION   ii
TRANSCANADA CORPORATION   1
  Corporate Structure   1
  Significant Subsidiaries   1
GENERAL DEVELOPMENT OF THE BUSINESS   2
  Developments in Gas Transmission Business   2
  Developments in Power Business   3
  Recent Developments   5
BUSINESS OF TRANSCANADA   5
  Gas Transmission Business   6
    Gas Transmission   6
      Wholly-Owned Pipelines   7
      Other Gas Transmission   12
      Regulation of North American Pipelines   14
      Competition in Gas Transmission   15
      Research and Development   15
    Power   15
      TransCanada Power, L.P.   16
      Other Power   17
      Power Performance   17
      Regulation of Power   18
      Competition in Power   19
    Other Interests   19
      Cancarb Limited   19
      TransCanada Turbines   19
      TransCanada Calibrations   19
  Discontinued Operations   19
HEALTH, SAFETY AND ENVIRONMENT   19
  Environment   20
LEGAL PROCEEDINGS   20
TRANSFER AGENTS AND REGISTRAR   21
INTEREST OF EXPERTS   21
RISK FACTORS   21
DIVIDENDS   22
DESCRIPTION OF CAPITAL STRUCTURE   22
RATINGS   23
MARKET FOR SECURITIES   25
DIRECTORS AND OFFICERS   25
    Directors   25
    Officers   28
CORPORATE GOVERNANCE   29
    Audit Committee   30
    Other Board Committees   31
    Conflicts of Interest   32
ADDITIONAL INFORMATION   32
GLOSSARY   33
SCHEDULE "A"   35
  Exchange Rate of the Canadian Dollar   35
  Metric Conversion Table   35
SCHEDULE "B"   36

TRANSCANADA CORPORATION    i



PRESENTATION OF INFORMATION

 Unless otherwise noted, the information contained in this Annual Information Form ("AIF") is given at or for the year ended, December 31, 2004 ("Year End"). Amounts are expressed in Canadian dollars unless otherwise indicated. Financial information is presented in accordance with Canadian generally accepted accounting principles.

 This AIF provides material information about the business and operations of TransCanada Corporation ("TransCanada"). TransCanada's Management's Discussion and Analysis dated March 1, 2005 ("MD&A") and TransCanada's Audited Consolidated Financial Statements are incorporated by reference into this AIF and can be found in TransCanada's Annual Report to Shareholders for the year ended December 31, 2004 ("Annual Report") which is available on SEDAR at www.sedar.com.

 Unless the context indicates otherwise, a reference in this AIF to "TransCanada" includes the subsidiaries of TransCanada through which its various business operations are conducted. In particular, "TransCanada" includes references to TransCanada PipeLines Limited ("TCPL"). Where TransCanada is referred to with respect to actions that occurred prior to its 2003 plan of arrangement with TCPL, which is described below under the heading "TransCanada Corporation — Corporate Structure", these actions were taken by TCPL or its subsidiaries. The term "subsidiary", when referred to in this AIF, means direct and indirect wholly-owned subsidiaries of TransCanada or TCPL, as applicable.

 Trends impacting TransCanada's gas transmission and power businesses are discussed in the MD&A under the headings "Gas Transmission" (under the subheadings "Opportunities and Developments", "Regulatory Developments" and "Business Risks") and "Power" (under the subheadings "Opportunities and Developments" and "Business Risks").


FORWARD-LOOKING INFORMATION

 This AIF, the documents incorporated by reference into this AIF, and other reports and filings made with the securities regulatory authorities include forward-looking statements. All forward-looking statements are based on TransCanada's beliefs and assumptions based on information available at the time the assumption was made. Forward-looking statements relate to, among other things, anticipated financial performance, business prospects, strategies, regulatory developments, new services, market forces, commitments and technological developments. Much of this information also appears in the MD&A. By its nature, such forward-looking information is subject to various risks and uncertainties, including those discussed in this AIF, which could cause TransCanada's actual results and experience to differ materially from the anticipated results or other expectations expressed. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed in this AIF or otherwise, and TransCanada undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise.


REFERENCE INFORMATION

 For the reference information noted below, please refer to Schedule "A".

ii    TRANSCANADA CORPORATION


TRANSCANADA CORPORATION

Corporate Structure

 TransCanada's head office and registered office are located at 450 - 1st Street S.W., Calgary, Alberta, T2P 5H1.

 TransCanada was incorporated pursuant to the provisions of the Canada Business Corporation Act on February 25, 2003 in connection with a plan of arrangement designed to establish TransCanada as the parent company of TCPL. The arrangement was approved by TCPL common shareholders on April 25, 2003 and, following court approval and the filing of Articles of Arrangement, the arrangement became effective May 15, 2003. Pursuant to the arrangement, the common shareholders of TCPL exchanged each of their TCPL common shares for one common share of TransCanada. The debt securities and preferred shares of TCPL remained obligations and securities of TCPL. TCPL continues to hold the assets it held prior to the arrangement and continues to carry on business as the principal operating subsidiary of the TransCanada group of entities. TransCanada does not hold any assets directly other than the common shares of TCPL.

 TransCanada is a Canadian public company. Significant dates and events are set forth below.

Date
   Event
February 25, 2003   TransCanada incorporated under Canada Business Corporations Act.
May 15, 2003   Certificate of Arrangement issued.

 The significant dates and events relating to TCPL are set out in TCPL's Annual Information Form for the year ended December 31, 2004, dated March 7, 2005.

 TransCanada does not directly employ any employees or contractors. At Year End, TransCanada's principal operating subsidiary, TCPL, had approximately 2,473 employees, substantially all of whom were employed in Canada and the United States.

Significant Subsidiaries

 TransCanada's significant subsidiaries(1) at Year End and the jurisdiction under which each subsidiary was incorporated are noted below. TransCanada owns, directly or indirectly, 100 per cent of the voting shares of each of these subsidiaries.

GRAPHIC

(1)
Excludes certain of TransCanada's subsidiaries where:

•
the total assets of each excluded subsidiary does not exceed ten per cent of the consolidated assets of TransCanada at Year End;

•
the sales and operating revenues of each excluded subsidiary does not exceed ten per cent of the consolidated sales and operating revenues of TransCanada for the year ended December 31, 2004;

TRANSCANADA CORPORATION    1


GENERAL DEVELOPMENT OF THE BUSINESS

 The general development of TransCanada's business during the last three financial years, and the significant acquisitions, events or conditions which have had an influence on that development, are described below.

Developments in Gas Transmission Business

 TransCanada's focus has been to sustain, grow and optimize its natural gas transmission business. Summarized below are significant developments that have occurred in TransCanada's natural gas transmission business over the last three years.

2004

 In September 2004, TransCanada and Petro-Canada signed a memorandum of understanding for the development of the Cacouna Energy liquefied natural gas ("LNG") facility in Cacouna, Québec, approximately 15 kilometers northeast of Rivière-du-Loup. The proposed facility will be capable of receiving, storing and regasifying imported LNG with an average annual send out capacity of approximately 500 million cubic feet per day of natural gas. TransCanada and Petro-Canada will share equally the construction costs of the facility, which are estimated to be $660 million. TransCanada will operate the facility while Petro-Canada will contract for the facility's entire regasification capacity and supply the LNG. The proposed facility requires regulatory and other approvals from federal, provincial and municipal governments and regulators and the regulatory approval process is anticipated to take approximately two years to complete. Provided the necessary approvals are obtained, the facility is anticipated to be in service towards the end of this decade.

 On October 1, 2004, TransCanada acquired the 380 kilometre Simmons pipeline system ("Simmons Pipeline System"), which delivers natural gas to the oil sands region near Fort McMurray, Alberta from several connecting receipt points on the Alberta System, for approximately $22 million.

 On November 1, 2004, TransCanada acquired the Gas Transmission Northwest pipeline system ("GTN System") and the North Baja pipeline system ("North Baja System") from National Energy & Gas Transmission, Inc. ("NEGT") for US$1.7 billion, including approximately US$0.5 billion of assumed debt, subject to typical closing adjustments. The GTN System, formerly known as Pacific Gas Transmission, extends more than 2,174 kilometres from a connection point on TransCanada's BC System and Foothills System near Kingsgate, British Columbia on the B.C.-Idaho border to a point near Malin, Oregon on the Oregon-California border. The natural gas transported on this system originates primarily in Canada and is supplied to markets in the Pacific Northwest, California and Nevada. The North Baja System extends 128 kilometres from a point near Ehrenberg, Arizona to a point near Ogilby, California on the California-Mexico border. The natural gas transported on the North Baja System comes primarily from supplies in the southwestern U.S. for markets in northern Baja California, Mexico.

 In November 2004, TransCanada and Shell US Gas & Power LLC ("Shell") announced plans to jointly develop an offshore LNG regasification terminal, Broadwater Energy, in the New York State waters of Long Island Sound. The proposed floating storage and regasification unit will be capable of receiving, storing and regasifying imported LNG with an average send out capacity of approximately one billion cubic feet ("Bcf") per day of natural gas. TransCanada and Shell will build and install a floating storage and regasification unit at a location approximately 15 kilometers off the Long Island coast and 18 kilometers off the Connecticut coast. TransCanada will own 50 per cent of Broadwater Energy LLC, which will own and operate the facility, while Shell will contract for the facility's entire regasification capacity and supply the LNG. The estimated cost of construction is US$700 million. The proposed Broadwater Energy LNG facility requires regulatory approval from Federal and State governments before construction can begin and the regulatory approval process is anticipated to take up to three years to complete. Provided the necessary approvals are granted and commercial commitments obtained, the facility could be in service in late 2010. TransCanada and Shell have filed a request with the U.S. Federal

2    TRANSCANADA CORPORATION


Energy Regulatory Commission ("FERC") to initiate a six to nine month public review of the Broadwater proposal.

 In a referendum held in March 2004, the residents of Harpswell, Maine voted against leasing a town-owned site to build the Fairwinds LNG regasification facility. As a result, TransCanada and its partner, ConocoPhillips Company, suspended further work on this LNG project.

 For further information about Gas Transmission Developments in 2004, refer to the headings "Business of TransCanada — Gas Transmission — Wholly-Owned Pipelines" and "Business of TransCanada — Gas Transmission — Other Gas Transmission" below.

2003

 In August 2003, TransCanada acquired the remaining interests in Foothills Pipe Lines Ltd. ("Foothills") that it did not previously own. The Foothills System, which is owned by Foothills, extends 1,040 kilometres and has two legs: one which originates south of Caroline, Alberta and runs along the foothills of the Rocky Mountains through the Crowsnest Pass to Kingsgate, B.C. where it connects to the GTN System; and the other which originates south of Caroline, Alberta and runs southeast across Alberta and Saskatchewan to the Canada-U.S. border near Monchy, Saskatchewan where it interconnects with Northern Border Pipeline Company ("Northern Border Pipeline"). The Foothills System carries over 30 per cent of all Canadian natural gas exports to the U.S.

 TransCanada, through Foothills, holds certificates for both the Alaskan and Canadian segments of the Alaska Highway Pipeline Project and also holds significant right-of-way assets for the project in both Canada and Alaska.

 In June 2003, TransCanada, the Mackenzie Delta Producers Group ("Mackenzie Producers") and Mackenzie Valley Aboriginal Pipeline L.P. ("Aboriginal Pipeline Group" or "APG") reached a funding and participation agreement. TransCanada agreed to finance the APG's share of project development costs in exchange for several options, including an ownership interest in the pipeline, certain rights of first refusal in the Mackenzie Gas Pipeline Project and the right to have the Mackenzie Delta gas flow into the Alberta System.

 Through acquisitions that took place in September and December 2003, TransCanada increased its ownership interest in Portland Natural Gas Transmission System Partnership ("Portland") in the northeastern U.S. from 33.3 per cent to 61.7 per cent.

2002

 In August 2002, TransCanada completed the acquisition of a portion of the two per cent general partnership interest in Northern Border Partners, L.P. ("NBP L.P."), a publicly held limited partnership. This interest provides TransCanada with a 17.5 per cent voting interest on the partnership policy committee. NBP L.P. owns interests in pipelines and gas processing plants in the U.S. and Canada, including a 70 per cent interest in Northern Border Pipeline.

Developments in Power Business

 In the past three years, TransCanada has grown its power business and, in particular, has increased its generation capacity from facilities it owns, operates and/or controls, including those under construction or in development, from approximately 4,033 megawatts ("MW") in 2002 to 5,712 MW at Year End. Summarized below are significant developments that have occurred in TransCanada's power business over the last three years.

2004

 TransCanada received approval from the Québec government in April 2004, to develop the 550 MW natural gas-fired Bécancour cogeneration plant which is located at an industrial park near Trois-Rivières, Québec ("Bécancour Plant") and which will supply its entire power output to Hydro-Québec Distribution under a 20 year power purchase agreement. The Bécancour Plant will also supply steam to two other companies located within the same industrial park. Construction of the 550 MW Bécancour Plant began in the third quarter of 2004. The

TRANSCANADA CORPORATION    3


cost of the Bécancour Plant is estimated to be $550 million, including capitalized interest, and the plant is expected to be in service in late 2006.

 In April 2004, TransCanada sold its ManChief and Curtis Palmer power plants to TransCanada Power, L.P. ("Power LP") for approximately US$402.6 million, excluding closing adjustments. The acquisition was partially financed by Power LP through a public offering of subscription receipts which were subsequently converted into limited partnership units. TransCanada did not take up its full pro rata share of the units and as a result, its interest in the Power LP was reduced from 35.6 per cent to 30.6 per cent.

 On September 29, 2004, TransCanada entered into an asset purchase agreement with USGen New England, Inc. ("USGen"), a power generation company, for the purchase of hydroelectric generation assets with a total generating capacity of 567 MW of power for US$505 million. The asset purchase was subject to a bankruptcy court sanctioned auction in which TransCanada was declared the successful bidder. The assets include generating systems on two rivers in New England: the 484 MW Connecticut River system in New Hampshire and Vermont and the 83 MW Deerfield River system in Massachusetts and Vermont. The necessary bankruptcy court approvals for the sale have been granted; however, the sale is also subject to certain regulatory approvals and conditions. In December 2004, Vermont Hydroelectric Power Authority exercised its option with USGen to purchase the 49 MW Bellows Falls facility located on the Connecticut River system. Upon closing of this purchase option, the Bellows Falls facility will be sold to Vermont Hydroelectric for US$72 million, thereby effectively reducing TransCanada's total purchase price by that amount.

 Cartier Wind Energy Inc. ("Cartier Wind Energy"), of which 62 per cent is owned by TransCanada, was awarded six wind energy projects by Hydro-Québec Distribution in October 2004, representing a total of 739.5 MW in the Gaspé region of Québec. The six projects are distributed throughout the Gaspésie-Iles-de-la-Madeleine region and the Regional County Municipality of Matane and are expected to cost a total of more than $1.1 billion to develop and construct. Construction of the projects is expected to begin late in 2005 and the projects are expected to be commissioned between 2006 and 2012. Long-term electricity supply contracts, which are subject to approval by the Régie de l'Energie, were negotiated with Hydro-Québec Distribution for each of the six facilities and were executed on February 25, 2005. Cartier Wind Energy has begun the process of seeking environmental approvals for the projects.

 Construction of the 165 MW MacKay River power plant located in Alberta was completed in 2003 and the plant was put into commercial service in 2004.

 Construction of the 90 MW Grandview natural gas-fired cogeneration power plant on the site of the Irving Oil refinery in Saint John, New Brunswick ("Grandview Plant") was completed by the end of 2004 and was commissioned in the first quarter of 2005. Under a 20 year tolling arrangement, a subsidiary of Irving Oil Limited will provide fuel to the Grandview Plant and has contracted for 100 per cent of the Grandview Plant's heat and electricity output.

2003

 In February 2003, TransCanada, as part of a consortium, acquired a 31.6 per cent interest in Bruce Power L.P. ("Bruce Power") and a 33.3 per cent interest in Bruce Power Inc., the general partner of Bruce Power. Bruce Power leases its generation facilities from Ontario Power Generation Inc. ("OPG"). The facilities consist of eight nuclear reactors, five of which were operational at the end of 2003, with a capacity of 3,950 MW. An additional reactor with capacity of 750 MW commenced commercial operations in March 2004.

 The members of the purchasing consortium of Bruce Power severally guaranteed, on a pro-rata basis, certain contingent financial obligations of Bruce Power related to operator licenses, the OPG lease agreement, power sales agreements and contractor services. Bruce Power continues to be operated by experienced nuclear power plant operators. Spent fuel and decommissioning liabilities remain with OPG under the terms of the lease.

2002

 In November 2002, TransCanada completed the acquisition of the 300 MW ManChief power plant, situated approximately 145 kilometres northeast of Denver, Colorado. The ManChief power plant was subsequently sold to Power LP in 2004.

4    TRANSCANADA CORPORATION


Recent Developments

 In January 2005, TransCanada announced that it would develop a $200 million natural gas storage facility near Edson, Alberta. The Edson facility is expected to have a capacity of approximately 50 Bcf and will connect to TransCanada's Alberta System. TransCanada has also secured a long-term contract with a third party for up to an additional 40 Bcf of storage capacity in Alberta. Upon completion of the Edson facility, combined with the existing storage capacity it holds through its 60 per cent interest in CrossAlta Gas Storage & Services Ltd., TransCanada will own or control more than 110 Bcf of storage capacity, which will amount to approximately one third of the storage capacity in Alberta at that time. TransCanada is in a position to provide fee based gas storage services directly to customers by April 2005 and the Edson facility's capacity will be available to customers on a phased in basis commencing in 2006.

 In February 2005, TransCanada announced its intention to gauge industry interest in a project to develop a 3,000 kilometre oil pipeline, with capacity to transport approximately 400,000 barrels per day. The pipeline will run from Hardisty, in southeastern Alberta, south through Alberta, eastwards through Saskatchewan and Manitoba, and then south across the Canada — U.S. border through North Dakota, South Dakota, Iowa, Missouri and finally to the Wood River and Patoka delivery points in Illinois. The oil pipeline project will involve the conversion from gas service of approximately 1,240 kilometres of one line of TransCanada's existing multi-line Alberta System and Canadian Mainline as well as new pipeline construction. Discussions with various stakeholders have begun and, if sufficient support for the oil pipeline project is attained, TransCanada will proceed to seek the necessary regulatory approvals.


BUSINESS OF TRANSCANADA

 TransCanada is a leading North American energy infrastructure company focused on natural gas transmission and power generation. At Year End, the gas transmission business accounted for approximately 77 per cent of revenues and 83 per cent of TransCanada's total assets and the power business accounted for approximately 23 per cent of revenues and 13 per cent of TransCanada's total assets. The following is a description of each of TransCanada's two main areas of operation.

 The following table shows TransCanada's revenues from operations by segment, classified geographically, for the years ended December 31, 2004 and 2003.

 
   2004
   2003
 
   (millions of dollars)
  (millions of dollars)
Gas Transmission        
  Canada — Domestic Deliveries   2,441   2,492
  Canada — Export Deliveries(1)   1,259   1,291
  United States   217   173
   
 
    3,917   3,956
   
 

Power
 
 
 
 
  Canada — Domestic Deliveries   706   765
  Canada — Export Deliveries(1)   2   2
  United States   482   634
   
 
    1,190   1,401
   
 
Total Revenues(2)   5,107   5,357
   
 

Notes:

(1)
Export deliveries include gas transmission revenues attributable to deliveries to U.S. pipelines and power deliveries to U.S. markets.

(2)
Revenues are attributed to countries based on country of origin of product or service.

TRANSCANADA CORPORATION    5

Gas Transmission Business

Canada

 TransCanada, through subsidiaries, has substantial Canadian natural gas pipeline holdings, including:

United States

 TransCanada, through subsidiaries, has natural gas pipeline holdings in the U.S. including:


 TransCanada holds a 33.4 per cent interest in TC PipeLines, L.P., a publicly held limited partnership of which a subsidiary of TransCanada acts as the general partner. The remaining interest of TC PipeLines, L.P. is widely held by the public. TC PipeLines, L.P. holds a 30 per cent interest in Northern Border Pipeline and a 49 per cent interest in Tuscarora.

Gas Transmission

 TransCanada's transmission business principally includes the operation of the wholly-owned Canadian Mainline, Alberta System, Foothills System, BC System, GTN System and North Baja System as well as TransCanada's other investments in partially-owned natural gas pipelines and storage facilities located primarily in Canada and the U.S.

 Canadian natural gas transmission services are provided under gas transportation tariffs that provide for cost recovery including return of and return on capital as approved by the applicable regulatory authorities. In some cases, such tariffs are determined under agreements with customers and other interested parties, subject to regulatory approval. The net income of the gas transmission business is generated based on such tariffs. Under the current regulatory model, net income is not affected by fluctuations in the commodity price of natural gas, but such fluctuations influence both production levels and the natural gas basins from which North American natural gas consumers elect to purchase natural gas supplies.

6    TRANSCANADA CORPORATION


 Both the GTN System and the North Baja System operate under fixed rate models, under which maximum and minimum rates for various service types have been ordered by FERC and under which, these two systems are permitted to discount or negotiate rates on a non-discriminatory basis. The net earnings attributable to the GTN System and the North Baja System are impacted by variations in volumes delivered under the various service types that are provided, as well as by variations in the costs of providing transportation service.

 The volume of natural gas shipments on the Canadian Mainline, Alberta System, Foothills System, BC System, GTN System and North Baja System depends on the volume of natural gas produced and sold both in and outside of Alberta, and on the cost and availability of other pipeline capacity. The natural gas transported by TransCanada on its Canadian pipelines comes primarily from the Western Canada Sedimentary Basin ("WCSB"). The WCSB's estimated remaining established reserves of natural gas are approximately 55 trillion cubic feet ("Tcf") with a remaining reserve-to-production ratio of approximately nine years at current levels of production. At present, incremental reserves are continually being discovered and generally maintain the reserve-to-production ratio at close to nine years. Production of natural gas from the WCSB has not increased since 2001. With the expansion of capacity on TransCanada's wholly and partially-owned pipelines over the past decade, and the competition provided by other pipelines, combined with significant growth in natural gas demand in Alberta, TransCanada anticipates there will be excess pipeline capacity out of the WCSB for the foreseeable future.

 In addition to the information concerning the gas transmission segment of TransCanada's business set out herein, further information can be found in the MD&A under the heading "Gas Transmission — Opportunities and Developments".

Wholly-Owned Pipelines

 The Canadian Mainline consists of 14,898 kilometres of pipeline system transporting natural gas from the Alberta border east to various delivery points in Canada and at the U.S. border.

 Capital expenditures on the Canadian Mainline in 2004 were approximately $43 million. These expenditures were primarily for some localized capacity capital and maintenance capital projects. TransCanada anticipates approximately $57 million of further localized capital spending on the Canadian Mainline in 2005, primarily related to capacity capital and maintenance capital projects.

 The following table sets forth the revenues earned and volumes delivered for the years ended December 31, 2004 and 2003 for the Canadian Mainline.

 
   2004
   2003
 
   Revenues(1)
   Per cent
   Revenues
   Per cent
 
   (millions of dollars)
   
   (millions of dollars)
   
Revenues                
Domestic Deliveries   952   44   1,035   46
Export Deliveries   1,201   56   1,214   54
   
 
 
 
Total   2,153   100   2,249   100
   
 
 
 
 
   2004
   2003
 
   Volume
   Per cent
   Volume
   Per cent
 
   (Bcf)
   
   (Bcf)
   
Volumes Transported                
Domestic Deliveries   1,345   51   1,295   49
Export Deliveries   1,276   49   1,333   51
   
 
 
 
Total   2,621   100   2,628   100
   
 
 
 

Note:

(1)
2004 domestic revenues were reduced as a result of transportation service credits related to a new service offered. Total credits of $23 million were reported against 2004 domestic revenues.

TRANSCANADA CORPORATION    7

 As of Year End, the Canadian Mainline was providing transportation for 127 shippers pursuant to 371 firm service transportation contracts. Approximately 44 per cent of the total daily transportation volume represented by these contracts relates to contracts for delivery of natural gas at U.S. border points.

 As of Year End, the weighted average remaining term of firm transportation contracts on the Canadian Mainline was approximately 2.5 years compared to a weighted average remaining term of 3.2 years at December 31, 2003. These contracts are renewable by the customer providing notice to TransCanada at least six months prior to the expiry of the current contract term. The Canadian Mainline last operated at capacity with one year or longer firm service contracts during the 1998-1999 contract year. Since then, the Canadian Mainline has seen a 36 per cent decrease in firm contracted deliveries and a 19 per cent decrease in total deliveries originating at the Alberta border and in Saskatchewan. Further information can be found in the MD&A under the headings "Gas Transmission — Earnings Analysis" and "Gas Transmission — Opportunities and Developments".

 Under the terms of the National Energy Board Act (Canada), the National Energy Board ("NEB") regulates the construction, operation, tolls and tariffs of the Canadian Mainline. The NEB is the authority under the Canadian Environmental Assessment Act responsible for considering the environmental and social impacts of proposed pipeline projects. The Canadian Mainline tolls are designed to generate sufficient revenues for TransCanada to recover operating expenses, depreciation, taxes and financing costs of the Canadian Mainline, including interest on debt and payments on preferred securities attributable to the Canadian Mainline, together with a return on deemed common equity.

 The tolls are composed of a demand charge component and a commodity charge component. The demand charge is independent of the volumes shipped and is designed to recover fixed costs, such as fixed operating expenses, financing costs (including a return on deemed common equity), taxes and depreciation. The commodity charge is designed to recover variable operating costs. These charges are paid by shippers under transportation contracts with TransCanada.

 In February 2003, the NEB denied TransCanada's September 2002 request for a Review and Variance of an NEB decision referred to as the Fair Return Decision, which TransCanada considered unsatisfactory. Consequently, TransCanada applied for and was granted leave to appeal the NEB's denial of the Review and Variance to the Federal Court of Appeal. However, in April 2004, the Federal Court of Appeal dismissed TransCanada's appeal. TransCanada remains disappointed with the Fair Return Decision; however, the Federal Court of Appeal decision extinguished any means of having it varied. In the 2002 Fair Return Decision, the NEB denied an application by TransCanada requesting the adoption of an after-tax weighted average cost of capital methodology for establishing investment return and an after-tax weighted average cost of capital of 7.5 per cent, equivalent to a 12.5 per cent rate of return on deemed common equity of 40 per cent. The NEB instead affirmed a formula under which the rate of return on common equity ("ROE") for the Canadian Mainline was determined to be 9.61 per cent in 2001, 9.53 per cent in 2002 and 9.79 per cent in 2003. The NEB increased deemed common equity to 33 per cent from the previously approved level of 30 per cent. TransCanada is of the belief that the Fair Return Decision does not recognize the long-term business risks of the Canadian Mainline.

 In January 2004, TransCanada filed an application with the NEB to determine 2004 Canadian Mainline tolls and the NEB, because of the then pending appeal to the Federal Court of Appeal regarding the Fair Return Decision, decided to hear the application in two phases: Phase I which addressed all matters except cost of capital and Phase II which addressed cost of capital. As part of Phase I of the application, TransCanada originally requested an 11 per cent return on deemed common equity of 40 per cent, however, given the Federal Court of Appeal's dismissal of TransCanada's appeal respecting its request of the NEB to review the Fair Return Decision, TransCanada amended the application so as to request an ROE of 9.56 per cent, as determined under the NEB's generic ROE formula on deemed common equity of 40 per cent. In its Phase I decision issued in September 2004, the NEB approved virtually all applied-for costs and the new Firm Transportation — Non Renewable service. The NEB considered the cost of capital portions of TransCanada's application in Phase II of the proceeding and a decision on Phase II is expected in the second quarter of 2005.

8    TRANSCANADA CORPORATION


 In February 2005, TransCanada announced that it had reached a settlement with its Canadian Mainline shippers regarding the tolls and tariff that are applicable to the Canadian Mainline in 2005.

 Further information about regulatory development involving the Canadian Mainline can be found in the MD&A under the headings "Gas Transmission — Regulatory Developments — Canadian Mainline" and "Consolidated Financial Review — Gas Transmission".

 The Alberta System, held by NOVA Gas Transmission Ltd. ("NGTL"), a subsidiary of TransCanada, is an Alberta-wide natural gas transmission system that collects and transports natural gas for use in Alberta and for delivery to connecting pipelines, such as the Canadian Mainline, the Foothills System and the BC System, as well as to other unaffiliated pipelines, at various points on the Alberta border for delivery to eastern Canada, B.C. and the U.S. The Alberta System includes 23,186 kilometres of mainlines and laterals. On October 1, 2004, the Simmons Pipeline System, which delivers gas to the Fort McMurray area, became part of the Alberta System.

 Capital expenditures, which are dependent in part upon requests for increased transportation service by customers, were $87 million in 2004. TransCanada anticipates approximately $97 million of capital spending on the Alberta System in 2005. These capital expenditures will be primarily related to capacity expansion.

 The following table sets forth the annual volumes delivered by the Alberta System for the years ended December 31, 2004 and 2003.

 
   2004
   2003
Deliveries to Market Areas
   Volume(1)
   Per cent
   Volume(2)
   Per cent
 
   (Bcf)
   
   (Bcf)
   
Alberta   589   15   539   14
Eastern Canada and Eastern United States   1,418   36   1,552   40
Western United States   737   19   665   17
Midwestern United States   1,155   30   1,117   29
B.C.   10   —   10   —
   
 
 
 
Total   3,909   100   3,883   100
   
 
 
 

Notes:

(1)
Of the total volumes transported in 2004, 1.80 Tcf of natural gas was delivered to the Canadian Mainline, 743 Bcf of natural gas was delivered to the BC System and 768 Bcf of natural gas was delivered to the Saskatchewan portion of the Foothills System.

(2)
Of the total volumes transported in 2003, 1.89 Tcf of natural gas was delivered to the Canadian Mainline, 673 Bcf of natural gas was delivered to the BC System and 777 Bcf of natural gas was delivered to the Saskatchewan portion of the Foothills System.

 As of Year End, the Alberta System was providing transportation for 282 shippers pursuant to approximately 18,300 firm service transportation contracts.

 As of Year End, the weighted average remaining term of firm transportation contracts was approximately 2.9 years, compared to a weighted average remaining term of 2.4 years as of December 31, 2003. Currently, these contracts are renewable by the customer providing notice to NGTL at least twelve months prior to the expiry of the current contract term.

 Further information about the Alberta System can be found in the MD&A under the headings "Gas Transmission — Earnings Analysis" and "Gas Transmission — Opportunities and Developments".

 The construction and operation of the Alberta System is regulated by the Alberta Energy and Utilities Board ("EUB") primarily under the provisions of the Gas Utilities Act (Alberta) and the Pipeline Act (Alberta). NGTL also requires the EUB's approval for rates, tolls and charges, and the terms and conditions under which it provides its services. Under the provisions of the Pipeline Act, the EUB oversees various matters, including the

TRANSCANADA CORPORATION    9

economic, orderly and efficient development of the pipeline, the operation and abandonment of the pipeline, and certain related pollution and environmental conservation issues. In addition to requirements under the Pipeline Act, the construction and operation of natural gas pipelines in Alberta are subject to certain provisions of, and require certain approvals under, other provincial legislation such as the Environmental Protection and Enhancement Act (Alberta).

 Alberta System tolls are designed to generate sufficient revenues for NGTL to recover operating expenses, depreciation, taxes and financing costs of the Alberta System, including interest on debt and payments on securities attributable to the Alberta System, together with a return on deemed common equity.

 In 2004, TransCanada received two significant regulatory decisions from the EUB in respect of the Alberta System which were disappointing.

 In July 2004, the EUB released its decision in the generic cost of capital ("GCOC") proceeding. All Alberta provincially regulated utilities, including the Alberta System, were mandated an ROE of 9.60 per cent for 2004. This generic ROE will be adjusted annually by 75 per cent of the change in long-term Government of Canada bonds from the previous year, consistent with the approach used by the NEB. The EUB also established a deemed common equity of 35 per cent for the Alberta System. This result was less than the applied for ROE of 11 per cent on deemed common equity of 40 per cent, which the company considered to be a fair return.

 In September 2003, TransCanada filed Phase I of the 2004 General Rate Application ("GRA") with the EUB, consisting of evidence in support of the applied-for rate base and revenue requirement. In its August 2004 decision, the EUB approved TransCanada's purchase of the Simmons Pipeline System and the recovery of costs associated with firm transportation service arrangements with the Foothills, Simmons and Ventures LP systems; however, the EUB decision disallowed certain operating costs, including incentive compensation costs.

 In September 2004, TransCanada filed with the Alberta Court of Appeal for leave to appeal the EUB's decision on Phase I of the 2004 GRA with respect to the disallowance of applied-for incentive compensation costs. TransCanada believes the EUB made errors of law in deciding to deny the inclusion of these compensation-related costs in the revenue requirement which it considers necessary and prudent for the safe, reliable and efficient operation of the Alberta System. At TransCanada's request, the Court of Appeal adjourned the appeal for an indefinite period of time to allow TransCanada to consider the merits of a review and variance application to the EUB in respect of 2004 costs, and work toward a negotiated settlement of future years' tolls with its customers which would replace or amend TransCanada's 2005 GRA. In September 2004, the EUB gave approval for TransCanada to enter into negotiations for a settlement that would not exceed three years.

 In December 2004, the EUB approved interim rates that were effective in 2004 as final rates and approved interim rates effective January 1, 2005, which will remain in place until final 2005 rates are determined. In addition, in February 2005, TransCanada reached an agreement in principle with its Alberta System shippers in respect of a revenue requirement settlement for the period from January 1, 2005 until December 31, 2007. TransCanada is proceeding with finalizing the terms of the settlement with the negotiating parties and anticipates executing the settlement agreement in March 2005. TransCanada expects to file the settlement agreement with the EUB for approval, shortly thereafter.

 Further information about regulatory developments involving the Alberta System can be found in the MD&A under the headings "Gas Transmission — Regulatory Developments — Alberta System" and "Consolidated Financial Review — Gas Transmission".

 The current tolling methodology and rate design for the Alberta System features differentiated pricing for each gas receipt point on the Alberta System. The receipt-point price is dependent on geographic location, the diameter of the pipe through which the customer's natural gas travels, and the term of the transportation contract.

10    TRANSCANADA CORPORATION

 The Foothills System, which is regulated by the NEB and the Northern Pipeline Agency of Canada, is a 1,040 kilometre natural gas pipeline that transports western Canadian natural gas from central Alberta to connecting pipelines for transportation to markets in the U.S. Midwest, Pacific Northwest, California and Nevada. TransCanada merged Foothills' operations with its own in February 2004. TransCanada previously held a 50 per cent interest in Foothills and in August 2003, acquired the remaining interest.

 The Alaska Highway Pipeline Project, which will bring Prudhoe Bay natural gas from Alaska to markets in Canada and the U.S., involves pipeline construction in Canada and Alaska. Foothills holds the priority right to build, own and operate the first pipeline through Canada for the transportation of Alaskan gas. This right was granted under the Northern Pipeline Act of Canada following a lengthy competitive hearing before the NEB in the late 1970's which resulted in a decision in favor of Foothills.

 TransCanada spent approximately $1 million on the Foothills System in 2004 and anticipates that it will spend approximately $2 million on the Foothills System in 2005, primarily for maintenance capital.

 The BC System, which is regulated by the NEB, consists of 201 kilometres of pipeline that carries natural gas from a connecting point with the Alberta System through the southeastern corner of B.C. to connect with the GTN System at the Canada-U.S. border near Kingsgate, B.C. The GTN System delivers gas to markets in California, Nevada and the northwestern U.S. Further information can be found about the GTN System under the heading "General Development of the Business — Developments in Gas Transmission Business — 2004", above and under the heading "Business of TransCanada — Gas Transmission — Wholly Owned Pipelines — GTN System", below.

 In 2004, capital expenditures on the BC System were approximately $1 million, primarily for maintenance capital. TransCanada anticipates approximately $2 million of capital spending on the BC System in 2005, primarily for maintenance capital.

 The BC System is regulated on a complaint basis and the tolls are based on a cost-of-service methodology. In December 2003, the NEB adopted interim rates and charges for 2004 pending the resolution of compensation cost issues with shippers on the BC System. As discussions continue in an effort to resolve these issues, the BC System closed the year on interim rates. On December 23, 2004, the NEB adopted new interim rates and charges for 2005, again pending resolution of the outstanding issues.

 The GTN System, which is a natural gas pipeline system regulated by FERC, is comprised of more than 2,174 kilometres of pipeline and runs from a connection point on TransCanada's BC System near Kingsgate, B.C. on the B.C.-Idaho border to a point near Malin, Oregon on the Oregon-California border. The natural gas transported on this system originates primarily in Canada and is supplied to the Pacific Northwest, California and Nevada.

 As of Year End, 95 per cent of the GTN System's available long-term firm capacity was held among 43 shippers. The volume-weighted average remaining term of those contracts was approximately ten years. The GTN System operates under fixed rate models.

 TransCanada acquired the GTN System in November 2004 and anticipates approximately $11 million of capital spending on it in 2005, primarily for maintenance capital.

 The North Baja System is a 128 kilometre natural gas pipeline which extends from a point near Ehrenberg, Arizona to a point near Ogilby, California on the California-Mexico border. The natural gas transported on the North Baja System comes primarily from supplies in the southwestern U.S. for markets in northern Baja California, Mexico. FERC also regulates the North Baja System.

TRANSCANADA CORPORATION    11

 During 2004, the North Baja System provided long-term transportation service to four customers. As of Year End, the volume-weighted average remaining term of all long-term contracted capacities on the North Baja System was approximately 18 years. Long-term firm service accounted for 93 per cent of the North Baja System's total transportation revenue and transported volumes in 2004. Like the GTN System, the North Baja System operates under fixed rate models.

 TransCanada acquired the North Baja System in November 2004 and anticipates spending approximately $2 million on capital expenditures in 2005. The majority of these capital expenditures relate to accommodating future gas supplies from LNG facilities on the Pacific Coast of Mexico, which are expected to be operational in 2007.

Other Gas Transmission

 TransCanada actively pursues natural gas pipeline and pipeline-related development, acquisition and operation opportunities in Canada and the U.S., where these opportunities are driven by strong customer demand.

 TransCanada holds a 50 per cent interest in the Great Lakes System which is a 3,387 kilometre pipeline system which is operated by Great Lakes Gas Transmission Limited Partnership. The Great Lakes System transports Canadian natural gas from its interconnection with the Canadian Mainline at Emerson, Manitoba to markets in central Canada through an interconnect at St. Clair, Ontario as well as markets in the eastern and midwestern U.S. The Great Lakes System's rates are based on a five year settlement agreement which was approved by FERC in 2001 and is effective until October 31, 2005.

 TC PipeLines, L.P., a U.S. publicly-held limited partnership, was formed to acquire, own and participate in the management of U.S. based pipeline assets which are regulated by FERC. In May 1999, TransCanada's 30 per cent general partner interest in Northern Border Pipeline was conveyed to TC PipeLines, L.P. in exchange for cash and a 33.4 per cent interest in TC PipeLines, L.P., 31.4 per cent of which is comprised of units and two per cent of which is a general partnership interest. TC PipeLines, L.P. issued the balance of the units to the public. The main asset of TC Pipelines, L.P. is the 30 per cent interest in Northern Border Pipeline which operates a 2,010 kilometre natural gas pipeline system which connects with the Foothills System at the Saskatchewan-Montana border and serves the midwestern U.S., terminating at North Hayden, Indiana. In October 2001, Northern Border Pipeline completed a 55 kilometre pipeline extension and installed additional compression that provided 545 MMcf/d of incremental transportation capacity to North Hayden, Indiana and expanded Northern Border Pipeline's delivery capability into the Chicago area by approximately 30 per cent.

 In September 2000, TC PipeLines, L.P. acquired a 49 per cent general partnership interest in Tuscarora from TCPL. Tuscarora owns a 386 kilometre natural gas pipeline system which transports natural gas from Malin, Oregon to Wadsworth, Nevada and delivers to points in northeastern California. In January 2001, the Tuscarora system was extended by the addition of a second citygate connection to the expanding Reno, Nevada metropolitan market.

 A subsidiary of TransCanada acts as the general partner of TC PipeLines, L.P.

 The Iroquois System, which is regulated by FERC, connects with the Canadian Mainline near Waddington, New York and delivers natural gas to customers in the northeastern U.S. TransCanada's aggregate interest in the Iroquois System, through two subsidiaries, is approximately 41 per cent.

 Iroquois' Eastchester extension and expansion was completed and the facilities were put into service in February 2004. This expansion extends the Iroquois System from Long Island into New York City, adding 59 kilometres to the Iroquois System and will provide an additional 230 MMcf/d of new service into this market. The Iroquois System is now 663 kilometres in length.

12    TRANSCANADA CORPORATION


 In January 2004, Iroquois filed a rate application with FERC to establish rates for the Eastchester expansion. As a result of settlement conferences held in June and July 2004, Iroquois submitted a comprehensive settlement agreement to FERC in August 2004, which was approved by FERC in October 2004. The settlement agreement provides for recourse rates applicable until 2011 and implements an eight year rate moratorium for Eastchester.

 TransCanada holds a 50 per cent interest in the 572 kilometre TQM System which connects with the Canadian Mainline. TQM serves markets in Québec and connects with the Portland system. The TQM System is regulated by the NEB.

 TransCanada holds a 61.7 per cent controlling interest in Portland which is a 471 kilometre interstate pipeline that interconnects with the pipeline system of TQM at the U.S.-Canada border near East Hereford, Québec, and with the Tennessee Gas Pipeline in Haverhill and Dracut, Massachusetts. The southern sections of Portland's system, consisting of 163 kilometres of pipeline, are part of the joint facilities shared with the Maritimes and Northeast Pipeline. Portland holds a one-third ownership interest in the joint facilities. Portland is regulated by FERC.

 In August 2004, Portland initiated a restructuring plan whereby all of its operating and administrative functions would be performed by TransCanada pursuant to a services agreement. The transition of duties was completed by November 2004.

 In 2004, TransCanada continued to pursue pipeline opportunities to move both Mackenzie Delta and Alaska North Slope natural gas to markets throughout North America. TransCanada worked with key stakeholders in the interest of participating in these pipeline projects, as set out below:

 TransCanada, the Mackenzie Producers and the APG reached funding and participation agreements in June 2003. These agreements secured a role for TransCanada in the proposed Mackenzie Gas Pipeline Project and entitled the APG to become an equity participant. The Mackenzie Gas Pipeline Project involves the construction and operation of a natural gas pipeline system in the Mackenzie Valley that would move Mackenzie Delta natural gas from Inuvik, Northwest Territories to the northern border of Alberta, where it would connect with the Alberta System. TransCanada has agreed to finance the APG for its one-third share of project development costs. This share is currently expected to be $90 million. This loan will be repaid from the APG's share of available future pipeline revenues. TransCanada funded $34 million of this loan in 2003 and another $26 million in 2004, for a total funding of $60 million to date.

 In October 2004, Imperial Oil Resources announced that applications for the main regulatory approvals for the Mackenzie Gas Pipeline Project had been submitted to the boards, panels and agencies responsible for assessing and regulating energy developments in the Northwest Territories. These filings mark a significant milestone in the project definition phase.

 In 2004, TransCanada continued its discussions with Alaska Highway pipeline stakeholders including Alaska North Slope producers and the State of Alaska, relating to the Alaskan portion of the Alaska Highway pipeline project. In June 2004, TransCanada filed an application under the State of Alaska's Stranded Gas Development Act, and requested the State to resume processing the long pending application for a right of way lease across State lands. Once the right of way lease application is approved, TransCanada is prepared to convey the right of way lease to another entity if that entity is willing to connect with TransCanada's pipeline system. The lease conveyance would require an interconnection agreement with TransCanada at the Yukon-Alaska border.

 In January 2004, Foothills and the Kaska First Nation signed an Agreement in Principle that provides the framework for a future participation agreement. The Agreement in Principle marks the completion of the second stage of negotiations related to a potential participation agreement for the Alaska Highway Pipeline Project.

TRANSCANADA CORPORATION    13

 In September and November of 2004, TransCanada announced plans for the development of two significant LNG facilities: the Cacouna Energy LNG facility and the offshore Broadwater Energy LNG regasification terminal. These developments are more fully described under the heading "General Development of the Business — Developments in Gas Transmission Business — 2004", above in this AIF.

 TransCanada Pipeline Ventures Limited Partnership ("Ventures LP"), which is wholly owned by TransCanada, owns a 121 kilometre pipeline and related facilities, which supply natural gas to the oil sands region of northern Alberta, and a 27 kilometre pipeline which supplies natural gas to a petrochemical complex at Joffre, Alberta.

 TransCanada holds a 60 per cent interest in the Crossfield Storage Joint Venture which controls an underground gas storage facility near Crossfield, Alberta. The facility is commercially operated on behalf of the joint venture by CrossAlta Gas Storage & Services Ltd., in which TransCanada also holds a 60 per cent interest.

 TransCanada holds a 46.5 per cent interest in TransGas de Occidente S.A., a Colombian corporation which operates a 344 kilometre natural gas pipeline between the cities of Mariquita and Cali, Colombia.

 TransCanada holds a 30 per cent interest in Gasoducto del Pacifico ("Gas Pacifico"), a 540 kilometre natural gas pipeline from Argentina to Concepción, Chile.

 TransCanada holds a 30 per cent interest in INNERGY Holdings S.A., an industrial natural gas transportation and marketing company operating in the area of Concepción, Chile, which markets natural gas transported on the Gas Pacifico system.

Regulation of North American Pipelines

 Under the National Energy Board Act (Canada), the NEB regulates the construction and operation of interprovincial pipelines and the Canadian portion of international pipelines as well as the traffic, tolls and tariffs applicable to those pipelines. The NEB also approves the import and export of natural gas.

 Pipelines located within provincial boundaries are regulated by the applicable provincial regulatory body.

 The construction and operations of the Alberta System and Ventures LP's pipeline are regulated by the EUB.

 With respect to TransCanada's U.S. pipeline investments, the U.S. Natural Gas Act of 1938 ("NGA") establishes the framework for regulation of interstate natural gas transportation, facilities construction and terms and conditions of service. FERC is charged with implementing the NGA's requirements. The terms and conditions of service under which TransCanada transports natural gas on the Great Lakes System, are subject to NGA authorizations issued by FERC. Interconnected natural gas pipelines and other U.S. interstate pipeline projects in which TransCanada owns an interest, are subject to FERC and NGA regulation, as well as certain state regulatory requirements.

 Further information about the regulation of the Canadian Mainline, Alberta System and other pipeline systems, can be found under the heading "Business of TransCanada — Gas Transmission — Wholly Owned Pipelines" above.

14    TRANSCANADA CORPORATION


Competition in Gas Transmission

 TransCanada's wholly-owned pipelines are connected to and supplied by one of North America's largest natural gas basins, the WCSB. However, the WCSB is maturing and it will be a challenge for producers to increase production in this basin. Other pipeline systems connected to the WCSB, including some of TransCanada's interconnected pipelines, have expanded in the last few years. These expansions have provided shippers with additional flexibility and competitive choices when moving WCSB supplies to market. The WCSB gas supply is expected to remain essentially flat.

 The Alberta System is the primary transporter of natural gas within the province of Alberta and to provincial boundary points. However, there are a number of alternative pipelines which offer price advantages and which compete with the Alberta System. In anticipation of and in response to these developments, the Alberta System's current tolling methodology was designed to enhance NGTL's ability to provide competitive pricing and service flexibility and to provide TransCanada with the ability to respond to potential future export bypass pipelines.

 The Canadian Mainline is now one of five natural gas pipelines providing transportation service from the WCSB. Increased competition has led to the non-renewal of some of the firm service contracts on the Alberta System and the Canadian Mainline, and has led to decreased utilization on certain pipeline segments.

 Further information about business risks in Gas Transmission can be found under the heading "Risk Factors — Gas Transmission" below and in the MD&A under the headings "Gas Transmission — Opportunities and Developments" and "Gas Transmission — Business Risks".

Research and Development

 In 2004, TransCanada spent approximately $7.0 million on research and development activities of which approximately $2.5 million related to research on pipeline integrity management, approximately $3.0 million on other regulated pipeline activities and approximately $1.5 million on non-regulated pipeline ventures.

Power

 The Power segment of TransCanada's business includes the acquisition, development, construction, ownership, operation and management of power plants, the marketing of electricity and the provision of electricity account services to energy and industrial customers.

 The power plants and power supply that TransCanada owns, operates and/or controls, including those under development or in construction, in the aggregate, represent approximately 5,700 MW of power generation capacity in Canada and the U.S.

 TransCanada owns and operates:


 TransCanada has long-term power purchase arrangements in place for:

 TransCanada owns, but does not operate:

TRANSCANADA CORPORATION    15

 TransCanada owns the following facilities which are under construction or development:

 TransCanada is in the process of acquiring hydroelectric generation assets from USGen which are located on two rivers in New England and which will have a generating capacity of up to 518 MW, which excludes the generating capacity of the Bellows Falls facility (49 MW) as this plant is the subject of a purchase option held by a third party which has been exercised but not yet closed.

 TransCanada has a power marketing office in Westborough, Massachusetts to manage the Ocean State Power purchase agreements and fulfill supply obligations, and to take advantage of additional marketing opportunities in the New England and New York markets. The office also markets the output of Power LP's Castleton power plant.

 Operations and maintenance services for the Bruce Power plant continue to be supplied by Bruce Power management and staff. Bruce Power leases the Bruce Power facilities from OPG and currently operates six nuclear power units out of the eight on site. The two units that are not being operated are laid up. Bruce Power sells the output from the operating units through a combination of fixed-price contracts and spot market sales. Bruce Power is the tenant under a long-term lease with OPG and under the terms of the lease, spent fuel and site decommissioning liabilities remain the responsibility of OPG. Bruce Power is subject to risks related to the operation and maintenance of the nuclear power generating facilities, including risks relating to the use, handling, containment and storage of radioactive materials; limitations on the amounts and types of insurance that are commercially available to cover any related liabilities that may arise from these operations; changes in and varying interpretations of the extensive federal regulations that apply to Bruce Power's nuclear operations; modifications needed to meet increasing security requirements; and repairs, modifications, replacements and outages that may be necessitated as a result of testing and inspection programs which, themselves, may need to be enhanced in coming years to improve operations or satisfy increasing regulatory or other requirements.

 Late in the fourth quarter of 2004, TransCanada responded to the Ontario government's Request for Proposals for 2,500 MW of new electricity generation capacity. TransCanada and OPG, through their limited partnership, Portlands Energy Centre L.P., responded by proposing a 550 MW combined-cycle natural gas-fuelled power plant that would be located in the Portlands area of downtown Toronto, Ontario. TransCanada, in its own right, responded to the Request for Proposals with another, unrelated proposal.

 TransCanada continues to investigate potential power investment opportunities throughout North America, including a potential investment, together with its Bruce Power partners, in the Point Lepreau nuclear generating station in New Brunswick. The Point Lepreau facility, which is indirectly owned by the New Brunswick provincial government, is a 680 MW nuclear power plant with a CANDU reactor similar to the reactors operated by Bruce Power. No decision has been made by TransCanada and its partners as to whether an investment will be made in the Point Lepreau facility; however, discussions are ongoing with New Brunswick Power.

TransCanada Power, L.P.

 TransCanada is the general partner of, manages and operates Power LP and holds 30.6 per cent of its outstanding limited partnership units. Power LP is a publicly-held limited partnership that owns eleven power plants in Canada and the U.S. which generate approximately 744 MW of power. It is one of the largest publicly traded power limited partnerships in Canada with a market capitalization of approximately $1.7 billion. TransCanada supplies the natural gas fuel and waste heat for certain of Power LP's plants and buys output from one of the plants.

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 Power LP owns:

Other Power

 TransCanada effectively holds an approximate 11 per cent interest in PT Paiton Energy Company, which owns a power project consisting of two 615 MW coal-fired power units located in Indonesia.

Power Performance

 The following tables set forth the revenues earned, power volumes marketed and generation capacity in Canada and the U.S. for the years ended December 31, 2004 and 2003 from TransCanada's power operations.


 
 
2004
 
2003
 
   Revenues
   Per cent
   Revenues
   Per cent
 
   (millions of dollars)
   
   (millions of dollars)
   
Revenues(1)                
Canada — Domestic   706   59   765   55
Canada — Export   2   —   2   —
United States   482   41   634   45
   
 
 
 
Total   1,190   100   1,401   100
   
 
 
 

 
 
2004
 
2003
 
   Volume
   Per cent
   Volume
   Per cent
 
   (gigawatt hours)
   
   (gigawatt hours)
   
Volumes Sold(2)(3)(4)                
Canada — Domestic   24,426   79   20,575   74
Canada — Export   37   —   38   —
United States   6,457   21   7,397   26
   
 
 
 
Total   30,920   100   28,010   100
   
 
 
 

TRANSCANADA CORPORATION    17


 
 
2004
 
2003
 
   Generation
   Per cent
   Generation
   Per cent
 
   (MW)
   
   (MW)
   
Generation Capacity(2)(3)(4)(5)(6)                
Canada   3,112   76   2,641   73
United States   984   24   984   27
   
 
 
 
Total   4,096   100   3,625   100
   
 
 
 

Notes:

(1)
2004 revenues reflect the sale of Curtis Palmer and ManChief facilities to Power LP on April 30, 2004.

(2)
Includes 100 per cent of volumes sold by, and the generation capacity of, Power LP (after eliminating intercompany transactions with TransCanada).

(3)
TransCanada, directly or indirectly, acquires 560 MW from Sundance A and 353 MW from Sundance B through long-term power purchase arrangements, which represent 100 per cent of the Sundance A and 50 per cent of the Sundance B power plant output, respectively.

(4)
Sales volumes in 2003 reflect TransCanada's 31.6 per cent share of Bruce Power output from the acquisition date of February 14, 2003.

(5)
2004 excludes Bécancour (550 MW) and Grandview (90 MW) which were not in commercial service at Year End. 2003 excludes MacKay River (165 MW), Bécancour (550 MW), Grandview (90 MW) and Bruce, Unit 3 (237 MW) which were not in commercial service at December 31, 2003.

(6)
Excludes USGen generation capacity (518 MW, excluding the Bellows Falls facility), which TransCanada expects to acquire in 2005. Also excludes TransCanada's proportionate share of Cartier Wind Energy's generation capacity (458 MW) which is under development.

Regulation of Power

 Deregulation of the power industry is proceeding at different stages throughout most of the markets in which TransCanada currently operates, which are primarily Alberta, Ontario and the northeastern U.S. In 2001, Alberta deregulated its generation assets and opened the market for retailers and wholesalers. In May 2002, the government of Ontario created a competitive, bid-based wholesale market for electricity in Ontario, a process that began with legislation first enacted under the Electricity Act in 1998. Later in 2002, after considerable volatility and rising prices under this new market, the government of Ontario instituted retail price caps, effectively shielding eligible customers from wholesale price volatility. After a change in government in Ontario, these retail caps were increased on April 1, 2004, to better reflect the cost of electricity. These caps do not directly affect the wholesale market in which TransCanada is primarily focused. In December 2004, the government of Ontario again restructured the Ontario markets by passing the Electricity Restructuring Act, 2004 ("ERA"). Among other things, the ERA places certain of the Ontario Power Generation Corporation's baseload nuclear and hydro generation assets under direct rate regulation by the Ontario Energy Board. Bruce Power was not affected by this legislation and remains a participant in the wholesale market in Ontario. Bruce Power is presently in discussions with a provincially appointed negotiator respecting the possible restart of Bruce Power's units 1 and 2. It is unclear whether these negotiations will result in any change to the commercial context in which Bruce Power operates. In addition, the ERA provides for a return to coordinated system planning by the newly created Ontario Power Authority ("OPA"), which is charged with managing the long-term supply of electricity in Ontario. The OPA will assume responsibility for procuring electricity supply through requests for proposals or otherwise, and will enter into new power purchase agreements with generators responding to procurement initiatives. It is possible that these and subsequent changes in Ontario's power industry, will have both positive and negative impacts on TransCanada's Ontario power operations.

 TransCanada's investment in Ocean State Power and TransCanada's U.S. electric power marketing activities are subject to the jurisdiction of FERC under the U.S. Federal Power Act, as well as to the jurisdiction of certain state regulatory authorities in which the generation facilities are located. In 1998 and 1999, respectively, FERC began operation of competitive, bid-based wholesale power markets in New England and New York. These markets continue to evolve through consultation with government, regulators and market stakeholders. The northeastern markets in which TransCanada operates are converging in terms of structure with the recent adoption of Standard Market Design elements that have been defined by FERC.

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Competition in Power

 TransCanada's power business has operated and continues to operate in highly competitive markets with many participants that are driven mainly by price. TransCanada mitigates the effects of short-term changes in the market using various forms of hedging, including entering into fixed price forward sales. The quantity and term of such forward sales varies by region and depends on liquidity of markets in these regions. TransCanada also retains an amount of unsold generation capacity in order to preserve its flexibility in the short-term to manage TransCanada's portfolio of assets.

 Further information about business risks in TransCanada's power business can be found in the MD&A under the heading "Risk Factors — Power" below and in the MD&A under the heading "Power — Business Risks".

Other Interests

Cancarb Limited

 TransCanada owns Cancarb Limited, a world scale thermal carbon black manufacturing facility located in Medicine Hat, Alberta.

TransCanada Turbines

 TransCanada owns a 50 per cent interest in TransCanada Turbines Ltd., a repair and overhaul business for aero-derivative industrial gas turbines. This business operates primarily out of facilities in Calgary, Alberta, with offices in Bakersfield, California; East Windsor, Connecticut and Liverpool, England.

TransCanada Calibrations

 TransCanada owns an 80 per cent interest in TransCanada Calibrations Ltd., a gas meter calibration business certified by Measurement Canada, located at Ile des Chênes, Manitoba.

Discontinued Operations

 Since 1999, TransCanada has focused on natural gas transmission and power generation in North America. During that time, TransCanada sold substantially all of its assets in the international, midstream, and oil and gas marketing businesses. For further information about Discontinued Operations please refer to the MD&A under the heading "Corporate — Discontinued Operations".


HEALTH, SAFETY AND ENVIRONMENT

 TransCanada is committed to providing a safe and healthy environment for its employees and the public, and to the protection of the environment. Health, safety and environment ("HS&E") is a priority in all of TransCanada's operations. The HS&E Committee of TransCanada's Board of Directors ("Board") monitors compliance with the TransCanada HS&E corporate policy through regular reporting by TransCanada's department of Community, Safety & Environment. TransCanada's senior executives are also committed to ensuring TransCanada is in compliance with its policies and is an industry leader. Senior executives are regularly advised of all important operational issues and initiatives relating to HS&E by way of a formal reporting process. In addition, TransCanada's management system and performance in the HS&E area are assessed by an independent outside firm every three years or more often if the HS&E Committee requests it. The most recent assessment was completed by PricewaterhouseCoopers in January of 2004. These assessments involve senior executive interviews, review of policies and objectives, performance measurement and reporting.

 TransCanada has an HS&E management system modeled after elements of the International Organization for Standardization's standard for environmental management systems which is known as ISO 14001, to facilitate the focus of resources on the areas of greatest risk to the organization's business activities relating to HS&E. It highlights opportunities for improvement, enables TransCanada to work towards defined HS&E expectations and objectives, and provides a competitive business advantage. HS&E outside, independent assessments, management system assessments and planned inspections are used to assess both the effectiveness of

TRANSCANADA CORPORATION    19


implementation of HS&E programs, processes and procedures, and TransCanada's compliance with regulatory requirements.

 TransCanada employs full-time staff dedicated to HS&E matters, and incorporates HS&E policies and principles into the planning, development, construction and operation of all its projects. Environmental protection requirements have not had a material impact on the capital expenditures of TransCanada to date; however, there can be no assurance that such requirements will not have a material impact on TransCanada's financial or operating results in future years. Such requirements can be dependent on a variety of factors including the regulatory environment in which TransCanada operates.

Environment

 The most significant environmental issues facing TransCanada relate to climate change. Climate change is a strategic issue for TransCanada, particularly in light of the Canadian government's ratification of the Kyoto Protocol which came into force in February 2005 and requires Canada to reduce its greenhouse gas emissions significantly. The Canadian government is currently developing the policies relating to how it intends to meet these reduction targets and, until it is completed, TransCanada cannot predict the degree to which it will be affected. TransCanada has had a comprehensive climate change strategy in place since 1999, which includes five key areas of activity:

 Activities in each of these areas occurred in 2004 and will continue in 2005.

 TransCanada received its sixth consecutive gold level reporting status for its 2004 Climate Change and Air Issues Annual Report from the Canadian Standards Association Canadian GHG Challenge Registry which was formerly the Voluntary Challenge and Registry ("VCR") program. To achieve gold level status, reports are rated in several categories. Only 12 per cent of the submissions to the registry have received gold level reporting recognition. In 2004, the VCR program was replaced with the Canadian GHG Challenge Registry as a result of the Canadian government passing legislation to mandate greenhouse gas emissions reporting.


LEGAL PROCEEDINGS

 The Canadian Alliance of Pipeline Landowners' Association and two individual landowners have commenced an action 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 National Energy Board Act. TransCanada believes the claim is without merit and will vigorously defend the action. TransCanada has made no provision for any potential liability. A liability, if any, would be dealt with through the regulatory process.

 TransCanada 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 TransCanada's management that the resolution of such proceedings and actions will not have a material impact on TransCanada's consolidated financial position or results of operations.

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TRANSFER AGENT AND REGISTRAR

 TransCanada's transfer agent and registrar is Computershare Trust Company of Canada with transfer facilities in the Canadian cities of Vancouver, Calgary, Winnipeg, Toronto, Montréal and Halifax.


INTEREST OF EXPERTS

 TransCanada's auditor is KPMG LLP and as of March 1, 2005, the partners of KPMG LLP do not hold any registered or beneficial ownership, directly or indirectly, in the securities of TransCanada.


RISK FACTORS

 A number of factors, including but not limited to those discussed in this section, could cause actual results or events to differ materially from current expectations.

 TransCanada's businesses are highly complex and are dispersed over tens of thousands of square kilometres, often in remote locations. Pipeline and power facilities are subject to operational risks, including mechanical failure, physical degradation, operator error, manufacturer defects, labour disputes, terrorism, failure of supply, catastrophic events and natural disasters. The occurrence or continuation of such events could increase TransCanada's costs and reduce its ability to transport natural gas or generate power.

Gas Transmission

 TransCanada faces competition in its gas transmission business at both the supply and market ends of its systems. The competition is a result of other pipelines accessing an increasingly mature WCSB and serving some of the same markets as TransCanada. In addition, the continued expiration of firm transportation contracts has resulted in significant reductions in firm contracted capacity on both the Canadian Mainline and Alberta System. As well, regulatory decisions continue to have significant impact on the financial returns for and future investments in TransCanada's Canadian wholly-owned pipelines.

 Further information about competition risks in TransCanada's natural gas transmission business can be found under the heading "Business of TransCanada — Gas Transmission — Competition in Transmission" above and in the MD&A under the headings "Gas Transmission — Opportunities and Developments" and "Gas Transmission — Business Risks".

Power

 TransCanada's power business and investments can be affected by a variety of factors including competition from other market participants, fluctuating market demand, reliance on the supply of feed stocks such as natural gas, wood waste, water, coal and uranium, fluctuating feed stock prices, fluctuating electricity prices, unexpected outages, third party power plant operator performance, power transmission disruptions and regulatory changes and influences.

 Further information about competition risks in TransCanada's power business can be found under the headings "Business of TransCanada — Power — Competition in Power" above and in the MD&A under the heading "Power — Business Risks".

International

 TransCanada's international investments are subject to a number of risks unique to international business. These risks include exchange controls and fluctuation of the local currency, political risk, community actions, changes in laws, price controls, the availability and quality of local labour skills, and labour unrest, among others. Such risks are mitigated by insurance policies, participation of local and foreign partners, prudent commercial structuring and other measures.

Corporate

 TransCanada carries on its businesses with numerous counterparties with a wide range of creditworthiness. While processes are followed to address the creditworthiness of these counterparties, the failure of any

TRANSCANADA CORPORATION    21


counterparty to meet its financial obligations could have an impact on TransCanada's financial position. Such failure could result from a number of factors beyond TransCanada's control, including (but not limited to) fluctuating energy prices, currency exchange and interest rates, changes in regulatory and economic environments, political instability and legally reviewable activities.

 TransCanada operates primarily in Canada and the U.S. and as a result, its financial performance can be impacted by interest rates and foreign exchange rates. TransCanada has an active hedging program in place to address interest and foreign exchange rate risks, but there can be no assurance that such hedging will be adequate to address the risks.

 TransCanada's growth strategy is dependent upon acquiring or constructing facilities and businesses that align with or complement its current businesses. TransCanada may incur costs in the pursuit of acquisitions or development of power or natural gas transmission assets that may not be completed. Failure by TransCanada to consummate negotiated acquisitions or new developments may result in contractual liabilities, liquidated damages, additional costs and expenses which could affect financial performance.

 TransCanada's growth is also dependent on access to capital markets in the U.S. and Canada. Although significant credit facilities are currently available, changing market conditions could result in a materially increased cost of, or reduced access to capital which would reduce TransCanada's ability to pursue growth opportunities.

 Further information about TransCanada's risk factors and risk management can be found in the MD&A under the headings "Gas Transmission — Business Risks", "Power — Business Risks" and "Risk Management".


DIVIDENDS

 TransCanada has no formal dividend policy. The Board reviews the financial performance of TransCanada quarterly and makes a determination of the appropriate level of dividends to be declared in the following quarter. Currently, TransCanada's payment of dividends on its common shares is funded from dividends TransCanada receives as the sole shareholder of TCPL common shares. Provisions of various trust indentures and credit arrangements to which TCPL is a party, restrict TCPL's ability to declare and pay dividends to TransCanada, under certain circumstances and, if such restrictions apply, they may, in turn, have an impact on TransCanada's ability to declare and pay dividends on its common shares. In the opinion of TransCanada management, such provisions do not restrict or alter TransCanada's ability to declare or pay dividends.

 The dividends declared per share during the past three completed financial years are set forth in the following table:

 
   2004
   2003
   2002
Dividends declared on common shares(1)   1.16   1.08   1.00
   
 
 

Note:

(1)
Prior to May 15, 2003, dividends were paid by TCPL.


DESCRIPTION OF CAPITAL STRUCTURE

Share Capital

 TransCanada's authorized share capital consists of an unlimited number of common shares, of which approximately 484,914,324 were issued and outstanding at Year End, and an unlimited number of first preferred shares and second preferred shares issuable in series, of which none are outstanding. The following is a description of the material characteristics of each of these classes of shares.

 The common shares entitle the holders thereof to one vote per share at all meetings of shareholders, except meetings at which only holders of another specified class of shares are entitled to vote, and, subject to the rights, privileges, restrictions and conditions attaching to the first preferred shares and the second preferred shares, whether as a class or a series, and to any other class or series of shares of TransCanada which rank prior to the

22    TRANSCANADA CORPORATION

common shares, entitle the holders thereof to receive (i) dividends if, as and when declared by the Board out of the assets of TransCanada properly applicable to the payment of the dividends in such amount and payable at such times and at such place or places as the Board may from time to time determine and (ii) the remaining property of TransCanada upon a dissolution.

 Subject to certain limitations, the Board may, from time to time, issue first preferred shares in one or more series and determine for any such series, its designation, number of shares and respective rights, privileges, restrictions and conditions. The first preferred shares as a class, have, among others, provisions to the following effect.

 The first preferred shares of each series shall rank on a parity with the first preferred shares of every other series, and shall be entitled to preference over the common shares, the second preferred shares and any other shares ranking junior to the first preferred shares with respect to the payment of dividends, the repayment of capital and the distribution of assets of TransCanada in the event of a liquidation, dissolution or winding up of TransCanada.

 Except as provided by the Canada Business Corporations Act or as referred to below, the holders of the first preferred shares will not have any voting rights nor will they be entitled to receive notice of or to attend shareholders' meetings. The holders of any particular series of first preferred shares will, if the directors so determine prior to the issuance of such series, be entitled to such voting rights as may be determined by the directors if TransCanada fails to pay dividends on that series of preferred shares for any period as may be so determined by the directors.

 The provisions attaching to the first preferred shares as a class may be modified, amended or varied only with the sanction of the holders of the first preferred shares as a class. Any such sanction to be given by the holders of the first preferred shares may be given by the affirmative vote of the holders of not less than 662/3 per cent of the first preferred shares represented and voted at a meeting or adjourned meeting of such holders.

 The rights, privileges, restrictions and conditions attaching to the second preferred shares are substantially identical to those attaching to the first preferred shares, except that the second preferred shares are junior to the first preferred shares with respect to the payment of dividends, repayment of capital and the distribution of assets of TransCanada in the event of a liquidation, dissolution or winding up of TransCanada.


RATINGS

 TransCanada has not issued debt and is not rated. However, the following table sets out the credit ratings of outstanding classes of securities of TransCanada's subsidiary, TCPL, which has been rated:

Overall
   DBRS
   Moody's
   S&P
Senior Secured Debt            
  First Mortgage Bonds   A   A2   A
Senior Unsecured Debt            
  Debentures   A   A2   A-
  Medium-term Notes   A   A2   A-
Subordinated Debt   A (low)   A3   BBB+
Junior Subordinated Debt   Pfd-2   A3   BBB
Preferred Shares   Pfd-2 (low)   Baa1   BBB
Commercial Paper   R-1 (low)   P-1   —
Trend/Rating Outlook   Stable   Stable   Negative

 Credit ratings are intended to provide investors with an independent measure of credit quality of an issue of securities. Credit ratings are not recommendations to purchase, hold or sell securities and do not address the market price or suitability of a specific security for a particular investor. There is no assurance that any rating

TRANSCANADA CORPORATION    23


will remain in effect for any given period of time or that any rating will not be revised or withdrawn entirely by a rating agency in the future if, in its judgment, circumstances so warrant. A description of the rating agencies' credit ratings listed in the table above is set out below.

Dominion Bond Rating Service (DBRS)

 DBRS has different rating scales for short and long-term debt and preferred shares. "High" or "low" grades are used to indicate the relative standing within a rating category. The absence of either a "high" or "low" designation indicates the rating is in the "middle" of the category. The R-1 (low) rating assigned to TransCanada's short-term debt is the third highest of ten rating categories and indicates satisfactory credit quality. The overall strength and outlook for key liquidity, debt and profitability ratios is not normally as favourable as with higher rating categories, but these considerations are still respectable. Any qualifying negative factors that exist are considered manageable, and the entity is normally of sufficient size to have some influence in its industry. The A ratings assigned to TransCanada's senior secured and senior unsecured debt and the A (low) rating assigned to its subordinated debt are the third highest of ten categories for long-term debt. Long-term debt rated A is of satisfactory credit quality. Protection of interest and principal is still substantial, but the degree of strength is less than that of AA rated entities. While a respectable rating, entities in the A category are considered to be more susceptible to adverse economic conditions and have greater cyclical tendencies than higher rated entities. The Pfd-2 and Pfd-2 (low) ratings assigned to TransCanada's junior subordinated debt and preferred shares are the second highest of six rating categories for preferred shares. Preferred shares rated Pfd-2 are of satisfactory credit quality. Protection of dividends and principal is still substantial; however, earnings, the balance sheet and coverage ratios are not as strong as Pfd-1 rated companies.

Moody's Investor Services (Moody's)

 Moody's has different rating scales for short and long-term obligations. Numerical modifiers 1, 2 and 3 are applied to each rating classification, with 1 being the highest and 3 being the lowest. The P-1 rating assigned to TransCanada's short-term debt is the highest of four rating categories and indicates a superior ability to repay short-term debt obligations. The A2 ratings assigned to TransCanada's senior secured and senior unsecured debt and the A3 ratings assigned to its subordinated debt and junior subordinated debt are the third highest of nine rating categories for long-term obligations. Obligations rated A are considered upper-medium grade and are subject to low credit risk. The Baa1 rating assigned to TransCanada's preferred shares is the fourth highest of nine rating categories for long-term obligations. Obligations rated Baa are subject to moderate credit risk, are considered medium-grade, and as such, may possess certain speculative characteristics.

Standard & Poor's (S&P)

 S&P has different rating scales for short and long-term obligations. Ratings may be modified by the addition of a plus (+) or minus (-) sign to show the relative standing within a particular rating category. The A and A- ratings assigned to TransCanada's senior secured and senior unsecured debt are the third highest of ten rating categories for long-term obligations. An A rating indicates the obligor's capacity to meet its financial commitment is strong; however, the obligation is somewhat susceptible to the adverse effects of changes in circumstances and economic conditions than obligations in higher rated categories. The BBB+ rating assigned to TransCanada's subordinated debt and the BBB ratings assigned to its junior subordinated debt and preferred shares are the fourth highest of ten rating categories for long-term obligations. An obligation rated BBB exhibits adequate protection parameters. However, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the obligor to meet its financial commitment on the obligation.

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MARKET FOR SECURITIES

 TransCanada's common shares are listed on the Toronto Stock Exchange ("TSX") and the New York Stock Exchange ("NYSE"). The following table sets forth the reported monthly high and low closing prices and monthly trading volumes of the common shares of TransCanada on the TSX for the period indicated:

Common Shares (TRP)

Month
   High
($)
   Low
($)
   Volume Traded
December, 2004   30.35   28.51   18,175,381
November, 2004   29.52   27.00   17,243,717
October, 2004   28.31   26.98   21,415,001
September, 2004   28.60   27.11   29,869,649
August, 2004   27.72   26.28   14,911,517
July, 2004   26.79   25.37   17,985,303
June, 2004   27.30   25.70   21,550,578
May, 2004   28.39   26.92   19,232,179
April, 2004   29.40   26.31   29,357,948
March, 2004   29.72   27.60   39,732,275
February, 2004   27.83   26.47   27,926,798
January, 2004   28.43   26.45   22,784,477

 In addition, the following securities of TransCanada's subsidiaries, TCPL and NGTL, are listed on the markets specified:


DIRECTORS AND OFFICERS

 As of March 7, 2005, the directors and executive officers of TransCanada as a group beneficially owned, directly or indirectly, or exercised control or direction over, 2,601,214 common shares of TransCanada and 19,800 units of Power LP, which constitutes less than one per cent of TransCanada's common shares and less than one per cent of the voting securities of any of its subsidiaries or affiliates. TransCanada collects this information from its directors and officers but otherwise has no direct knowledge of individual holdings of its securities. Further information as to securities beneficially owned, or over which control or direction is exercised, is provided in TransCanada's Management Proxy Circular dated March 1, 2005 ("Proxy Circular") under the heading "Business To Be Transacted at the Meeting — Election of Directors". See also "Additional Information" in this AIF.

Directors

 Set forth below are the names of the twelve directors who served on TransCanada's Board at Year End, together with their jurisdictions of residence, all positions and offices held by them with TransCanada and its significant affiliates, their principal occupations or employment during the past five years and the year from which each

TRANSCANADA CORPORATION    25


director has continually served as a director of TransCanada and, prior to the arrangement, with TCPL. Positions and offices held with TransCanada are also held by such person at TCPL.

Name and Place of Residence
   Principal Occupation During The Five Preceding Years
   Director Since
Douglas D. Baldwin
Calgary, Alberta
Canada		   Chairman, Talisman Energy Inc., (oil and gas) since May 2003. President and Chief Executive Officer, TCPL, from August 1999 to April 2001. Director, Calgary Airport Authority, Citadel Group of Funds, Resolute Energy Inc. and UTS Energy Corporation. Member, Board of Governors, University of Calgary.   1999
Wendy K. Dobson
Uxbridge, Ontario
Canada		   Professor, Rotman School of Management and Director, Institute for International Business, University of Toronto (education). Director, MDS Inc., Toronto-Dominion Bank and Vice Chair, Canadian Public Accountability Board.   1992
The Hon. Paule Gauthier,
P.C., O.C., O.Q., Q.C.
Québec, Québec
Canada		   Senior Partner, Desjardins Ducharme Stein Monast (law firm). Director, Royal Bank of Canada, The Royal Trust Corporation of Canada, The Royal Trust Company, Rothmans Inc. and Metro Inc. Chair, Security Intelligence Review Committee. President, Fondation de la Maison Michel Sarrazin and President, Institut Québecois des Hautes Études Internationales, Laval University.   2002
Richard F. Haskayne,
O.C., F.C.A.
Calgary, Alberta
Canada		   Chairman of the Board, TransCanada and TCPL. Prior to February 19, 2003, Chairman, Fording Inc. (coal and wollastonite). Director, EnCana Corporation and Weyerhauser Company.   1998
(NOVA, 1991)(1)
Kerry L. Hawkins
Winnipeg, Manitoba
Canada		   President, Cargill Limited (grain handlers, merchants, transporters, processors of agricultural products and gas marketers). Director, NOVA Chemicals Corporation, Shell Canada Limited and Hudson's Bay Company.   1996
S. Barry Jackson
Calgary, Alberta
Canada		   Chairman, Resolute Energy Inc. (oil and gas) since 2002 and Chairman, Deer Creek Energy Limited (oil and gas) since 2001. President and Chief Executive Officer, Crestar Energy Inc. (oil and gas) from 1993 to 2000. Director, Nexen Inc.   2002
Paul L. Joskow
Brookline, Massachusetts
United States		   Professor, Department of Economics, Massachusetts Institute of Technology (MIT) (education). Director of the MIT Center for Energy and Environmental Policy Research. Director, National Grid Transco plc. Trustee, Putnam Mutual Funds and President, Yale University Council.   2004
         

26    TRANSCANADA CORPORATION

Harold N. Kvisle(2)
Calgary, Alberta
Canada		   President and Chief Executive Officer, TransCanada since May 2003 and TCPL since May 2001. Executive Vice-President, Trading and Business Development, TCPL, from June 2000 to April 2001. Senior Vice-President, Trading and Business Development, TCPL, from April 2000 to June 2000. Senior Vice-President and President, Energy Operations, TCPL, from September 1999 to April 2000. Director, PrimeWest Energy Inc. and Bank of Montreal. Past Chair, Interstate National Gas Association of America (INGAA) and Chair, Mount Royal College.   2001
David P. O'Brien(3)
Calgary, Alberta
Canada		   Chairman, EnCana Corporation (oil and gas) since April 2002 and Chairman, Royal Bank of Canada (banking) since February 2004. Chairman and Chief Executive Officer, PanCanadian Energy Corporation (oil and gas) from October 2001 to April 2002. Chairman, President and Chief Executive Officer, Canadian Pacific Limited (transportation, energy and hotels) from May 1996 to October 2001. Director, Fairmont Hotels & Resorts Inc., Inco Limited, Molson Coors Brewing Company, Profico Energy Management Ltd. and The E & P Limited Partnership.   2001
James R. Paul
Kingwood, Texas
United States		   Chairman, James and Associates (private investment firm). Member of the Advisory Board, AMEC plc.   1996
Harry G. Schaefer, F.C.A.
Calgary, Alberta
Canada		   President, Schaefer & Associates (business advisory services). Vice-Chairman of the Board, TransCanada and TCPL. Chairman, Crestar Energy Inc. (oil and gas) from May 1996 to November 2000. Director, Agrium Inc. and Fording Canadian Coal Trust. Chairman, Alberta Chapter, Institute of Corporate Directors, Fellow, Institute of Corporate Directors and Director, The Mount Royal College Foundation.   1987
W. Thomas Stephens
Boise, Idaho
United States		   Chairman and Chief Executive Officer, Boise Cascade LLC since November 2004. Director, The Putnam Funds.   1999

Notes:

(1)
NOVA Corporation merged with TCPL on July 2, 1998.

(2)
Mr. Kvisle will not stand for re-election as a director of Norske Skog Canada Limited at its April 27, 2005 annual meeting. Mr. Kvisle was elected to the Bank of Montreal's Board of Directors on February 22, 2005.

(3)
Mr. O'Brien was a director of Air Canada on April 1, 2003 when Air Canada filed for protection under the Companies' Creditors Arrangement Act (Canada). Mr. O'Brien resigned as a director from Air Canada in November 2003.

 Each director holds office until the next annual meeting or until his or her successor is earlier elected or appointed. Mr. Haskayne and Mr. Paul will be retiring from their respective positions on the Board on April 29, 2005. Mr. Jackson has been designated as the next Chair of the Board and will succeed Mr. Haskayne as Chair upon his retirement on April 29, 2005.

TRANSCANADA CORPORATION    27

Officers

 All of the executive officers and corporate officers of TransCanada reside in Calgary, Alberta, Canada. References to positions and offices with TransCanada prior to May 15, 2003 are references to the positions and offices held with TCPL. Current positions and offices held with TransCanada are also held by such person at TCPL. As of the date hereof, the officers of TransCanada, their present positions within TransCanada and their principal occupations during the five preceding years are as follows:

Name
   Present Position Held
   Principal Occupation During the Five Preceding Years
Harold N. Kvisle   President and Chief Executive Officer   Executive Vice-President, Trading and Business Development, June 2000 to April 2001. Senior Vice-President, Trading and Business Development, April 2000 to June 2000. Senior Vice-President and President, Energy Operations, September 1999 to April 2000.

Albrecht W.A. Bellstedt, Q.C.(1)
 
Executive Vice-President, Law and General Counsel
 
Senior Vice-President, Law and General Counsel, April 2000 to June 2000. Senior Vice-President, Law and Administration, September 1999 to April 2000.

Russell K. Girling
 
Executive Vice-President, Corporate Development and Chief Financial Officer
 
Executive Vice-President and Chief Financial Officer, June 2000 to March 2003. Senior Vice-President and Chief Financial Officer, August 1999 to June 2000.

Dennis J. McConaghy
 
Executive Vice-President, Gas Development
 
Senior Vice-President, Business Development, October 2000 to May 2001. Senior Vice-President, Midstream/Divestments, June 2000 to October 2000. Prior to June 2000 Vice-President, Corporate Strategy and Planning.

Alexander J. Pourbaix
 
Executive Vice-President, Power
 
Executive Vice-President, Power Development, May 2001 to March 2003. Senior Vice-President, Power Ventures, June 2000 to May 2001. Prior to June 2000, Vice-President, Corporate Development, Power Services.

Sarah E. Raiss
 
Executive Vice-President, Corporate Services
 
Executive Vice-President, Human Resources and Public Sector Relations, June 2000 to January 2002. Senior Vice-President, Human Resources and Public Sector Relations, February 2000 to June 2000.
         

28    TRANSCANADA CORPORATION


Ronald J. Turner
 
Executive Vice-President, Gas Transmission
 
Executive Vice-President, Operations and Engineering, December 2000 to March 2003. Executive Vice-President, International, June 2000 to December 2000. Prior to June 2000, Senior Vice-President, International.

Donald M. Wishart
 
Executive Vice-President, Operations and Engineering
 
Senior Vice-President, Field Operations, June 2000 to March 2003. August 1999 to June 2000, Senior Vice-President, Operations, Transmission Division.

Note:

(1)
Mr. Bellstedt, who served as a trustee of Atlas Cold Storage Income Trust, was subject to an Ontario Securities Commission cease trade order issued in respect of all insiders of Atlas Cold Storage Income Trust on December 2, 2003 and arose because of late filed financial statements required to reflect certain re-statements. The cease trade order was rescinded in January 2004.
Name
   Present Position Held
   Principal Occupation During the Five Preceding Years
Ronald L. Cook   Vice-President, Taxation   Prior to April 2002, Director, Taxation.

Rhondda E.S. Grant
 
Vice-President, Communications and Corporate Secretary
 
Prior to February 2005, Vice-President and Corporate Secretary.

Lee G. Hobbs
 
Vice-President and Controller
 
Prior to August, 2001, Director, Accounting.

Garry E. Lamb
 
Vice-President, Risk Management
 
Vice-President, Audit and Risk Management, June 2000 to October 2001. Vice-President, Risk Management, February 2000 to June 2000.

Donald R. Marchand
 
Vice-President, Finance and Treasurer
 
Vice-President, Finance and Treasurer


CORPORATE GOVERNANCE

 The Board and members of TransCanada's management are committed to the highest standards of corporate governance. TransCanada is subject to a variety of corporate governance guidelines and requirements enacted by the TSX, the Canadian Securities Administrators ("CSA"), the NYSE, and by the U.S. Securities and Exchange Commission ("SEC") under its rules and those mandated by the U.S. Sarbanes-Oxley Act of 2002 ("SOX"). TransCanada's corporate governance practices comply with the TSX Company Manual Corporate Governance Guidelines, governance rules of the NYSE applicable to foreign issuers and applicable requirements of the CSA and SEC. As a non-U.S. company, TransCanada is not required to comply with most of the NYSE corporate governance listing standards applicable to U.S. domestic issuers. TransCanada discloses the significant ways in which its corporate governance practices differ from those followed by domestic companies listed on the NYSE, on its website at www.transcanada.com. TransCanada is in compliance with the CSA's Multilateral Instrument 52-110 pertaining to audit committees, as proposed to be amended. TransCanada is also in substantial compliance with the proposed corporate governance guidelines and proposed disclosure of corporate governance practice rules, both released for comment by the CSA on October 29, 2004. Full disclosure of TransCanada's corporate governance practices are set out in TransCanada's Proxy Circular. TransCanada's corporate governance documents, are available on TransCanada's website located at: http://www.transcanada.com/company/board_committees.html.

TRANSCANADA CORPORATION    29


Audit Committee

 TransCanada has an Audit Committee which is responsible for assisting the Board in overseeing the integrity of TransCanada's financial statements and compliance with legal and regulatory requirements and in ensuring the independence and performance of TransCanada's internal and external auditors. The members of the Audit Committee at Year End are Harry G. Schaefer (Chair), Douglas D. Baldwin, Paule Gauthier, S. Barry Jackson and Paul L. Joskow.

 The Board believes that the composition of the Audit Committee reflects a high level of financial literacy and expertise. Each member of the Audit Committee has been determined by the Board to be "independent" and "financially literate" within the meaning of the definitions under Canadian and U.S. securities laws and the NYSE rules. In addition, the Board has determined that Mr. Schaefer is an "Audit Committee Financial Expert" as that term is defined under U.S. securities laws. The Board has made these determinations based on the education and breadth and depth of experience of each member of the Audit Committee. The following is a description of the education and experience, apart from their respective roles as directors of TransCanada, of each member of the Audit Committee that is relevant to the performance of his or her responsibilities as a member of the Audit Committee:

 Mr. Schaefer earned a Bachelor of Commerce from the University of Alberta, is a Chartered Accountant and is a Fellow of the Canadian Institute of Chartered Accountants. He has served on the boards of several public companies and other organizations, including as Chairman of the Alberta Chapter of the Institute of Corporate Directors, and on the Audit Committees of some of those boards. Mr. Schaefer has also held several executive positions with public companies.

 Mr. Baldwin earned a Bachelor of Science in Chemical Engineering from the University of Saskatchewan. He has served on the boards of several public companies and other organizations and on the Audit Committees of some of those boards. Mr. Baldwin has also held several executive positions with public companies, including the position of President and Chief Executive Officer of both Esso Resources Canada Limited and TCPL.

 Ms. Gauthier earned a Bachelor of Arts from the Collège Jésus-Marie de Sillery, a Bachelor of Laws from Laval University and a Master of Laws in Business Law (Intellectual Property) from Laval-University. She has served on the boards of several public companies and other organizations and on the Audit Committees of some of those boards.

 Mr. Jackson earned a Bachelor of Science in Engineering from the University of Calgary. He has served on the boards of several public companies and on the Audit Committees of some of those boards. Mr. Jackson has also held several executive positions with public companies, including the position of President and Chief Executive Officer of Crestar Energy Inc.

 Mr. Joskow earned a Bachelor of Arts with Distinction in Economics from Cornell University, a Masters of Philosophy in Economics from Yale University, and Ph.D. in Economics from Yale University. He has served on the boards of several public companies and other organizations and on the Audit Committees of some of those.

 The Charter of the Audit Committee can be found in Schedule "B" of this AIF and on TransCanada's website under the Corporate Governance — Board Committees page, at the link specified above under the heading "Corporate Governance".

 TransCanada's Audit Committee has adopted a pre-approval policy with respect to permitted non-audit services. Under the policy, the Audit Committee has granted pre-approval for specified non-audit services of $25,000 or less that are within the annual pre-approved limit for non-audit services. For engagements of $25,000 or less which are not within the annual pre-approved limit, and for engagements between $25,000 and $100,000, approval of the Audit Committee chair is required and the Audit Committee is to be informed of the engagement at the next scheduled Audit Committee meeting. For all engagements of $100,000 or more, pre-approval of the Audit Committee is required. In all cases, regardless of the dollar amount involved, where there is a potential for conflict of interest involving the external auditor on an engagement, the Audit Committee chair must pre-approve the assignment.

30    TRANSCANADA CORPORATION

 To date, TransCanada has not approved any non-audit services on the basis of the de-minimis exemptions. All non-audit services have been pre-approved by the Audit Committee in accordance with the pre-approval policy described above.

 The aggregate fees for external auditor services rendered by KPMG LLP ("External Auditor") for TransCanada in each of 2004 and 2003 fiscal years, are shown in the table below:

Fee Category
   2004
   2003
   Description of Fee Category
 
   (millions of dollars)
   
Audit Fees   2.50   1.80   Aggregate fees for audit services rendered by TransCanada's External Auditor.
Audit Related Fees   0.06   0.05   Aggregate fees for assurance and related services rendered by TransCanada's External Auditor that are reasonably related to performance of the audit or review of TransCanada's financial statements and are not reported as Audit Fees. The nature of services comprising these fees related to the audit of the financial statements of TransCanada's various pension plans.

Tax Fees
 
0.06
 
0.06
 
Aggregate fees rendered by TransCanada's External Auditor for tax compliance and tax advice. The nature of these services consisted of: tax compliance including the review of original and amended tax returns; assistance with questions regarding tax audits; assistance in completing routine tax schedules and calculations; and tax services relating to common forms of domestic and international taxation (i.e.: income tax, capital tax, Goods and Services Tax and Value Added Tax).

All Other Fees
 
0.05
 
0.05
 
Aggregate fees for products and services other than those reported in this table above rendered by TransCanada's External Auditor. The nature of these services consisted of activities with respect to TransCanada's compliance with SOX and particularly, with section 404.

Total
 
2.67
 
1.96
 
 

Other Board Committees

 In addition to the Audit Committee, TransCanada has three other Board committees: the Governance Committee, the Health, Safety and Environment Committee and the Human Resources Committee. The members of each of these committees as of Year End are identified below:

Governance Committee
Chair:   W.K. Dobson
Members:   P.L. Joskow
    D.P. O'Brien
    J.R. Paul
    H.G. Schaefer

Health, Safety & Environment Committee
Chair:   D.D. Baldwin
Members:   P. Gauthier
    K.L. Hawkins
    J.R. Paul
    W.T. Stephens
     

TRANSCANADA CORPORATION    31


Human Resources Committee
Chair:   K.L. Hawkins
Members:   W.K. Dobson
    S.B. Jackson
    D.P. O'Brien
    W.T. Stephens

 The charters of the Governance Committee, the Health, Safety & Environment Committee and the Human Resources Committee were filed with TransCanada's 2003 Annual Information Form dated February 24, 2004 and can be found on TransCanada's website under the Corporate Governance — Board Committees page at the link specified below.

 Further information about TransCanada's Board committees and corporate governance can be found in the Proxy Circular under the heading "Corporate Governance" or on TransCanada's website located at: http://www.transcanada.com/company/board_committees.html.

Conflicts of Interest

 The Board and members of TransCanada's management are not aware of any existing or potential material conflicts of interest between TransCanada or a subsidiary and any director or officer of TransCanada or its subsidiary. Directors and officers of TransCanada and its subsidiaries are required to disclose the existence of existing or potential conflicts in accordance with TransCanada policies governing directors and officers and in accordance with the Canada Business Corporations Act. If a director or officer has such a conflict, TransCanada requires that the director or officer absent themselves from any discussion or voting relating to the matter giving rise to the material existing or potential conflict.


ADDITIONAL INFORMATION

1.
Additional information in relation to TransCanada may be found on SEDAR at www.sedar.com.

2.
Additional information including directors' and officers' remuneration and indebtedness, principal holders of TransCanada's securities and securities authorized for issuance under equity compensation plans (all where applicable), is contained in TransCanada's Proxy Circular for its most recent annual meeting of shareholders that involved the election of directors and can be obtained upon request from the Corporate Secretary of TransCanada.

3.
Additional financial information is provided in TransCanada's Audited Consolidated Financial Statements and MD&A for its most recently completed financial year.

32    TRANSCANADA CORPORATION


GLOSSARY

AIF — Annual Information Form of TransCanada Corporation dated March 7, 2005
Alberta System — A natural gas transmission system throughout the province of Alberta
Annual Report — TransCanada's Annual Report to Shareholders for the year ended, December 31, 2004
APG — Aboriginal Pipeline Group or Mackenzie Valley Aboriginal Pipeline L.P.
Bcf — Billion cubic feet
BC System — A natural gas transmission system in southeastern B.C.
Bécancour Plant — A power plant near Trois-Rivières, Québec
Board — TransCanada's Board of Directors
Bruce Power — Bruce Power L.P.
Canadian Mainline — A natural gas pipeline system running from the Alberta border east to delivery points in eastern Canada and along the U.S. border
CSA — Canadian Securities Administrators
ERA — Electricity Restructuring Act, 2004
EUB — Alberta Energy and Utilities Board
External Auditor — KPMG LLP
FERC — Federal Energy Regulatory Commission (USA)
Foothills — Foothills Pipe Lines Ltd.
Foothills System — A natural gas pipeline system in southeastern B.C., southern Alberta and southwestern Saskatchewan
Gas Pacifico — Gasoducto del Pacifico
GCOC — Generic cost of capital
GRA — General rate application
Grandview Plant — A power plant in Saint John, New Brunswick
Great Lakes System — A natural gas pipeline system in the north central U.S., roughly parallel to the Canada-U.S. Border
GTN System — A natural gas transmission system running from northwestern Idaho, through Washington and Oregon to California
HS&E — Health, Safety and Environment
Iroquois System — A natural gas pipeline system in New York
LNG — Liquefied Natural Gas
Mackenzie Producers — Mackenzie Delta Producers Group
MD&A — TransCanada's Management's Discussion and Analysis dated March 1, 2005
Mmcf/d — Million British thermal units per day
MW — Megawatts
NBP L.P. — Northern Border Partners, L.P.
NEB — National Energy Board (Canada)
NEGT — National Energy & Gas Transmission, Inc.
NGTL — NOVA Gas Transmission Ltd.
North Baja System — A natural gas pipeline system in southeastern California
Northern Border Pipeline — Northern Border Pipeline Company
NYSE — New York Stock Exchange
OPG — Ontario Power Generation Inc.
Portland — Portland Natural Gas Transmission System Partnership
Power LP — TransCanada Power, L.P.
Proxy Circular — TransCanada's Management Proxy Circular dated March 1, 2005
psi — Pounds per square inch
ROE — Return on common equity
SEC — U.S. Securities and Exchange Commission
Shell — Shell US Gas & Power LLC
Simmons Pipeline System — A natural gas pipeline system in northeastern Alberta
SOX — U.S. Sarbanes-Oxley Act of 2002
     

TRANSCANADA CORPORATION    33

Tcf — Trillion cubic feet
TCPL — TransCanada PipeLines Limited
TQM — Trans Québec & Maritimes Pipeline Inc.
TQM System — A natural gas pipeline system in southeastern Québec
TransCanada — TransCanada Corporation
TSX — Toronto Stock Exchange
Tuscarora — Tuscarora Gas Transmission Company
USGen — US Gen New England, Inc.
VCR — Voluntary Challenge and Registry
WCSB — Western Canada Sedimentary Basin
Year End — December 31, 2004

34    TRANSCANADA CORPORATION


SCHEDULE "A"

Exchange Rate of the Canadian Dollar

 All dollar amounts in the AIF are in Canadian dollars, except where otherwise indicated. The following table shows the yearly high and low noon rates, the yearly average noon rates and the year-end noon spot rates for the U.S. dollar for the past five years, each expressed in Canadian dollars, as reported by the Bank of Canada.

 
   Year Ended
  
 
   2004
   2003
   2002
   2001
   2000
  
Yearly High Noon Rate   1.3968   1.5747   1.6132   1.6021   1.5593  
Yearly Low Noon Rate   1.1774   1.2924   1.5110   1.4936   1.4341  
Yearly Average Noon Rate   1.3016   1.4014   1.5703   1.5484   1.4852  
Year-End Noon Rate   1.2036   1.2924   1.5796   1.5926   1.5002 *
*
Year end noon rate for 2000 is as at December 29, 2000.

 On March 7, 2005, the noon rate for the U.S. dollar as reported by the Bank of Canada was US $1.00 = Cdn. $1.2293.

Metric Conversion Table

 The conversion factors set out below are approximate factors. To convert from Metric to Imperial multiply by the factor indicated. To convert from Imperial to Metric divide by the factor indicated.

Metric
   Imperial
   Factor
Kilometres   Miles   0.62
Millimetres   Inches   0.04
Gigajoules   Million British thermal units   0.95
Cubic metres*   Cubic feet   35.3
Kilopascals   Pounds per square inch   0.15
Degrees Celsius   Degrees Fahrenheit   to convert to Fahrenheit multiply by
1.8, then add 32 degrees;
to convert to Celsius subtract
32 degrees, then divide by 1.8
*
The conversion is based on natural gas at a base pressure of 101.325 kilopascals and at a base temperature of 15 degrees Celsius.

TRANSCANADA CORPORATION    35


SCHEDULE "B"

CHARTER OF

THE AUDIT COMMITTEE

PART 1
Establishment of Committee and Procedures

  1.     Committee

  2.     Composition of Committee

  3.     Appointment of Committee Members

  4.     Vacancies

  5.     Committee Chair

  6.     Absence of Committee Chair

36    TRANSCANADA CORPORATION

  7.     Secretary of Committee

  8.     Meetings

  9.     Quorum

10.   Notice of Meetings

11.   Attendance of Company Officers and Employees at Meeting

12.   Procedure, Records and Reporting

13.   Review of Charter and Evaluation of Committee

14.   Outside Experts and Advisors

15.   Reliance

TRANSCANADA CORPORATION    37


PART II

Specific Mandate of Committee

16.   Appointment of the Company's External Auditors

17.   Oversight in Respect of Financial Disclosure

38    TRANSCANADA CORPORATION

18.   Oversight in Respect of Legal and Regulatory Matters

19.   Oversight in Respect of Internal Audit

TRANSCANADA CORPORATION    39

20.   Oversight in Respect of the External Auditors

21.   Oversight in Respect of Audit and Non-Audit Services

40    TRANSCANADA CORPORATION

22.   Oversight in Respect of Certain Policies

23.   Oversight in Respect of Pension Matters


24.   Oversight in Respect of Internal Administration

25.   Oversight Function

TRANSCANADA CORPORATION    41

42    TRANSCANADA CORPORATION

 

 


 

Financial Highlights

Chairman’s Message

Letter to Shareholders

Management’s Discussion and Analysis

2004 Consolidated Financial Statements

Supplementary Information

Investor Information

 

 

 


 

FINANCIAL HIGHLIGHTS

 

Year ended December 31 (millions of dollars)

 

2004

 

2003

 

2002

 

2001

 

2000

 

 

 

 

 

 

 

 

 

 

 

 

 

Income Statement

 

 

 

 

 

 

 

 

 

 

 

Net income/(loss)

 

 

 

 

 

 

 

 

 

 

 

Continuing operations

 

980

 

801

 

747

 

686

 

628

 

Discontinued operations

 

52

 

50

 

—

 

(67

)

61

 

 

 

1,032

 

851

 

747

 

619

 

689

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash Flow Statement

 

 

 

 

 

 

 

 

 

 

 

Funds generated from continuing operations

 

1,674

 

1,810

 

1,827

 

1,624

 

1,495

 

Capital expenditures and acquisitions

 

1,992

 

961

 

827

 

1,077

 

1,135

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance Sheet

 

 

 

 

 

 

 

 

 

 

 

Total assets

 

22,130

 

20,701

 

20,172

 

20,141

 

24,924

 

Long-term debt

 

9,713

 

9,465

 

8,815

 

9,347

 

9,928

 

Common shareholders’ equity

 

6,565

 

6,091

 

5,747

 

5,426

 

5,211

 

 

COMMON SHARE STATISTICS

 

Year ended December 31

 

2004

 

2003

 

2002

 

2001

 

2000

 

Net income/(loss) per share – Basic

 

 

 

 

 

 

 

 

 

 

 

Continuing operations

 

$

2.02

 

$

1.66

 

$

1.56

 

$

1.44

 

$

1.32

 

Discontinued operations

 

0.11

 

0.10

 

—

 

(0.14

)

0.13

 

 

 

$

2.13

 

$

1.76

 

$

1.56

 

$

1.30

 

$

1.45

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income/(loss) per share – Diluted

 

 

 

 

 

 

 

 

 

 

 

Continuing operations

 

$

2.01

 

$

1.66

 

$

1.55

 

$

1.44

 

$

1.32

 

Discontinued operations

 

0.11

 

0.10

 

—

 

(0.14

)

0.13

 

 

 

$

2.12

 

$

1.76

 

$

1.55

 

$

1.30

 

$

1.45

 

 

 

 

 

 

 

 

 

 

 

 

 

Dividends declared per share

 

$

1.16

 

$

1.08

 

$

1.00

 

$

0.90

 

$

0.80

 

Common shares outstanding (millions)

 

 

 

 

 

 

 

 

 

 

 

Average for the year

 

484.1

 

481.5

 

478.3

 

475.8

 

474.6

 

End of year

 

484.9

 

483.2

 

479.5

 

476.6

 

474.9

 

 

 

 

1


 

 

TransCanada continues to take strategic steps to expand its North American gas transmission network, one of the largest and most advanced gas transmission systems in North America.

 

We are actively advancing the Alaska Highway Pipeline Project in Canada and Alaska. Foothills Pipe Lines Ltd., a wholly-owned subsidiary of TransCanada, holds a priority right to build, own and operate the first pipeline through Canada for transport of Alaskan gas. This right was granted to Foothills under Canada’s Northern Pipeline Act (NPA) following a competitive hearing held by the National Energy Board.

 

We have made significant investments in the prebuild portion of this project, which currently extends more than 1,000 kilometres and carries 30 per cent of Canada’s gas exports to United States markets. The NPA is the regulatory framework under which the prebuild portion was constructed, and provides a clear regulatory framework for construction of the balance of the Canadian section of this project. We look forward to the day when the Alaska Highway Pipeline Project comes to fruition.

 

We continue to play a role in the Mackenzie Gas Pipeline Project. In October 2004, the project’s sponsors submitted applications for the main regulatory approvals required for the project to proceed.

 

In liquefied natural gas, we are working to advance a number of projects in Eastern Canada and in the Northeast U.S., where gas sells at a premium. We are currently pursuing the Cacouna Energy Project in Québec and the Broadwater Energy Project in New York. Our focus is on construction and operation of the re-gasification terminals and related pipeline infrastructure to complement and support our existing pipeline investments.

 

In February 2005, we proposed a US$1.7 billion oil pipeline project to transport approximately 400,000 barrels per day of heavy crude oil from Alberta to Illinois.

 

Finally, we have positioned ourselves to become one of the largest providers of natural gas storage capacity in Western Canada. Upon completion of our Edson facility, we will own or control more than 110 Bcf, or approximately one-third, of the storage capacity in Alberta.

 

These initiatives, combined with a strong balance sheet, put TransCanada in a solid position for future growth.

 

2


 

 

TransCanada is pursuing numerous opportunities to deliver long-term growth and value creation in its Power business.

 

The Ontario government has estimated that $25 billion to $40 billion of capital investment will be required to refurbish, rebuild, replace or conserve 25,000 megawatts (MW) of generating capacity by 2020. We are well-positioned to play a role in helping Ontario meet its future energy needs. We have been active in Ontario for almost 50 years in the natural gas transmission business and today, through our investments, are the largest private sector power generator in that province.

 

Bruce Power L.P., 31.6 per cent owned by TransCanada, continues to evaluate the feasibility of restarting Bruce A Units 1 and 2. Together these units would be capable of producing 1,500 MW of cost-effective electric power. TransCanada has also submitted proposals to the Ontario Government under the Government’s current process that seeks up to 2,500 MW of new generation capacity.

 

In Québec, we have commenced construction of the 550 MW Bécancour power plant near Trois-Rivières. The large and highly efficient Bécancour plant is expected to be in-service in late 2006. The entire power output will be supplied to Hydro-Québec Distribution (Hydro-Québec) under a 20 year power purchase contract. The plant will also supply steam to major businesses located nearby.

 

Cartier Wind Energy Inc., which is 62 per cent owned by TransCanada, was recently awarded six projects by Hydro-Québec totalling 739.5 MW. The projects are expected to be commissioned between 2006 and 2012 at an estimated total capital cost of more than $1.1 billion. Long-term electricity supply contracts with Hydro-Québec for each of the six facilities were executed on February 25, 2005.

 

Including facilities that are under construction or in development, TransCanada owns, operates and/or controls approximately 5,700 MW of power generation – enough electricity to meet the needs of about 5.7 million average households.

 

3


 

 

CHAIRMAN’S MESSAGE

 

As I retire from my position as Chairman of TransCanada after seven years, it is with a great sense of pride in the company’s achievements, its first-class Board of Directors and its highly talented management team headed by President and Chief Executive Officer Hal Kvisle. As a result of TransCanada’s strong performance, and in recognition of the importance of the dividend to our shareholders, we were able to raise the dividend in January 2005 for the fifth consecutive year. Over the last five years, the quarterly dividend has increased 53 per cent to $0.305 per share from $0.20 per share.

 

The Board of Directors and management have developed a sound corporate strategy which has been successfully executed by a capable management team, supported by highly skilled employees. Shareholders have seen significant benefits as the company’s share price has increased substantially since early in 2000, when it traded below $10. The share price is now in the $30 range. That equates to a compound annual growth in total shareholder return of 25 per cent over the five-year period.

 

In addition to our disciplined strategic direction, we continue to place a high priority on effective corporate governance. In 2004, TransCanada was recognized for corporate governance by leading Canadian CEOs in the KPMG-Ipsos survey, and for having one of the top ten Boards in Canada by Canadian Business magazine. We were also honoured to receive the Alberta Business Award of Distinction for Ethics in Business.

 

During the past three decades, it has been my privilege to serve on 18 public company boards, and my time spent as Chairman of TransCanada’s Board has been one of the most satisfying experiences. Accordingly, I would like to express my appreciation to my fellow Directors for their support and conscientious commitment to TransCanada and its shareholders. James R. Paul will also be retiring from the Board at the annual meeting in April after serving eight years. Mr. Paul has made a valuable contribution to developing the revised corporate strategy and has served with distinction on the Audit, Governance, and Health, Safety and Environment Committees.

 

In closing, I wish TransCanada and all of its stakeholders – our shareholders, customers, employees, and the communities we serve – continuing great success in the future.

 

 

On behalf of the Board of Directors,

 

 

/s/ R.F Haskayne

 

Richard F. Haskayne Chairman

 

4


 

 

LETTER TO SHAREHOLDERS

 

Financial Performance Net income from continuing operations (net earnings) grew to a record $980 million or $2.02 per share in 2004. Included in this amount are gains related to TransCanada Power, L.P. of $187 million, or $0.39 per share.

 

Funds generated from continuing operations were approximately $1.7 billion. This strong underlying cash flow, combined with proceeds from the sale of assets to TransCanada Power, L.P., allowed us to invest approximately $2.6 billion, including assumed debt, in our core businesses in 2004. Notably, we were able to reach this level of investment without issuing common equity or weakening our financial position. That was a significant accomplishment.

 

During 2004, the Board of Directors increased the annual dividend on TransCanada’s common shares from $1.08 to $1.16 and our share value increased from $27.88 at the end of 2003 to $29.80 at December 31, 2004. Our total shareholder return in 2004 was 11 per cent, resulting in a 25 per cent compound annual return to shareholders over the last five years.

 

In January 2005, TransCanada’s Board of Directors raised the quarterly dividend on the company’s common shares to $0.305 per share which is equivalent, on an annualized basis, to $1.22 per share.

 

Corporate Strategy The results we have achieved in the last five years are the direct result of executing our strategic plan in a disciplined and focused manner. Our goal is to become the leading energy infrastructure company in North America, with a strong focus on natural gas transmission and power generation in regions where we enjoy significant competitive advantages.

 

Achievements in 2004 In the past year, we added a number of quality assets to our portfolio.

 

Gas Transmission Northwest and North Baja In November, we acquired the Gas Transmission Northwest System and the North Baja System for $2.1 billion (US$1.7 billion), including assumed debt. The acquisition is an excellent strategic fit and was immediately accretive to earnings and cash flow.

 

5


 

The 2,174-kilometre Gas Transmission Northwest System is essentially an extension of our existing pipeline infrastructure. It interconnects with our BC and Foothills systems and transports Western Canadian natural gas to growing markets in the Pacific Northwest, California and Nevada. The Gas Transmission Northwest System will also play an important role in delivering Northern gas to end customers when new supply from the Mackenzie Delta and Alaska is connected to the North American market.

 

The North Baja System is a 128-kilometre pipeline that moves natural gas westward from Arizona, through California, to a point on the California/Mexico border. In the future, flows could be reversed and expanded on this line to move natural gas from liquefied natural gas (LNG) terminals on the west coast of Mexico to markets in the United States.

 

USGen New England In December, we announced that we are proceeding with the purchase of hydroelectric generation assets in New England with a total generating capacity in excess of 500 megawatts (MW). These are low-cost, base-load facilities that fit well with our existing operations in the U.S. Northeast. The purchase is expected to close in the first half of 2005 and be immediately accretive to earnings and cash flow.

 

MacKay River and Grandview During 2004, we also completed the construction of two new gas-fired cogeneration plants – the 165 MW MacKay River facility in Alberta and the 90 MW Grandview facility in New Brunswick.

 

Challenges in 2004 While the performance of our existing asset-based businesses and these new initiatives combined to produce another year of solid operating and financial results for TransCanada, we did face some challenges in 2004. Disappointing decisions from the Alberta Energy and Utilities Board (EUB) relating to the Alberta System, and the negative impacts of an arbitration decision with respect to our Ocean State Power facility, resulted in lower than expected results from these assets.

 

TransCanada: Committed to creating value for shareholders

 

2000

 

2001

 

2002

 

2003

 

2004

 

 

 

 

 

 

 

 

 

Calstock power plant in-service*

Acquired the remaining ownership interest in OSP power plant

 

PPA acquired for Sundance A power plant

PPA acquired for Sundance B power plant

Carseland power plant in-service

Redwater power plant in-service


Acquired Curtis Palmer power facilities*

Increased interest in Iroquois Pipeline

 

Acquired ManChief power plant*

Acquired a general partner interest in Northern Border Partners, L.P.

 

Acquired balance of Foothills Pipe Lines Ltd.

Acquired interest in Bruce Power L.P.

Increased ownership in Portland Natural Gas Transmission System

Secured a position in Mackenzie Gas Pipeline Project

Bear Creek power plant in-service

Bruce Power Unit 4 in-service

 

Acquired Gas Transmission
Northwest System and North Baja System

Grandview power plant completed

MacKay River power plant in-service

Bruce Power Unit 3 in-service

 

* These plants were subsequently sold to TransCanada Power, L.P.

 

6


 

In February 2005, we advised the EUB that an agreement in principle for the Alberta System had been reached with negotiating parties on a revenue requirement settlement for the period January 1, 2005 to December 31, 2007. The agreement is subject to formal approval by participating parties and, ultimately, by the EUB. We also reached a settlement with shippers and other interested parties in February 2005 regarding 2005 tolls on our Canadian Mainline gas transmission system.

 

Future Growth Opportunities The TransCanada team remains highly focused on adding to our portfolio of high-quality, large-scale energy infrastructure assets.

 

North American natural gas demand is expected to grow by approximately 20 per cent over the next decade, and a significant portion of that growth will be driven by power demand. However, on the supply side, most experts agree that aggregate natural gas production from North America’s traditional basins will remain flat over the next decade. High gas prices are clear evidence that North America needs new sources of supply. Northern gas and LNG will be required to fill the gap between supply and demand.

 

Recognizing these market dynamics, TransCanada has identified a number of large-scale opportunities to connect new supplies of natural gas and provide new sources of power to growing North American markets. As a result of our focused efforts over the last five years, we are well-positioned to serve growing power demand in our core markets in the near term and to connect new natural gas supply to North American markets in the medium to long term.

 

The TransCanada team has created significant platforms for growth in our two core growth regions. In western North America, we are pursuing large-scale natural gas and power opportunities from Alaska, through western Canada and into the Pacific Northwest and Midwest regions of the United States. Our western initiatives include pipeline extensions to gather new supply and serve new markets, natural gas storage facilities to meet growing storage demand in high-priced markets, northern pipelines to meet long-term demand and, of course, power generation facilities using a diversity of fuels.

 

TARGET DATES for projects that are proposed, in development or under construction**

 

2005

 

2006

 

2008/2009

 

2010

 

2012

 

 

 

 

 

 

 

 

 

USGen New England acquisition

 

Bécancour power plant

expected to begin operations

 

Keystone Pipeline Project expected to begin operations

 

Cacouna Energy LNG facility expected to begin operations

 

Alaska Highway Pipeline expected to be in-service

 

 

Edson Gas Storage expected to begin operations

 

 

 

Broadwater Energy LNG facility expected to begin operations

 

 

 

 

 

 

 

 

 

 

 

 

 

Cartier Wind Energy expected to begin operations
(2006 – 2012)

 

 

 

Mackenzie Gas Pipeline expected to be in-service

 

 

 

** The target dates indicated above are forward-looking and subject to important risks and uncertainties. Results or events predicted may differ from actual results or events due to a number of factors.

 

7


 

In eastern North America, we are pursuing large-scale natural gas and power opportunities in North America’s largest and most intensive energy market. We are a leading natural gas and power developer in our eastern region, stretching from the Great Lakes through Québec to the Canadian Maritimes and including the Northeastern United States. Our eastern activities include pipeline extensions, power generation and LNG terminals.

 

These initiatives have created a solid platform for long-term growth that will continue to enhance shareholder value.

 

In Conclusion I want to take this opportunity to thank all our employees for their continued hard work and commitment to excellence. At TransCanada, we recognize that it takes quality assets, quality people and a top-performing organization to achieve outstanding results. We are committed to making TransCanada a great company in every respect.

 

In closing, I particularly wish to thank Richard F. Haskayne and James R. Paul who will retire from TransCanada’s Board of Directors this April, having reached our mandatory Board retirement age. For the past seven years, Dick Haskayne has made an extraordinary contribution as Chairman of our Board of Directors. He has provided leadership and wise counsel to me and my colleagues, chaired our Board through some difficult decisions, and represented TransCanada to the highest possible standard. Jim Paul has been an active and valuable Board member both prior to and throughout my tenure as CEO. Dick and Jim, we will miss you and we thank you for your many contributions.

 

 

/s/ Hal Kvisle

 

 

 

Hal Kvisle President and Chief Executive Officer

 

 

8


 

 

9


 

CONSOLIDATED FINANCIAL REVIEW

 

The Management’s Discussion and Analysis dated March 1, 2005 should be read in conjunction with the audited consolidated financial statements of TransCanada Corporation (TransCanada or the company) and the notes thereto for the year ended December 31, 2004. Amounts are stated in Canadian dollars unless otherwise indicated.

 

HIGHLIGHTS

 

Net Income In 2004, net income was $1.032 billion or $2.13 per share compared to $851 million or $1.76 per share in 2003.

 

Net Earnings In 2004, TransCanada’s net income from continuing operations (net earnings) increased $179 million to $980 million or $2.02 per share compared to $801 million or $1.66 per share in 2003.

 

Investing Activities In 2004, TransCanada invested more than $2.6 billion (including assumed debt), in the Gas Transmission and Power businesses. Approximately $2.1 billion was invested in the acquisition of the Gas Transmission Northwest System and the North Baja System (collectively GTN).

 

Balance Sheet In 2004, TransCanada’s shareholders’ equity increased by approximately $0.5 billion.

 

Dividend On February 1, 2005, the Board of Directors of TransCanada raised the quarterly dividend on the company’s outstanding common shares 5.2 per cent to $0.305 per share from $0.29 per share for the quarter ending March 31, 2005.

 

Consolidated Results-at-a-Glance

 

Year ended December 31 (millions of dollars except per share amounts)

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

Net Income

 

 

 

 

 

 

 

Continuing operations*

 

980

 

801

 

747

 

Discontinued operations

 

52

 

50

 

—

 

 

 

1,032

 

851

 

747

 

Net Income Per Share – Basic

 

 

 

 

 

 

 

Continuing operations*

 

$

2.02

 

$

1.66

 

$

1.56

 

Discontinued operations

 

0.11

 

0.10

 

—

 

 

 

$

2.13

 

$

1.76

 

$

1.56

 

 

Segment Results-at-a-Glance

 

Year ended December 31 (millions of dollars)

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

Gas Transmission

 

586

 

622

 

653

 

Power

 

396

 

220

 

146

 

Corporate

 

(2

)

(41

)

(52

)

Continuing operations*

 

980

 

801

 

747

 

Discontinued operations

 

52

 

50

 

—

 

Net income

 

1,032

 

851

 

747

 

 

* Net earnings.

 

10


 

Net income for the year ended December 31, 2004 was $1.032 billion or $2.13 per share compared to $851 million or $1.76 per share for 2003. This includes net income from discontinued operations of $52 million or $0.11 per share in 2004 and $50 million or $0.10 per share in 2003, reflecting income recognized on the initially deferred gains relating to the disposition in 2001 of the company’s Gas Marketing business. Net income in 2002 was $747 million or $1.56 per share.

 

TransCanada’s net earnings for the year ended December 31, 2004 were $980 million or $2.02 per share compared to $801 million or $1.66 per share in 2003 and $747 million or $1.56 per share in 2002. The increase of $179 million or $0.36 per share in 2004 compared to 2003 was primarily due to significantly higher net earnings from the Power business. In addition, lower net earnings from the Gas Transmission business were offset by reduced net expenses in the Corporate segment.

 

Net earnings from the Power business increased $176 million in 2004 compared to 2003 primarily due to the realization in 2004 of a gain of $15 million after tax ($25 million pre tax) or $0.03 per share on the sale of the ManChief and Curtis Palmer power plants to TransCanada Power, L.P. (Power LP) and the recognition of $172 million or $0.36 per share of dilution and other gains resulting from a reduction in TransCanada’s ownership interest in Power LP and the removal of Power LP’s obligation, in 2017, to redeem units not owned by TransCanada. TransCanada was previously required to fund this redemption, therefore, the removal of Power LP’s obligation eliminates this requirement.

 

Excluding the above-mentioned $187 million of combined gains included in net earnings related to Power LP and the recognition in 2003 of a $19 million after-tax settlement with a former counterparty, Power’s net earnings in 2004 were $8 million higher than in 2003. Higher equity income from TransCanada’s investment in Bruce Power L.P. (Bruce Power), acquired in February 2003, was partially offset by lower contributions from Eastern Operations and TransCanada’s investment in Power LP.

 

The decrease in net earnings of $36 million in the Gas Transmission business in 2004 compared to 2003 were primarily due to a decline in the Alberta System’s and Canadian Mainline’s net earnings. The Alberta System’s net earnings in 2004 reflect the impacts of the Alberta Energy and Utilities Board (EUB) decisions in 2004 on Phase I of the General Rate Application (GRA) and Generic Cost of Capital (GCOC). The decline in the Canadian Mainline’s net earnings was primarily as a result of a lower rate of return on common equity (ROE) as determined by the generic ROE formula set by the National Energy Board (NEB) and a lower average investment base. These decreases were partially offset by net earnings from GTN, which TransCanada acquired on November 1, 2004, higher earnings from CrossAlta Gas Storage & Services Ltd. (CrossAlta) and TransCanada Pipeline Ventures Limited Partnership (Ventures LP), and a $7 million gain on sale of the company’s equity interest in the Millennium Pipeline project (Millennium). The 2003 results included TransCanada’s $11 million share of a positive future income tax benefit adjustment recognized by TransGas de Occidente S.A. (TransGas).

 

The decrease in net expenses of $39 million in the Corporate segment in 2004 was primarily due to the positive impacts of income tax and foreign exchange related items throughout 2004 and the release in 2004 of previously established restructuring provisions.

 

The increase of $54 million or $0.10 per share in 2003 net earnings compared to 2002 was mainly due to higher net earnings from the Power business and reduced net expenses in the Corporate segment, partially offset by lower net earnings from the Gas Transmission business. Net earnings from the Power business in 2003 included equity income of $73 million after tax from TransCanada’s investment in Bruce Power and a $19 million after-tax settlement with a former counterparty. The reduction in net earnings in the Gas Transmission business in 2003 compared to 2002 reflects a decline in the Canadian Mainline and the Alberta System’s net earnings. The 2002 results included TransCanada’s $7 million share of a favourable ruling for Great Lakes Gas Transmission Limited Partnership related to Minnesota use tax paid in prior years.

 

11


 

Pursuant 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.

 

TRANSCANADA OVERVIEW

 

TransCanada is a leading North American energy company focused on natural gas transmission and power generation and marketing opportunities in regions where it enjoys significant competitive advantages. Natural gas transmission and power are complementary businesses for TransCanada. They are driven by similar supply and demand fundamentals, they are both capital intensive businesses, and use similar technology and operating practices. They are businesses with significant long-term growth prospects.

 

North American natural gas demand is growing and that demand is mainly driven by the demand for electricity.  Experts predict that demand for electricity will increase at an average annual rate of approximately two per cent over the next ten years primarily due to a growing population and an increase in gross domestic product.  A large part of that demand growth is expected to be met through higher utilization of new gas-fired generating plants that were built as part of the massive capacity additions that occurred in many North American markets over the last five years.

 

Coal-fired plants are still the largest source of electric power in North America and coal reserves are significant. Nuclear facilities have also played a significant role in supplying North America with power in the past and new nuclear capacity will likely come on stream over time.

 

However, the long lead times required to complete new coal and nuclear projects, the associated environmental and public relations issues, the high capital costs and the difficulty in locating these plants near load centres may impede the development and completion of new coal or nuclear generation over the next five to ten years. As a result, North America is expected to continue to rely on natural gas-fired generation to satisfy its growing electricity needs in the near term. This is expected to lead to a significant increase in natural gas consumption. Overall, North American natural gas demand is expected to grow to 85 billion cubic feet per day (Bcf/d) by 2015, an increase of 15 Bcf/d when compared to 2004. New natural gas-fired power generation is expected to account for approximately 10 Bcf/d of that growth.

 

While growing demand will provide a number of opportunities, the natural gas industry also faces a number of challenges. North America has entered a period when it will no longer be able to rely solely on traditional sources of natural gas supply to meet its growing needs. Current high natural gas prices are clear evidence that North America is in a period of transition and significant change. Natural gas supply is tight and this is likely to continue until major investments are made in the infrastructure required to bring new supply to market. Looking forward, production from North America’s traditional basins is expected to remain flat over the next decade. An increase in production in the United States Rockies will likely only offset declines in other basins, including the Gulf of Mexico. This outlook for traditional basins means that northern gas and offshore liquefied natural gas (LNG) will be required to fill the shortfall between supply and demand.

 

TransCanada is well positioned in North America to serve growing power generation demand in the near term and to bring new natural gas supply to market in the medium to longer term.

 

12


 

TRANSCANADA’S STRATEGY

 

TransCanada’s strong position in North America is the direct result of successfully executing its corporate strategy which was first adopted five years ago. While the plan has evolved over time in response to actual and anticipated changes in the business environment, it fundamentally remains the same. Today, TransCanada’s corporate strategy consists of the following five components:

 

• Grow the North American Gas Transmission business.

 

• Maximize the long-term value of the Canadian wholly-owned Gas Transmission business.

 

• Grow the North American Power business.

 

• Drive for operational excellence.

 

• Maximize the corporate strength and value of TransCanada.

 

GAS TRANSMISSION

 

TransCanada’s natural gas transmission assets link the Western Canada Sedimentary Basin (WCSB) with premium North American markets. With more than 41,000 kilometres (km) of pipeline, the company’s network of wholly-owned pipeline assets is one of the largest in North America.

 

In 2004, the wholly-owned Alberta System gathered 64 per cent of the natural gas produced in Western Canada or 16 per cent of total North American production. TransCanada exports gas from the WCSB to Eastern Canada and the U.S. West, Midwest and Northeast through four wholly-owned systems – the Canadian Mainline, the Gas Transmission Northwest System, the Foothills System and the BC System – and six partially-owned systems – Trans Québec & Maritimes System (TQM), Great Lakes Gas Transmission System (Great Lakes), Iroquois Gas Transmission System (Iroquois), Portland Natural Gas Transmission System (Portland), Northern Border Pipeline (Northern Border) and Tuscarora Gas Transmission System (Tuscarora).  The company’s strategy in Gas Transmission is focused on both growing its North American natural gas transmission network and maximizing the long-term value of its Canadian wholly-owned pipelines. In order to grow the Gas Transmission business, TransCanada is focusing its efforts on expanding and extending its existing systems to connect new supply to growing markets, increasing its ownership in partially-owned entities, acquiring other pipelines that provide it with a significant regional presence and in the long term, connecting new sources of supply in the form of northern gas and LNG.

 

The company’s ability to successfully execute its strategy has been and continues to be directly related to the core competencies that have been developed in Gas Transmission.

 

Over the past 50 years, TransCanada has developed significant expertise in large-diameter, cold-weather natural gas pipeline design, construction, operation and maintenance. It has also developed significant expertise in the design, optimization and operation of large gas turbine compressor stations. Today, TransCanada operates one of the largest, most sophisticated, remote-controlled pipeline networks in the world with a solid reputation for safety and reliability. TransCanada also has strong project development and management skills and is committed as an organization to the highest levels of operational excellence. The company’s strong financial position allows it to build large-scale infrastructure and act quickly on quality opportunities as they arise.

 

Significant milestones were achieved in the Gas Transmission business in 2004. The acquisition of GTN is a prime example. The Gas Transmission Northwest System consists of 2,174 km of pipeline extending from Kingsgate, British Columbia on the B.C./Idaho border to Malin, Oregon on the Oregon/California border. It interconnects with the BC System and Foothills System and transports WCSB natural gas to growing markets in the Pacific Northwest, California and Nevada. The North Baja System is a 128 km system that extends from Ehrenberg, Arizona to a point near Ogilby, California on the California/Mexico border. In the future, this line could be modified at relatively low cost to allow natural gas to flow from LNG terminals in Baja, Mexico to markets in the U.S.

 

Looking north, TransCanada has secured a position in the Mackenzie Gas Pipeline Project and, in Alaska, it has assembled significant legal, technical and environmental information. Foothills Pipe Lines Ltd. (Foothills) was granted certificates for the Canadian

 

13


 

portion of the Alaska Highway Pipeline Project over 25 years ago.  Certificates of Public Convenience and Necessity were granted to Foothills under the Northern Pipeline Act of Canada (NPA). Foothills holds the priority right to build, own and operate the first pipeline through Canada for the transportation of Alaskan gas. This right was granted under the NPA, following a lengthy competitive hearing before the NEB in the late 1970’s, which resulted in a decision in favour of Foothills. The NPA creates a single window regulatory regime that is uniquely available to Foothills. It has been used by Foothills to construct the facilities in Alberta which constitute a prebuild for the Alaska Highway Pipeline Project, and to expand those facilities five times, the latest of which was in 1998. Continued development under the NPA should ensure the earliest in-service date for the project.

 

During 2004, to continue to move the Alaska Highway Pipeline Project forward, the company filed an application under the State of Alaska’s Stranded Gas Development Act, which is the State’s vehicle for dealing with fiscal concessions and other matters related to this project.  TransCanada’s application is one of three applications currently before the State. As well, TransCanada requested the State to resume processing its long-pending application for a right-of-way lease on State lands. TransCanada holds the complementary rights-of-way on federal lands in Alaska. In addition, the company continued discussions with a number of parties, including Alaska North Slope producers, the State of Alaska, the government of Canada and key players in the North American natural gas market.

 

If the Mackenzie Gas Pipeline Project and the Alaska Highway Pipeline Project are constructed and connected to TransCanada’s existing infrastructure, they would represent additional growth opportunities for TransCanada and enhance the long-term viability of the company’s existing Gas Transmission business, especially the Canadian wholly-owned pipelines.

 

In 2004, TransCanada also took steps to advance a number of LNG projects. TransCanada is of the view that LNG will play a significant role in meeting growing North American gas demand. Based on North American natural gas prices, the company believes that Eastern Canada and the Northeast U.S., where natural gas sells at a premium, are logical locations to import LNG. TransCanada is currently assessing a number of long-term opportunities in these regions including the Cacouna Energy Project in Québec and the Broadwater Energy Project in New York. In general, LNG projects may experience siting challenges.

 

TransCanada’s focus on these projects is on the regasification terminal and related pipeline infrastructure that complements and supports the company’s existing pipeline investments.

 

The company’s initiatives in the natural gas storage business are a logical extension of its Gas Transmission business. TransCanada believes Alberta-based natural gas storage will continue to serve market needs and could play an important role should northern gas be connected to North American markets. In January 2005, TransCanada announced plans to develop a natural gas storage facility near Edson, Alberta. The Edson facility will have a capacity of approximately 50 Bcf and connect to TransCanada’s Alberta System. In addition, in 2004, the company secured a long-term contract with a third party for existing Alberta-based natural gas storage capacity, ramping up from approximately 20 Bcf in 2005 to 30 Bcf in 2006 and to 40 Bcf in 2007. These initiatives, combined with the company’s current 60 per cent ownership interest in CrossAlta, position TransCanada to become one of the largest natural gas storage providers in Western Canada with 110 Bcf of storage capacity by 2007 which will represent approximately one-third of the natural gas storage capacity available in Alberta.

 

In addition to growing the North American Gas Transmission business, the company continues to place a strategic priority on maximizing the long-term value of its Canadian wholly-owned pipelines. Efforts in this area are focused on achieving a fair return on invested capital and streamlining and harmonizing processes and tariff provisions for and among TransCanada’s regulated pipelines. Further, the company continues to respond to changes in the market by introducing new services to meet customer needs.

 

In 2004, TransCanada received a number of regulatory decisions from the NEB and the EUB with mixed results. TransCanada was generally pleased with the NEB’s decision on the 2004 Canadian Mainline Tolls and Tariff Application (2004 Application) Phase I and its decision to approve North Bay Junction (NBJ) as a new receipt

 

14


 

and delivery point, which TransCanada views as forward steps in ensuring the long-term sustainability of the Canadian Mainline to the benefit of all stakeholders. However, two decisions from the EUB in 2004 related to the Alberta System were disappointing.

 

In July 2004, the EUB released its decision in the GCOC proceeding. All Alberta provincially regulated utilities, including the Alberta System, were mandated an ROE of 9.60 per cent for 2004. This generic ROE will be adjusted annually by 75 per cent of the change in long-term Government of Canada bonds from the previous year, consistent with the approach used by the NEB. The EUB also established a deemed common equity of 35 per cent for the Alberta System. This result was significantly less than the applied for ROE of 11 per cent on deemed common equity of 40 per cent, which the company considered to be a fair return.

 

In September 2003, TransCanada filed Phase I of the 2004 GRA with the EUB, consisting of evidence in support of the applied-for rate base and revenue requirement. In its August 24, 2004 decision, the EUB approved the purchase of the Simmons Pipeline System (Simmons) for approximately $22 million and the costs of firm transportation (FT) service arrangements with the Foothills, Simmons and Ventures LP systems. However, a significant amount of costs were disallowed for recovery, which reduced revenue requirement and rate base.

 

In September 2004, TransCanada filed with the Alberta Court of Appeal for leave to appeal the EUB’s decision on Phase I of the 2004 GRA with respect to the disallowance of applied-for incentive compensation costs. In its decision, the EUB disallowed approximately $24 million (pre tax) of operating costs, which included $19 million of applied-for incentive compensation costs.  TransCanada believes the EUB made errors of law in deciding to deny the inclusion of these compensation-related costs in the revenue requirement. The company believes these are necessary costs that it reasonably and prudently incurs for the safe, reliable and efficient operation of the Alberta System. At the request of TransCanada, the Alberta Court of Appeal adjourned the appeal for an indefinite period of time while TransCanada considers the merits of a review and variance application to the EUB in respect of 2004 costs.  On February 24, 2005, TransCanada advised the EUB that an agreement in principle had been reached with negotiating parties on a revenue requirement settlement for the period January 1, 2005 to December 31, 2007.  The agreement is subject to formal approval by participating parties, and ultimately by the EUB.

 

In 2004, TransCanada applied for an allowed return for the Canadian Mainline based on the NEB’s ROE formula on a 40 per cent deemed common equity. An NEB decision is expected in second quarter 2005.

 

On February 14, 2005, TransCanada announced it had reached a settlement with its Canadian Mainline shippers regarding 2005 tolls. This settlement establishes operating, maintenance and administration (OM&A) costs for 2005 at $169.5 million, which is comparable to the 2004 level. Any variance between actual OM&A costs in 2005 and those agreed to in the settlement will accrue to TransCanada. All other cost elements of the 2005 revenue requirement will be treated on a flow through basis. Further, the 2005 ROE for the Canadian Mainline will be 9.46 per cent as determined under the NEB formula, and the common equity component of the Canadian Mainline’s capital structure for 2005 shall be based on the NEB’s decision in the recently concluded hearing on the Canadian Mainline’s cost of capital for 2004, subject to the outcome of any review applications or appeals.

 

In February 2005, TransCanada announced that it is proposing a US$1.7 billion oil pipeline project to transport approximately 400,000 barrels per day of heavy crude oil from Alberta to Illinois. The proposed Keystone Pipeline (Keystone) would be approximately 3,000 km in length. In addition to new pipeline construction, Keystone would require the conversion of approximately 1,240 km of one of the lines in TransCanada’s existing multi-line natural gas pipeline systems in Alberta, Saskatchewan and Manitoba.

 

TransCanada will continue to meet with oil producers, refiners and industry groups, including the Canadian Association of Petroleum Producers, to gauge additional interest and support for Keystone. Preliminary discussions have begun with stakeholders, including communities, government representatives and landowners along the proposed route. TransCanada will proceed with the necessary regulatory applications when sufficient support for this project from oil producers and shippers is obtained.

 

15


 

TransCanada will require various regulatory approvals from Canadian and U.S. agencies before construction can begin. Input from all stakeholders will be received through the regulatory process and an extensive public consultation process.

 

TransCanada is in the business of connecting energy supplies to markets and it views this opportunity as another way of providing a valuable service to its customers. Converting one of the company’s natural gas pipeline assets for oil transportation is an innovative, cost-competitive way to meet the need for pipeline expansions to accommodate anticipated growth in Canadian crude oil production during the next decade.

 

POWER

 

TransCanada has built a substantial power business over the last ten years. Currently, the power plants and power supply that TransCanada owns, operates and/or controls, including those under construction or in development, in the aggregate, represent approximately 5,700 megawatts (MW) of power generation capacity in Canada and the U.S. The company’s physical assets are concentrated in two main regions – one in the west, the other in the east. The western business is focused in Alberta where TransCanada is one of the largest providers of wholesale power in the province. Assets include five gas-fired cogeneration plants and power purchase arrangements (PPAs) at the Sundance A and B coal-fired plants. In the east, the focus has been on the Ontario, Québec, New England and New York markets. The company started with a minority interest in Ocean State Power (OSP), a 560 MW gas-fired plant in Rhode Island. In Ontario, TransCanada began by developing three natural gas-fired plants adjacent to compressor stations along the Canadian Mainline. Today, through its investments, TransCanada is the largest private sector generator in Ontario.

 

TransCanada’s strategy for growth and value creation in Power has been driven by four main principles.

 

First, the company has focused its efforts on acquiring low-cost, base-load generation in markets it knows. PPA entitlements at the Sundance A and B coal-fired plants in Alberta, its investment in Bruce Power and the pending acquisition of USGen New England (USGen) are prime examples of this approach. The company believes that being a low-cost provider and/or having long-term power sales contracts is critical to being successful in the power business.

 

Second, TransCanada has focused on developing low-risk, greenfield, gas-fired cogeneration projects. Although higher on the cost curve than hydro, nuclear or coal, they are much more efficient than various other forms of generation including combined-cycle gas-fired plants. To reduce the risk associated with these higher cost sources of production, TransCanada has focused on selling a significant portion of the output from these plants to strong counterparties under long-term contracts where the buyer also assumes the risk associated with fluctuations in the natural gas price. The Grandview and Bécancour projects are examples of this approach.

 

Third, TransCanada actively participates in markets that are in transition. The changes that took place in New England and Alberta, and the changes that continue in Ontario, allow the company to capture opportunities that are created as a result of markets in transition.

 

Lastly, TransCanada has focused its attention on optimizing its existing asset portfolio by running the company’s facilities as efficiently and cost-effectively as possible through its drive for operational excellence.

 

TransCanada’s ability to successfully execute its strategy is directly related to the core competencies that it has developed in the power business. Over the years, the company has gained a broad understanding of North American energy markets and a deep understanding of its core markets in Alberta, Ontario, Québec, and the Northeastern U.S. It has been an active participant in deregulated markets. The experience gained in its core markets serves the company well as it pursues opportunities in those and other areas. TransCanada uses its ability to structure deals and manage risk which is critical to mitigating volatility and uncertainty for its industrial customers and its shareholders. TransCanada’s financial position allows it to build large-scale infrastructure and gives it the ability to act quickly on quality opportunities as they arise. The company has strong project development skills and is committed as an organization to operational excellence.

 

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In 2004, TransCanada continued to add to its diverse portfolio of quality power generation assets.

 

In addition to the completion of the restart of Unit 3 at Bruce Power and the commissioning of the MacKay River cogeneration plant in 2004, the company also completed construction of the Grandview facility, a 90 MW natural gas-fired cogeneration power plant located in Saint John, New Brunswick. All of the power and heat output from the Grandview plant will be sold to Irving Oil Limited under a 20 year PPA. The company also continued to make progress on the new 550 MW Bécancour natural gas-fired cogeneration plant, which is located near Trois-Rivières, Québec. All of the power output from that plant will be sold under a 20 year PPA to Hydro-Québec Distribution (Hydro-Québec). Final approvals for this project were received in July 2004 and construction has commenced. It is scheduled to be in-service in late 2006.

 

In October 2004, TransCanada announced that Cartier Wind Energy (Cartier Wind), owned 62 per cent by TransCanada, was awarded six projects by Hydro-Québec representing a total of 739.5 MW. Long-term electricity supply contracts were signed with Hydro-Québec on February 25, 2005 for each of the facilities. The six projects are expected to be commissioned between 2006 and 2012 at an estimated total capital cost of more than $1.1 billion.

 

In December 2004, TransCanada announced it would proceed with the purchase of hydroelectric generation assets with a total generating capacity of 567 MW from USGen for US$505 million. The assets include generating assets on two river systems in New England. The purchase is subject to the sale of the 49 MW Bellows Falls hydroelectric facility to the Vermont Hydroelectric Power Authority (Vermont Hydroelectric), which has exercised its pre-existing option to purchase this plant. This would result in a US$72 million reduction in the purchase price to US$433 million for 518 MW.

 

TransCanada is well positioned to play a role in helping Ontario meet its future energy needs. The Ontario government has estimated that $25 billion to $40 billion of capital investment will be required to refurbish, rebuild, replace or conserve 25,000 MW of generating capacity by 2020. Bruce Power, 31.6 per cent owned by TransCanada, continues to evaluate the feasibility of restarting Units 1 and 2 and talks between Bruce Power and a provincially appointed negotiator regarding the potential restart of the two 750 MW units are ongoing. TransCanada also submitted proposals to the Ontario government under its recent request-for-proposal process that seeks up to 2,500 MW of new electricity generation capacity and/or conservation measures. This power is expected to come on-line between 2005 and 2009.

 

TransCanada, together with its Bruce Power partners, is also evaluating a potential investment in the refurbishment of the 680 MW Point Lepreau nuclear generating station in New Brunswick. Discussions are currently ongoing with New Brunswick Power.

 

TransCanada expects its Power business to continue to be a key growth driver in the years ahead. The company is committed to growing the Power business through asset acquisitions, selected greenfield developments and further expansions of its existing business and footprint. The goal is to build and establish a diverse portfolio of high quality assets that deliver strong returns to TransCanada’s shareholders.

 

OPERATIONAL EXCELLENCE AND “SPIRIT”

 

In addition to growing its Gas Transmission and Power businesses, TransCanada is committed to an operational excellence business model. Its focus is on being a cost-conscious, reliable and safe operator, providing desired services to its customers in an effective and timely manner. The company’s values guide the way business is conducted at TransCanada. Within TransCanada, these values are commonly referred to as “SPIRIT”. They are the principles that direct how the company works and they include – Social responsibility, Passion, Integrity, Results, Innovation and Teamwork. The company’s commitment to these values helps ensure it maintains its reputation as one of North America’s premier energy companies.

 

TransCanada has approximately 2,450 employees who through their talent, hard work and results provide the company a strong competitive advantage because of their industry-leading expertise in pipeline and power operations, project management, depth of market and industry knowledge, and financial acumen.

 

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OUTLOOK

 

In 2005, TransCanada will continue to execute its corporate strategy in a disciplined and focused manner by directing its energies towards long-term growth opportunities that will strengthen its financial performance and create long-term value for shareholders. The company’s net earnings and cash flow combined with a strong balance sheet continue to provide the financial flexibility for TransCanada to make disciplined investments in its core businesses of Gas Transmission and Power.

 

In Gas Transmission, the company will continue to focus its efforts on expanding and extending its existing systems to connect new supply to growing markets, increasing its ownership in partially-owned entities, acquiring other pipelines that provide it with a significant regional presence and connecting new sources of supply in the form of northern gas and LNG. The company will also focus on maximizing the long-term value of its Canadian wholly-owned natural gas pipelines.

 

In 2005, there will be a full year’s contribution from GTN, which was acquired on November 1, 2004. The company expects lower allowed ROEs and lower average investment bases for both the Canadian Mainline and the Alberta System. The outcome of customer settlement negotiations and regulatory proceedings could have a significant positive or negative impact on earnings from the Gas Transmission segment in 2005.

 

In the Power business, the company will continue to focus on acquiring low-cost, base-load generation, developing low-risk greenfield cogeneration projects, capitalizing on opportunities in markets that are in transition and optimizing its existing asset portfolio.

 

The potential variability in Bruce Power’s earnings caused by changes in prices realized, operating expenses, and plant availability, and the outcome of a fourth arbitration related to the cost of fuel gas for OSP expected by the end of third quarter 2005 could impact earnings in 2005.

 

A $1.00 per megawatt hour (MWh) change in the spot price for electricity in Ontario would change TransCanada’s after-tax equity income from Bruce Power by approximately $5 million. Bruce Power operating expenses are expected to increase in 2005 due to higher outage costs, higher depreciation on the Bruce A units and recent capital programs and higher fuel costs. The average availability in 2005 for Bruce Power is expected to be 85 per cent compared to 82 per cent in 2004.

 

In 2004, as a result of a third arbitration process, OSP’s cost of fuel gas was substantially increased to a price in excess of market. Should a fourth arbitration decision at OSP, expected in 2005, continue to support a pricing mechanism for fuel gas in excess of market price and if anticipated market conditions do not change substantially, management expects there could be an asset impairment write-down of this facility. The net carrying value of OSP at December 31, 2004 was approximately US$150 million.

 

The sale of the Curtis Palmer and ManChief plants in April 2004 results in the loss of earnings from these plants for a full year in 2005. The Grandview cogeneration plant and the proposed acquisition of the USGen assets are expected to have a positive impact on 2005 earnings from the Power segment. In addition, plant availability, fluctuating market prices, weather and regulatory decisions could impact earnings.

 

In 2004, income tax and foreign exchange related items and the release of a previously established restructuring provision had a significantly positive impact on the results of the Corporate segment. In 2005, the Corporate segment is expected to incur a more normalized level of net expenses with higher net expenses than in 2004.

 

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GAS TRANSMISSION

 

HIGHLIGHTS

 

Net Earnings Net earnings from Gas Transmission decreased $36 million to $586 million in 2004 compared to $622 million in 2003.

 

This decrease is primarily due to a $40 million decrease from the Alberta System and an $18 million decrease from the Canadian Mainline offset by a $14 million increase due to the acquisition of GTN.

 

Canadian Mainline The NEB, in its decision on Phase 1 of the 2004 Application, approved virtually all applied-for costs, as well as a new non-renewable firm transportation (FT-NR) service.

 

In December, the NEB approved TransCanada’s application to establish the North Bay Junction as a new receipt and delivery point on the Canadian Mainline.

 

Alberta System In July 2004, TransCanada received a decision from the EUB on the GCOC proceeding which established an ROE of 9.60 per cent for all Alberta utilities for 2004 and an equity thickness for the Alberta System of 35 per cent.

 

The EUB disallowed approximately $24 million pre tax of operating costs associated with the operation of the Alberta System in its decision on Phase I of the 2004 GRA which dealt with revenue requirement and rate base.

 

Simmons became part of the Alberta System on October 1, 2004.

 

GTN On November 1, 2004, TransCanada acquired GTN which is a high-quality, reliable operation that exemplifies the company’s growth strategy.

 

GTN contributed $14 million of earnings for the two months ended December 31, 2004.

 

Other Gas Transmission In 2004, TransCanada announced plans to develop two new LNG facilities, one in Cacouna, Québec, and one offshore in the New York State waters of Long Island Sound.

 

In June 2004, TransCanada filed an application under the Alaska Stranded Gas Development Act and proceeded to process its application with the State of Alaska for a right-of-way across State lands for the Alaska Highway Pipeline Project.

 

TransCanada continued to fund the Aboriginal Pipeline Group’s (APG) participation in the Mackenzie Gas Pipeline Project.

 

TransCanada entered into arrangements that will increase TransCanada’s natural gas storage capacity in Alberta commencing in 2005. In January 2005, it announced plans to develop a $200 million natural gas storage project near Edson, Alberta.

 

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Canadian Mainline TransCanada’s 100 per cent owned 14,898 km natural gas transmission system in Canada extends from the Alberta/Saskatchewan border east to the Québec/Vermont border and connects with other natural gas pipelines in Canada and the U.S.

 

Alberta System TransCanada’s 100 per cent owned natural gas transmission system in Alberta gathers natural gas for use within the province and delivers it to provincial boundary points for connection with the Canadian Mainline, BC System, the Foothills System and other pipelines. The 23,186 km system is one of the largest carriers of natural gas in North America.

 

Gas Transmission Northwest System TransCanada’s 100 per cent owned natural gas transmission system extends 2,174 km and links the BC System and the Foothills System with Pacific Gas and Electric Company’s California Gas Transmission System and with Tuscarora, a partially-owned entity that runs from the Oregon/California border into Nevada.

 

Foothills System TransCanada’s 100 per cent owned 1,040 km natural gas transmission system in Western Canada carries natural gas for export from central Alberta to the U.S. border to serve markets in the U.S. Midwest, Pacific Northwest, California and Nevada.

 

BC System TransCanada’s 100 per cent owned natural gas transmission system extends 201 km from Alberta’s western border through B.C. to connect with the Gas Transmission Northwest System at the U.S. border, serving markets in B.C. as well as the Pacific Northwest, California and Nevada.

 

North Baja System The North Baja System is a 100 per cent owned, 128 km natural gas transmission system that extends from southwestern Arizona to a point near Ogilby, California on the California/Mexico border and connects with a pipeline system in Mexico.

 

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Ventures LP Ventures LP, which is 100 per cent owned by TransCanada, owns a 121 km pipeline and related facilities which supply natural gas to the oil sands region of northern Alberta, and a 27 km pipeline which supplies natural gas to a petrochemical complex at Joffre, Alberta.

 

Great Lakes Great Lakes connects with the Canadian Mainline at Emerson, Manitoba and serves markets in central Canada and the eastern and midwestern U.S. TransCanada has a 50 per cent ownership interest in this 3,387 km pipeline system.

 

TQM TQM is a 572 km natural gas pipeline system which connects with the Canadian Mainline and transports natural gas from Montréal to Québec City and to the Portland system. TransCanada holds a 50 per cent ownership interest in TQM.

 

Iroquois Iroquois connects with the Canadian Mainline near Waddington, New York and delivers natural gas to customers in the Northeastern U.S. TransCanada has a 41 per cent ownership interest in this 663 km pipeline system.

 

Portland Portland is a 471 km pipeline that connects with TQM near East Hereford, Québec and delivers natural gas to customers in the Northeastern U.S. TransCanada has a 61.7 per cent ownership interest in Portland.

 

Northern Border Northern Border is a 2,010 km natural gas pipeline system which serves the U.S. Midwest from a connection with the Foothills System. TransCanada indirectly owns approximately 10 per cent of Northern Border through its 33.4 per cent ownership interest in TC PipeLines, LP.

 

Tuscarora Tuscarora operates a 386 km pipeline system transporting natural gas from the Gas Transmission Northwest System at Malin, Oregon to Wadsworth, Nevada with delivery points in northeastern California and northwestern Nevada. TransCanada owns an aggregate 17.4 per cent interest in Tuscarora, of which 16.4 per cent is held through TransCanada’s interest in TC PipeLines, LP.

 

CrossAlta CrossAlta is an underground natural gas storage facility connected to the Alberta System and is located near Crossfield, Alberta. CrossAlta has a working natural gas capacity of 40 Bcf with a maximum deliverability capability of 410 million cubic feet per day (MMcf/d). TransCanada holds a 60 per cent ownership interest in CrossAlta.

 

Edson TransCanada is currently developing the Edson natural gas storage facility near Edson, Alberta. The Edson facility will have a capacity of approximately 50 Bcf and will connect to TransCanada’s Alberta System. The facility is expected to be in-service in second quarter 2006.

 

TransGas TransGas is a 344 km natural gas pipeline system which runs from Mariquita in the central region of Colombia to Cali in the southwest of Colombia. TransCanada holds a 46.5 per cent ownership interest in this pipeline.

 

Gas Pacifico Gas Pacifico is a 540 km natural gas pipeline extending from Loma de la Lata, Argentina to Concepción, Chile. TransCanada holds a 30 per cent ownership interest in Gas Pacifico.

 

INNERGY INNERGY is an industrial natural gas marketing company based in Concepción, Chile that markets natural gas transported on Gas Pacifico. TransCanada holds a 30 per cent ownership interest in INNERGY.

 

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Gas Transmission Net Earnings-at-a-Glance

 

Year ended December 31 (millions of dollars)

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

Wholly-Owned Pipelines

 

 

 

 

 

 

 

Canadian Mainline

 

272

 

290

 

307

 

Alberta System

 

150

 

190

 

214

 

GTN (1)

 

14

 

 

 

 

 

Foothills System (2)

 

22

 

20

 

17

 

BC System

 

7

 

6

 

6

 

 

 

465

 

506

 

544

 

Other Gas Transmission

 

 

 

 

 

 

 

Great Lakes

 

55

 

52

 

66

 

Iroquois

 

17

 

18

 

18

 

TC PipeLines, LP

 

16

 

15

 

17

 

Portland (3)

 

10

 

11

 

2

 

Ventures LP

 

15

 

10

 

7

 

TQM

 

8

 

8

 

8

 

CrossAlta

 

13

 

6

 

13

 

TransGas

 

11

 

22

 

6

 

Northern Development

 

(6

)

(4

)

(6

)

General, administrative, support costs and other

 

(18

)

(22

)

(22

)

 

 

121

 

116

 

109

 

Net earnings

 

586

 

622

 

653

 

 

(1)   TransCanada acquired GTN on November 1, 2004. Amounts in this table reflect TransCanada’s 100 per cent ownership interest in GTN’s net earnings from the acquisition date.

(2)   The remaining ownership interests in the Foothills System, previously not held by TransCanada, were acquired on August 15, 2003. Amounts in this table reflect TransCanada’s proportionate interest in Foothills’ net earnings prior to acquisition and 100 per cent interest thereafter.

(3)   TransCanada increased its ownership interest in Portland to 43.4 per cent from 33.3 per cent in September 2003 and to 61.7 per cent from 43.4 per cent in December 2003. Amounts in this table reflect TransCanada’s proportionate net earnings from Portland.

 

In 2004, net earnings from the Gas Transmission business were $586 million compared to $622 million and $653 million in 2003 and 2002, respectively. The decrease in 2004 compared to 2003 was mainly due to lower net earnings from Wholly-Owned Pipelines, partially offset by higher net earnings from Other Gas Transmission. The 2004 decrease in Wholly-Owned Pipelines’ net earnings was primarily due to a reduction in the Alberta System’s net earnings of $40 million, reflecting the EUB’s disallowance of certain operating costs in its decision on Phase I of the 2004 GRA and in its decision in the GCOC proceeding to allow an ROE in 2004 lower than the return implicit in the 2003 revenue requirement settlement with stakeholders.

 

In addition, net earnings on the Canadian Mainline were lower by $18 million in 2004 compared to 2003 due to a decline in both the average investment base and the allowed ROE. The addition of GTN had a positive effect on 2004 net earnings. Higher 2004 net earnings from Other Gas Transmission were primarily due to increased earnings from CrossAlta and Ventures LP and a $7 million gain on sale of Millennium, partially offset by the negative impact of a weaker U.S. dollar.

 

The overall decrease of $31 million in 2003 Gas Transmission net earnings compared to 2002 was mainly due to higher incremental earnings in 2002 due to the NEB’s Fair Return decision in 2002 and lower investment bases in 2003.

 

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GAS TRANSMISSION – EARNINGS ANALYSIS

 

Canadian Mainline The Canadian Mainline is regulated by the NEB. The NEB sets tolls which provide TransCanada the opportunity to recover projected costs of transporting natural gas and provide a return on the Canadian Mainline’s average investment base. New facilities are approved by the NEB before construction begins. Changes in investment base, the ROE, the level of deemed common equity and the potential for incentive earnings affect the net earnings of the Canadian Mainline.

 

The Canadian Mainline generated net earnings of $272 million in 2004, a decrease of $18 million and $35 million, respectively, when compared to 2003 and 2002 earnings. The decrease in net earnings in 2004 from 2003 is primarily due to a decline in average investment base and allowed ROE. The NEB-approved ROE decreased to 9.56 per cent in 2004 from 9.79 per cent in 2003. The reduction in net earnings from $307 million in 2002 to $290 million in 2003 is due to the combined effect of a lower average investment base and recognition of incremental earnings in 2002 as a result of the NEB’s June 2002 Fair Return decision in which it increased the deemed common equity ratio to 33 per cent from 30 per cent effective January 1, 2001. This decision resulted in additional net earnings of $16 million for the year ended December 31, 2001, which the company recognized in 2002.

 

Alberta System The Alberta System is regulated by the EUB primarily under the provisions of the Gas Utilities Act (Alberta) (GUA) and the Pipeline Act (Alberta). Under the GUA, its rates, tolls and other charges, and terms and conditions of service are subject to approval by the EUB.

 

Net earnings of $150 million in 2004 were $40 million lower than 2003 and $64 million lower than 2002. These decreases were primarily due to the impacts of the EUB decisions in respect of Phase I of the 2004 GRA in August 2004 and on the GCOC proceeding in July 2004. In the 2004 GRA Phase I decision, the EUB disallowed approximately $24 million of operating costs associated with the operation of the pipeline. In addition, the GCOC decision resulted in a lower return on deemed common equity in 2004 compared to the earnings implicit in the 2003 and 2002 negotiated settlements which included fixed revenue requirement components, before non-routine adjustments, of $1.277 billion and $1.347 billion, respectively. Net earnings in 2004 reflect a return of 9.60 per cent on deemed common equity of 35 per cent as approved in the GCOC decision. The negative impact of the two EUB decisions on 2004 net earnings was partially offset by lower operating costs.

 

GTN GTN is regulated by the U.S. Federal Energy Regulatory Commission (FERC), which has authority to regulate rates for natural gas transportation in interstate commerce. Both the Gas Transmission Northwest System and the North Baja System operate under fixed rate models, under which maximum and minimum rates for various service types have been ordered by the FERC and under which GTN is permitted to discount or negotiate rates on a non-discriminatory basis. The Gas Transmission Northwest System’s last filed rate case was in 1994 and it was settled and approved by the FERC in 1996. The North Baja System’s rates were established in the FERC’s initial order in 2002 certifying construction and operation of the system. The net earnings of GTN are impacted by variations in volumes delivered under the various service types

 

 

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that are provided, as well as by variations in the costs of providing transportation service. Net earnings were $14 million for the two months ended December 31, 2004.

 

Other Gas Transmission TransCanada’s direct and indirect investments in various natural gas pipelines and gas transmission related businesses are included in Other Gas Transmission. It also includes project development activities related to TransCanada’s pursuit of new pipeline and natural gas transmission related opportunities throughout North America, including northern gas and LNG.

 

TransCanada’s net earnings from Other Gas Transmission in 2004 were $121 million compared to $116 million and $109 million in 2003 and 2002, respectively. The increased net earnings of $5 million in 2004 compared to 2003 were due to higher earnings from CrossAlta, reflecting favourable natural gas storage market conditions in Alberta, higher earnings from Ventures LP as a result of an expansion that was completed in 2003 and higher earnings from Great Lakes as a result of successful marketing of short-term services. In addition, a $7 million gain was recorded on the sale of the company’s equity interest in Millennium in 2004. These increases were partially offset by the impact of a weaker U.S. dollar and higher general, administrative and support costs. Earnings for 2003 also included a positive $11 million tax adjustment for TransGas.

 

GAS TRANSMISSION – OPPORTUNITIES AND DEVELOPMENTS

 

GTN Acquisition TransCanada acquired GTN on November 1, 2004 for approximately US$1.2 billion, excluding assumed debt of approximately US$0.5 billion. The acquisition of GTN complements TransCanada’s long-term commitment to serve the Pacific Northwest and California markets, which the company has advanced over the past few years with its 2002 West Path expansion and the purchase of the remaining interests in Foothills in 2003 that it previously did not own. GTN consists of two interstate pipeline systems: the Gas Transmission Northwest System, a 2,174 km pipeline extending from Kingsgate, B.C. on the B.C./Idaho border to Malin, Oregon on the Oregon/California border; and the North Baja System, a 128 km system that extends from Ehrenberg, Arizona to a point near Ogilby, California on the California/Mexico border. The North Baja System is well positioned to provide natural gas transportation services from LNG regasification terminals currently planned to be constructed on the coast of northern Baja California, Mexico.

 

Simmons Acquisition In October 2004, TransCanada acquired Simmons for approximately $22 million. The assets include 380 km of pipeline and metering facilities and four compressor units located in northern Alberta. The system has a capacity of approximately 185 MMcf/d. Simmons delivers natural gas to the Fort McMurray area from several connecting receipt points within the Alberta System, along with production connected directly to the pipeline. Continued development of oil sands resources is expected to increase the demand for natural gas in the Fort McMurray area, as oil sands production requires natural gas supply for hydrogen feedstock, power generation and fuel.

 

Iroquois In February 2004, the Iroquois pipeline began commercial operation of its Eastchester expansion. The expansion was the first major natural gas transmission pipeline to be built into New York City in approximately 40 years. In January 2004, Iroquois filed a rate application with the FERC to establish rates for the Eastchester

 

 

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expansion. Iroquois received approval from the FERC in October 2004 of its comprehensive settlement agreement, which implements an eight year rate moratorium for Eastchester. In addition to settling the Eastchester recourse rates, Iroquois also entered into negotiated rate agreements with all of the initial shippers on the Eastchester project.

 

Portland In August 2004, Portland initiated a restructuring plan whereby all of its operating and administrative functions would be performed by TransCanada pursuant to service agreements. The transition of duties was completed by December 2004.

 

Supply In 2004, primary supply growth within the WCSB came from northeastern B.C. and the west central foothills area of Alberta. TransCanada attracted incremental volumes from the Sierra discovery in B.C. through the new Ekwan receipt connection and incremental supply from the emerging Cutbank Ridge discovery in B.C. In Alberta, TransCanada saw increased incremental volumes from the central foothills area as well as unconventional production from coalbed methane (CBM), primarily from Horseshoe Canyon coal located in the central Alberta area between Edmonton and Calgary.

 

TransCanada continues to pursue the most cost effective and timely connection of these volumes, which allows TransCanada’s customers to take advantage of continued premium gas price environments. TransCanada will continue to grow by seeking new opportunities to connect additional gas supplies.

 

Western Markets TransCanada continues to pursue growth opportunities within existing and new natural gas markets. In 2004, TransCanada further executed its strategy to provide cost effective incremental delivery service into the growing Fort McMurray, Alberta market. The acquisition of Simmons was approved by the EUB and the costs of acquiring these assets were added to the Alberta System rate base. The Alberta System’s new arrangement for transportation service with Ventures LP was also approved and this service commenced on October 1, 2004.

 

TransCanada has also negotiated an arrangement with Husky Oil for transportation service on the Kearl Lake Pipeline that will provide the Alberta System an additional 110 MMcf/d delivery capacity. The fast growing production from oil-sands supply in Fort McMurray has also driven expansion in the refining sector of east Edmonton. As a result, TransCanada has negotiated an arrangement for transportation service with ATCO Pipelines (ATCO) that will allow TransCanada to provide incremental delivery service into the industrial market east of Edmonton. Both the Husky Kearl Lake and ATCO transportation service arrangements are included in the 2005 GRA.

 

Eastern Markets Demand for natural gas continues to be strong in Eastern Canada and Northeast U.S. markets as reflected by the response to several open seasons held on TransCanada’s Canadian Mainline. Power generation continues to be the primary driver for incremental natural gas demand in these markets. Ontario and Québec markets continue to develop power projects that require significant incremental natural gas volumes.

 

Customer behaviour continues to reinforce contract repositioning from long haul to short haul transportation and TransCanada seeks to address these market needs. To that end, TransCanada proposed a new contracting point near North Bay, Ontario to provide customers with additional flexibility. The NEB approval of the NBJ Application in 2004 means the market now has an additional short haul contracting option available.

 

Northern Development In 2004, TransCanada continued to pursue pipeline opportunities to move both Mackenzie Delta and Alaska North Slope natural gas to markets throughout North America.

 

TransCanada, the Mackenzie Delta gas producers and the APG reached funding and participation agreements in June 2003 that secured a role for TransCanada in the proposed Mackenzie Gas Pipeline Project and the APG to become an equity participant. This 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. TransCanada has agreed to finance the APG for its one-third share of project development costs. This share is currently expected to be approximately $90 million. The loan will be repaid from the APG’s share of available future pipeline revenues. TransCanada funded $26 million of this loan in 2004, for a total of $60 million to December 31, 2004. The ability to recover this investment is dependent upon the outcome of the project. Under the terms of the

 

25


 

agreement, TransCanada gains an immediate opportunity to acquire up to five per cent equity ownership of the pipeline at the time of construction. In addition, TransCanada also gains certain rights of first refusal to acquire 50 per cent of any divestitures of existing partners and an entitlement to obtain a one-third interest in all expansion opportunities once the APG reaches a one-third share, with the producers and the APG sharing the balance.

 

In October 2004, Imperial Oil Resources applied for the main regulatory approvals for the Mackenzie Gas Pipeline Project. These were submitted to the boards, panels and agencies responsible for assessing and regulating energy developments in the Northwest Territories. These filings mark a significant milestone in the project definition phase. TransCanada will continue to support the project through its position established under the various project agreements and to facilitate the interconnection of Mackenzie Delta natural gas into the Alberta System.

 

In 2004, TransCanada continued its discussions with Alaska North Slope producers and the State of Alaska relating to the Alaskan portion of the Alaska Highway Pipeline Project. In June 2004, TransCanada filed an application under the State of Alaska’s Stranded Gas Development Act and requested the State resume processing of its long-pending application for a right-of-way lease across State lands. Once the right-of-way lease application is approved, TransCanada is prepared to convey the lease to another entity if that entity is willing to connect with TransCanada’s pipeline system. The lease conveyance would require an interconnection agreement with TransCanada at the Yukon/Alaska border. TransCanada’s application is one of three applications currently before the State.

 

Foothills holds the priority right to build, own and operate the first pipeline through Canada for the transportation of Alaskan gas. This right was granted under the NPA, following a lengthy competitive hearing before the NEB in the late 1970’s, which resulted in a decision in favour of Foothills. The NPA creates a single window regulatory regime that is uniquely available to Foothills. It has been used by Foothills to construct the facilities in Alberta which constitute a prebuild for the Alaska Highway Pipeline Project, and to expand those facilities five times, the latest of which was in 1998. Continued development under the NPA should ensure the earliest in-service date for the project.

 

LNG In September 2004, TransCanada and Petro-Canada signed a Memorandum of Understanding to develop an LNG facility, Cacouna Energy, in Cacouna, Québec. TransCanada and Petro-Canada will each own 50 per cent of the facility and TransCanada will operate the facility, while Petro-Canada will contract for all of the capacity and supply the LNG. The proposed facility would be capable of receiving, storing and regasifying imported LNG with an average annual send-out capacity of approximately 500 MMcf/d of natural gas. The estimated cost of construction is $660 million. Construction of the facility is subject to regulatory approval from federal, provincial and municipal governments which is expected to take approximately two years. If approval is received, the facility is expected to be in-service towards the end of this decade.

 

In November 2004, TransCanada and Shell US Gas & Power LLC (Shell) announced plans to jointly develop an offshore LNG regasification terminal, Broadwater Energy, in the New York State waters of Long Island Sound. The proposed floating storage and regasification unit would be located approximately 15 km off the Long Island coast and 18 km off the Connecticut coast. The proposed terminal would be capable of receiving, storing and regasifying imported LNG with an average send-out capacity of approximately one Bcf/d of natural gas. Broadwater Energy LLC, an entity which will be owned 50 per cent by TransCanada, will own and operate the facility, while Shell will contract for all of the capacity and supply the LNG. The estimated cost of construction is expected to be approximately US$700 million. Construction of the facility is subject to regulatory approval from U.S. federal and state governments. The regulatory approval process is expected to take approximately two to three years. TransCanada and Shell have filed a request with the FERC to initiate a six to nine month public review of the Broadwater proposal. Provided the necessary approvals are received, it is expected the facility will be in-service in late 2010.

 

In a referendum held in March 2004, the residents of Harpswell, Maine voted against leasing a town-owned site to build the Fairwinds LNG regasification facility. As a result, TransCanada and its partner, ConocoPhillips Company, have suspended further work on this LNG project.

 

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Natural Gas Storage In September 2004, TransCanada entered into long-term arrangements, commencing in second quarter 2005, for approximately 20 Bcf of additional natural gas storage capacity in Alberta. The capacity under contract increases to approximately 30 Bcf in 2006 and approximately 40 Bcf in 2007.

 

In January 2005, TransCanada announced that it is developing a $200 million natural gas storage project near Edson, Alberta. The Edson facility will have a capacity of approximately 50 Bcf and will connect to TransCanada’s Alberta System. Storage capacity is expected to be available from the Edson facility commencing in second quarter 2006, on a phased-in basis.

 

These developments, combined with the company’s investment in the CrossAlta natural gas storage facility, position TransCanada to become one of the largest natural gas storage providers in Western Canada. Upon completion of the Edson facility, TransCanada will own or control more than 110 Bcf, or approximately one-third, of the storage capacity in Alberta at that time. Current market fundamentals for natural gas storage are strong. The imbalance in North American natural gas supply and demand has created natural gas price volatility, resulting in demand for storage service. TransCanada believes Alberta-based storage will continue to serve market needs and could play an even more important role when northern gas is connected to North American markets.

 

Oil Pipeline In February 2005, TransCanada announced that it is proposing a US$1.7 billion oil pipeline project to transport approximately 400,000 barrels per day of heavy crude oil from Alberta to Illinois. The proposed Keystone project would be approximately 3,000 km in length. In addition to new pipeline construction, it would require the conversion of approximately 1,240 km of one of the lines in TransCanada’s existing multi-line natural gas pipeline systems in Alberta, Saskatchewan and Manitoba.

 

TransCanada will continue to meet with oil producers, refiners and industry groups, including the Canadian Association of Petroleum Producers, to gauge additional interest and support for Keystone. Preliminary discussions have begun with stakeholders, including communities, government representatives and landowners along the proposed route. When sufficient support for this project from oil producers and shippers is obtained, TransCanada will proceed with the necessary regulatory applications. TransCanada will require various regulatory approvals from Canadian and U.S. agencies before construction can begin.

 

TransCanada is in the business of connecting energy supplies to markets and it views this opportunity as another way of providing a valuable service to its customers. Converting one of the company’s natural gas pipeline assets for oil transportation is an innovative, cost-competitive way to meet the need for pipeline expansions to accommodate anticipated growth in Canadian crude oil production during the next decade.

 

GAS TRANSMISSION – REGULATORY DEVELOPMENTS

 

In 2004, TransCanada’s principal regulatory activities included the appeal to the Federal Court of Appeal (FCA) of the NEB’s February 2003 decision on TransCanada’s September 2002 application to review and vary its decision on the fair return for the Canadian Mainline in 2001 and 2002 issued in June 2002; the EUB’s GCOC proceeding; the 2004 Application; Phase I and II of the Alberta System’s 2004 GRA; and the NBJ proceeding. TransCanada also filed the Alberta System’s 2005 GRA-Phase I application. On February 24, 2005, TransCanada advised the EUB that it had reached an agreement in principle for the Alberta System with negotiating parties and requested a suspension of the established regulatory timetable for adjudication of the 2005 GRA pending its finalization of the contemplated settlement agreement. On February 25, 2005, the EUB granted this request. In February 2005, TransCanada reached a settlement with its Canadian Mainline shippers regarding 2005 tolls.

 

Canadian Mainline In February 2003, the NEB denied TransCanada’s September 2002 request for a Review and Variance of the Fair Return decision. TransCanada maintained that the Fair Return decision issued in June 2002 did not recognize the long-term business risks of the Canadian Mainline, which led to an appeal of this decision with the FCA. In May 2003, the FCA granted TransCanada leave to appeal the NEB’s February 2003 decision. In April 2004, the FCA dismissed TransCanada’s appeal of the NEB’s Fair Return Review and Variance

 

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decision, while endorsing TransCanada’s view of the law relating to the determination of a fair return by the NEB.

 

In September 2003, TransCanada filed an application to define a new receipt and delivery point near NBJ to better satisfy market requirements. A December 2004 NEB decision approved NBJ as a new contracting point.

 

In January 2004, TransCanada filed its 2004 Application with the NEB, which included a request for approval of an 11 per cent ROE on deemed common equity of 40 per cent. Given the then pending appeal to the FCA on return issues, the NEB decided to hear the application in a two-phase proceeding, with all matters except cost of capital to be considered in the first phase. In its Phase I decision issued in September 2004, the NEB approved virtually all applied-for costs and the new FT-NR. Upon receipt of the FCA’s decision dismissing TransCanada’s appeal in April 2004, TransCanada amended its application to an ROE of 9.56 per cent, as determined under the NEB’s generic ROE formula, on deemed common equity of 40 per cent. The NEB proceeded to consider cost of capital in the second phase of the proceeding which commenced in November 2004 and continued into 2005. A decision is expected in second quarter 2005.

 

In November 2004, the Canadian Association of Petroleum Producers (CAPP) filed an application with the NEB to review and vary its Phase I decision with respect to approving tolls for FT-NR to be determined on a biddable basis, allowing TransCanada to include all forecast long-term incentive compensation costs in its 2004 cost of service and allowing TransCanada to recover, through tolls, certain regulatory and legal costs relating to review and appeal proceedings.

 

On February 18, 2005, having considered whether there was a doubt as to the correctness of its decision on these matters, the NEB decided to review its decision on the toll to be charged for FT-NR service. It also decided not to review its decision on the inclusion of the disputed regulatory and legal costs in tolls. At CAPP’s request, the NEB deferred its consideration of a review on its decision regarding long-term incentive compensation costs. As a next step, the NEB will consider the merits of confirming, amending or overturning its decision on the FT-NR toll.

 

On February 14, 2005, TransCanada announced it had reached a settlement with its Canadian Mainline shippers regarding 2005 tolls. This settlement establishes OM&A costs for 2005 at $169.5 million, which is comparable to the 2004 level. Any variance between actual OM&A costs in 2005 and those agreed to in the settlement will accrue to TransCanada. All other cost elements of the 2005 revenue requirement will be treated on a flow through basis. Further, the 2005 ROE for the Canadian Mainline will be 9.46 per cent as determined under the NEB’s generic ROE formula, and the common equity component of the Canadian Mainline’s capital structure in 2005 shall be based on the NEB’s decision in the recently concluded hearing on the Canadian Mainline’s cost of capital for 2004, subject to the outcome of any review applications or appeals.

 

Alberta System In July 2003, TransCanada, along with other utilities, filed evidence in the EUB’s GCOC Proceeding. In this application, TransCanada requested a return of 11 per cent on a deemed common equity of 40 per cent for the Alberta System in 2004. In July 2004, the EUB released its decision on the GCOC Proceeding. In its GCOC decision, the EUB set a generic ROE of 9.60 per cent for all Alberta utilities for 2004 and an equity thickness for the Alberta System of 35 per cent. The EUB decided that the generic ROE in future years will be adjusted by 75 per cent of the change in long-term Canada bonds, consistent with the approach used by the NEB. The EUB also indicated that a review of its ROE adjustment mechanism would not occur prior to 2009, unless the ROE resulting from the application of the ROE formula is less than 7.6 per cent or greater than 11.6 per cent. As for changes in capital structure, the EUB expects changes would only be pursued if there is a material change in investment risk.

 

In August 2004, TransCanada received the EUB’s decision on Phase I of the 2004 GRA which consisted of evidence in support of the applied-for rate base and revenue requirement. The EUB approved depreciation rates which resulted in a composite rate of 4.05 per cent in 2004, the purchase of Simmons and the recovery of costs associated with existing transportation arrangements with the Foothills, Simmons and Ventures LP systems. However, the EUB decision disallowed certain operating and capital costs.

 

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In September 2004, TransCanada filed with the Alberta Court of Appeal for leave to appeal the EUB’s decision on Phase I of the 2004 GRA with respect to the disallowance of applied-for incentive compensation costs. In its decision, the EUB disallowed approximately $24 million (pre tax) of operating costs, which included $19 million of applied-for incentive compensation costs. TransCanada believes the EUB made errors of law in deciding to deny the inclusion of these compensation-related costs in the revenue requirement. The company believes these are necessary costs that it reasonably and prudently incurs for the safe, reliable and efficient operation of the Alberta System. At the request of TransCanada, the Court of Appeal adjourned the appeal for an indefinite period of time while TransCanada considers the merits of a review and variance application to the EUB in respect of 2004 costs, and works toward a negotiated settlement of future years’ tolls with its customers.

 

In October 2004, the EUB approved Phase II of the 2004 GRA, which primarily dealt with rate design and services. The EUB also directed TransCanada to file a 2005 GRA-Phase II application on or before April 1, 2005 to address certain cost allocation issues related to rate design.

 

In December 2004, TransCanada filed its 2005 Phase I GRA with the EUB. On February 24, 2005, TransCanada advised the EUB that it had reached an agreement in principle for the Alberta System with negotiating parties and requested a suspension of the established regulatory timetable for adjudication of the 2005 GRA pending its finalization of the contemplated settlement agreement. On February 25, 2005, the EUB granted this request.

 

GAS TRANSMISSION – BUSINESS RISKS

 

Competition TransCanada faces competition at both the supply end and the market end of its systems. The competition is a result of other pipelines accessing an increasingly mature WCSB and markets served by TransCanada’s pipelines. In addition, the continued expiration of transportation contracts has resulted in significant reductions in firm contracted capacity on both the Canadian Mainline and Alberta System.

 

As of December 2003, the WCSB had remaining discovered natural gas reserves of 55 trillion cubic feet and a reserves-to-production ratio of approximately nine years at current levels of production. Historically, additional reserves have continually been discovered to maintain the reserves-to-production ratio at close to nine years. Natural gas prices in the future are expected to be higher than long-term historical averages due to a tighter supply/demand balance which should stimulate exploration and production in the WCSB. However, WCSB supply is expected to remain essentially flat. With the expansion of capacity on TransCanada’s wholly- and partially-owned pipelines over the past decade, and the competition provided by other pipelines, combined with significant growth in natural gas demand in Alberta, TransCanada anticipates there will be excess pipeline capacity out of the WCSB for the foreseeable future.

 

TransCanada’s Alberta System provides the major natural gas gathering and export transportation capacity for the WCSB by connecting to most of the natural gas processing plants in Alberta and then transporting natural gas for domestic and export deliveries. The Alberta System faces competition primarily from the Alliance Pipeline, a natural gas pipeline from northeast B.C. to the Chicago area for ex-Alberta deliveries. In addition, the Alberta System has faced, and will continue to face, increasing competition from other pipelines.

 

The Canadian Mainline is TransCanada’s cross-continent natural gas pipeline serving mid-western and eastern markets in Canada and the U.S. The demand for natural gas in TransCanada’s key eastern markets is expected to continue to increase, particularly to meet the expected growth in gas-fired power generation. Although there are opportunities to increase market share in Canadian and U.S. export markets, TransCanada faces significant competition in these regions. Consumers in the U.S. Northeast have access to an array of pipeline and supply options. Eastern Canadian markets that historically received Canadian supplies only from TransCanada are now capable of receiving supplies from new pipelines into the region that can source Western Canadian, Atlantic Canadian and U.S. supplies.

 

The Canadian Mainline has experienced reductions in long haul FT contracts. This has been partially offset by an increase in short haul contracts. While decreases in throughput do not directly impact Canadian Mainline earnings, such decreases will impact the competitiveness of its tolls. Looking forward, in the short to medium

 

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term, there is limited opportunity to reduce tolls by increasing long haul volumes on the Canadian Mainline.

 

The Gas Transmission Northwest System must compete with other pipelines for access to natural gas supplies and its markets. Transportation service capacity on the Gas Transmission Northwest System provides customers with access to supplies of natural gas primarily from the WCSB and serves markets in the Pacific Northwest, California and Nevada. These three markets may also access supplies from other competing basins in addition to supplies from the WCSB. Historically, natural gas supplies from the WCSB have been competitively priced on the Gas Transmission Northwest System in relation to natural gas supplies from the other supply regions serving these markets. Natural gas transported from the WCSB on the Gas Transmission Northwest System competes for the California and Nevada markets against supplies from the Rocky Mountain and southwest U.S. supply basins. In the Pacific Northwest market, natural gas transported on the Gas Transmission Northwest System competes against Rocky Mountain gas supply as well as additional western Canadian supply that is transported by Williams’ Northwest Pipeline.

 

Transportation service on the North Baja System provides access to natural gas supplies primarily from both the Permian Basin, located in western Texas and southeastern New Mexico, and the San Juan Basin, primarily located in northwestern New Mexico and Colorado. The North Baja System delivers gas to Gasoducto Bajanorte Pipeline at the California/Mexico border, which transports the gas to markets in northern Baja California, Mexico. While there are currently no direct competitors to deliver natural gas to the North Baja System’s downstream markets, the pipeline may compete with fuel oil which is an alternative to natural gas in the operation of some electric generation plants in the North Baja region. The North Baja System’s market is near locations of interest for LNG development companies who may be interested in delivering foreign natural gas supplies to the area.

 

Financial Risk Regulatory decisions continue to have a significant impact on the financial returns for existing and future investments in TransCanada’s Canadian wholly-owned pipelines. TransCanada remains concerned the approved financial returns discourage additional investment in existing Canadian natural gas transmission systems. TransCanada had applied for a return of 11 per cent on 40 per cent deemed common equity, both to the NEB in the Canadian Mainline’s 2004 Application and to the EUB in the Alberta System’s application in the GCOC proceeding. In its GCOC decision, the EUB set a generic ROE of 9.60 per cent for all Alberta utilities for 2004 and a deemed equity thickness for the Alberta System of 35 per cent. Following the FCA’s decision, TransCanada revised its 2004 Application to reflect a return of 9.56 per cent based on the NEB formula on 40 per cent common equity. The NEB’s deliberations on the 2004 Application respecting these matters are currently under way with a decision expected in second quarter 2005.

 

The company is cognisant of the views and shares the concerns of credit rating agencies regarding the Canadian regulatory environment. Credit ratings and liquidity have risen to the forefront of investor attention. In light of the developments in the Canadian regulatory environment, there exists a view that current Canadian regulatory policy is eroding the credit worthiness of utilities which, over the long term, could make it increasingly difficult for utilities to access capital on reasonable terms.

 

Foreign Exchange TransCanada’s earnings from GTN, as well as a significant amount of earnings in Other Gas Transmission are generated in U.S. dollars. The performance of the Canadian dollar relative to the U.S. dollar would either positively or negatively impact Gas Transmission’s net earnings.

 

Throughput Risk As transportation contracts expire on Great Lakes, Northern Border and GTN, these pipelines will be more exposed to throughput risk and their revenues will more likely experience increased variability. Throughput risk is created by supply availability, economic activity, weather variability, pipeline competition and pricing of alternative fuels.

 

Regulation The Alberta System is regulated by the EUB. The remaining Canadian pipelines, other than Ventures LP, are regulated by the NEB. In the U.S., TransCanada’s wholly- and partially-owned pipelines are regulated by the FERC. These regulators approve the pipelines’ respective ROE, costs of service, capital structures, tolls and system expansions.

 

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GAS TRANSMISSION – OTHER

 

Operational Excellence TransCanada continued its commitment to operational excellence in 2004 by further advancing initiatives that will improve the company’s ability to provide low-cost, reliable and responsive service to customers. TransCanada continues to pursue this strategy in order to become the preferred company that customers choose to connect new natural gas supplies and markets.

 

In 2004, TransCanada reduced operating and maintenance costs through rationalizing maintenance and streamlining the delivery of services. The company met its ongoing goals in the management of greenhouse gases. TransCanada also achieved a high level of plant operating performance, as measured by the number of operational perfect days on both the Canadian Mainline and the Alberta System.

 

In 2004, TransCanada maintained high levels of customer satisfaction with the launch of a new website called “Customer Express”. Customer Express is integrated into TransCanada’s website and provides customers with more efficient access to commercial information needed to make transportation decisions. Customer feedback indicates this new website was very well received. Also, through a collaborative effort with customers, a new long-haul firm transportation service enhancement (FT-RAM) was offered on a one year pilot basis beginning November 1, 2004. The purpose of FT-RAM is to mitigate unutilized demand charges and provide greater flexibility in order to attract and retain contracts for FT service.

 

In 2005, TransCanada will continue to focus efforts on efficiencies, operational reliability, and environmental and safety performance. Greenhouse gas emissions management programs will continue to receive focused attention. Additional effort will be undertaken in 2005 with respect to improving contractor safety performance.

 

Safety TransCanada worked closely with regulators, customers and communities during 2004 to ensure the continued safety of employees and the public. Pipeline safety performance in 2004 was excellent with no line-breaks or other serious incidents. Under the approved regulatory models in Canada, expenditures on pipeline integrity have no negative impact on earnings. The company expects to spend approximately $70 million in 2005 for pipeline integrity on its Wholly-Owned Pipelines, which is comparable to amounts spent in 2004. TransCanada continues to use a rigorous risk management system that focuses spending on issues and areas that have the largest impact on maintaining or improving the reliability and safety of the pipeline system.

 

Environment In 2004, TransCanada continued to conduct activities to increase environmental protection through proactive sampling, remediation and monitoring programs. Compressor stations on the Alberta System have been assessed through the company’s Site Assessment, Remediation & Monitoring program. In 2004, TransCanada invested in improved environmental protection measures. This program of actively assessing and addressing environmental issues will continue into the future. In addition, the decommissioning of six Canadian Mainline compressor plants and two Alberta compressor plants was undertaken in 2004, effectively reclaiming each project site.

 

For information on management of risks with respect to the Gas Transmission business, see the Risk Management section.

 

GAS TRANSMISSION – OUTLOOK

 

TransCanada’s Gas Transmission business has a long history of providing pipeline capacity to markets and connecting natural gas supply for the company’s customers. As the marketplace has evolved and competition has grown, Gas Transmission has focused on providing market-responsive products and services, competitive cost-effective structures and the highest levels of reliability to customers.

 

TransCanada continues to actively pursue pipeline and natural gas transmission-related development and acquisition opportunities in North America, where these opportunities are driven by strong customer demand and sound economics. The company will continue to evaluate options in a disciplined fashion to maintain a strong financial position.

 

World geo-political events will have an impact on the level of development of future and existing natural gas supplies worldwide. This could directly impact TransCanada, with the company expanding existing

 

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facilities across North America and being involved in the development of alternative natural gas transportation solutions as producers access northern and Atlantic Canada natural gas reserves.

 

TransCanada is committed to play a key role in northern gas development. While there are many issues to be resolved before this moves forward, TransCanada has advantages including expertise in the design, construction and operation of large diameter pipe in cold weather conditions. TransCanada is also the leading operator of large natural gas turbine compressor stations, owns and operates one of the largest, most sophisticated, remote-controlled pipeline networks in the world and has a solid reputation for safety and reliability. This positions the company well to play a key role in bringing northern gas to market.

 

In 2005, the company will continue to focus on achieving additional efficiency improvements in all aspects of the business by maintaining focus on operational excellence and leveraging technological advancements. TransCanada will also continue to work collaboratively with all stakeholders on negotiated settlements and the evolution of services that will increase the value of TransCanada’s business to customers and shareholders.

 

Looking forward, as the supply/demand balance tightens, producers will continue to explore and develop new fields, particularly in northeastern B.C. and the central foothills regions of Alberta, as well as unconventional supply such as gas production from CBM reserves. In addition, TransCanada anticipates filing an application in 2005 with the EUB to construct Alberta System facilities required to connect additional natural gas supplies delivered to the Alberta System from the Mackenzie Delta.

 

TransCanada’s earnings from its Canadian wholly-owned pipelines are primarily determined by the average investment base, ROE, deemed common equity and opportunity for incentive earnings. In the short to medium term, the company expects a modest level of investment in these mature assets and therefore anticipates, due to depreciation, a continued decline in the average investment base. Accordingly, without an increase in ROE, deemed common equity or incentive opportunities, future earnings are anticipated to decrease. However, these mature assets will continue to generate strong cash flows that can be redeployed to other projects offering higher returns. Under the current regulatory model, earnings from the Canadian wholly-owned pipelines are not affected by short-term fluctuations in the commodity price of natural gas, changes in throughput volumes or changes in contract levels.

 

Earnings On February 14, 2005 TransCanada announced it had reached a settlement with its Canadian Mainline shippers regarding 2005 tolls. This settlement essentially establishes an OM&A at-risk model for 2005 and has fixed OM&A at a level comparable to 2004. This OM&A at-risk settlement will provide some opportunity for incentive earnings as TransCanada continues to focus efforts on cost efficiencies in 2005. This settlement also establishes the 2005 ROE for the Canadian Mainline at 9.46 per cent as determined under the NEB formula, and its capital structure for 2005 to be subject to the outcome of the recently concluded hearing of the 2004 Application – Phase II.

 

In February 2005, TransCanada reached an agreement in principle with its Alberta System shippers on a revenue requirement settlement for the period January 1, 2005 to December 31, 2007. TransCanada is proceeding with finalizing the terms of the settlement with the negotiating parties and anticipates executing the settlement agreement in March 2005. TransCanada expects to file the settlement agreement with the EUB for approval shortly thereafter.

 

In 2005, there will be a full year’s contribution from GTN, which was acquired on November 1, 2004.

 

Net earnings for Other Gas Transmission in 2005 will be affected by factors such as the level of project development costs and the performance of the Canadian dollar relative to the U.S. dollar.

 

Capital Expenditures Total capital spending for the Canadian wholly-owned pipelines during 2004 was $132 million. Overall capital spending on the Wholly-Owned Pipelines, including GTN, in 2005 is expected to be approximately $171 million. Capital expenditures on the Edson natural gas storage project are expected to be approximately $150 million in 2005.

 

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Natural Gas Throughput Volumes

 

(Bcf)

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

Canadian Mainline (1)

 

2,621

 

2,628

 

2,630

 

Alberta System (2)

 

3,909

 

3,883

 

4,146

 

Gas Transmission Northwest System (3)

 

181

 

 

 

 

 

Foothills System

 

1,139

 

1,110

 

1,098

 

BC System

 

360

 

325

 

371

 

Great Lakes

 

801

 

856

 

863

 

Northern Border

 

845

 

850

 

839

 

Iroquois

 

356

 

341

 

340

 

TQM

 

159

 

164

 

175

 

Ventures LP

 

136

 

111

 

85

 

Portland

 

50

 

53

 

52

 

Tuscarora

 

25

 

22

 

20

 

TransGas

 

18

 

16

 

16

 

 

(1)   Canadian Mainline deliveries originating at the Alberta border and in Saskatchewan for the year ended December 31, 2004 were 2,017 Bcf (2003 – 2,055 Bcf; 2002 – 2,221 Bcf).

(2)   Field receipt volumes for the Alberta System for the year ended December 31, 2004 were 3,952 Bcf (2003 – 3,892 Bcf; 2002 – 4,101 Bcf).

(3)   TransCanada acquired GTN on November 1, 2004. The North Baja System’s total delivery volumes were 13 Bcf. The delivery volumes represent November and December 2004 throughput.

 

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POWER

 

HIGHLIGHTS

 

Net Earnings Power’s net earnings in 2004 were $396 million compared to $220 million in 2003 with the increase primarily due to $187 million of gains related to Power LP.

 

Power’s net earnings for 2004, excluding the $187 million of gains related to Power LP, would have been $209 million which was an increase of $8 million compared to $201 million in 2003, excluding a positive settlement in 2003 of $19 million after tax with a former counterparty.

 

Bruce Power Pre-tax equity income from Bruce Power of $130 million in 2004 increased $31 million compared to TransCanada’s period of ownership in 2003.

 

Unit 3 returned to service in first quarter 2004 increasing TransCanada’s share of nominal generating capacity of Bruce Power to 1,487 MW.

 

A feasibility study was commenced with respect to the restart of Units 1 and 2.

 

A study of a potential investment in the refurbishment of the 680 MW Point Lepreau nuclear generating station in New Brunswick was commenced.

 

Expanding Asset Base TransCanada announced it will proceed with the purchase of hydroelectric generation assets from USGen with a total generating capacity of 567 MW for US$505 million. The acquisition is subject to regulatory approvals and pending the sale of the 49 MW Bellows Falls hydroelectric facility to Vermont Hydroelectric. If Vermont Hydroelectric acquires Bellows Falls, for which it exercised a pre-existing option to purchase, the purchase price will be reduced by US$72 million to US$433 million for generating capacity of 518 MW.

 

The MacKay River plant in Alberta was placed in-service in 2004.

 

Construction of the 90 MW Grandview cogeneration plant was completed on time and within budget.

 

Construction commenced in third quarter 2004 of the 550 MW Bécancour natural gas-fired cogeneration power plant in Québec to be in-service in late 2006.

 

TransCanada announced that Hydro-Québec awarded Cartier Wind, owned 62 per cent by TransCanada, six projects totalling 739.5 MW which are scheduled to be commissioned between 2006 and 2012.

 

The company responded to the Ontario government’s Request For Proposals for 2,500 MW of new electricity generation capacity.

 

Plant Availability Weighted average plant availability was 96 per cent in 2004, excluding Bruce Power, compared to 94 per cent in 2003.

 

Including Bruce Power, weighted average plant availability remained the same in 2004 as 2003 at 90 per cent.

 

34


 

Power Net Earnings-at-a-Glance

 

Year ended December 31 (millions of dollars)

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

Western operations

 

138

 

160

 

131

 

Eastern operations

 

108

 

127

 

149

 

Bruce Power investment

 

130

 

99

 

 

 

Power LP investment

 

29

 

35

 

36

 

General, administrative, support costs and other

 

(89

)

(86

)

(73

)

Operating and other income

 

316

 

335

 

243

 

Financial charges

 

(13

)

(12

)

(13

)

Income taxes

 

(94

)

(103

)

(84

)

 

 

209

 

220

 

146

 

Gains related to Power LP (after tax)

 

187

 

—

 

—

 

Net earnings

 

396

 

220

 

146

 

 

Power’s net earnings in 2004 of $396 million increased $176 million compared to $220 million in 2003, primarily due to $187 million of gains related to Power LP recorded in 2004. On April 30, 2004, TransCanada sold the ManChief and Curtis Palmer power facilities to Power LP for US$402.6 million, excluding closing adjustments, resulting in an after-tax gain on sale of $15 million (pre-tax gain of $25 million). At a meeting in April 2004, Power LP unitholders approved these acquisitions and the removal of Power LP’s obligation to redeem all units not owned by TransCanada in 2017. TransCanada was required to fund this redemption, thus the removal of Power LP’s obligation eliminated this requirement. To partially finance the acquisition, Power LP issued 8.1 million subscription receipts which were subsequently converted into partnership units and TransCanada contributed $20 million of the net proceeds of $286.8 million from this issue. This issue also reduced TransCanada’s ownership interest in Power LP from 35.6 per cent to 30.6 per cent. As a result of these events, TransCanada recognized dilution and other gains of $172 million in 2004, $132 million of which were previously deferred and were being amortized into income to 2017. Dilution gains arose when TransCanada’s ownership interest in Power LP was decreased at different times as a result of Power LP issuing new partnership units at a market price in excess of TransCanada’s per unit carrying value of the investment.

 

The 2003 results include recognition in Western Operations of a $31 million pre-tax ($19 million after-tax) settlement with a former counterparty that defaulted in 2001 under power forward contracts. Power’s net earnings for 2004, excluding the $187 million of gains related to Power LP in 2004, would have been $209 million which was an increase of $8 million compared to $201 million in 2003, excluding the positive settlement with a former counterparty. Pre-tax equity income from Bruce Power of $130 million in 2004 increased $31 million compared to TransCanada’s period of ownership in 2003. This was partially offset by lower contributions from Eastern Operations and Power LP investment.

 

Power’s net earnings of $220 million in 2003 increased $74 million or 51 per cent compared to earnings of $146 million in 2002. This increase is primarily attributable to the February 2003 acquisition of a 31.6 per cent interest in Bruce Power and higher contributions from Western Operations relating to the settlement with a former counterparty. Partially offsetting these increases were lower earnings from Eastern Operations and higher general, administrative, support costs and other associated with TransCanada’s focus on growth of the Power business.

 

35


 

 

Bear Creek Commercial operation of this 80 MW natural gas-fired cogeneration plant near Grande Prairie, Alberta commenced in March 2003.

 

MacKay River This 165 MW natural gas-fired cogeneration plant near Fort McMurray, Alberta was placed in-service in 2004.

 

Redwater Commercial operation of this 40 MW natural gas-fired cogeneration plant near Redwater, Alberta commenced in January 2002.

 

Sundance A&B The Sundance power facility in Alberta is the largest coal-fired electrical generating facility in Western Canada. TransCanada owns the Sundance A PPA, which increased the company’s power supply by 560 MW for a 17 year period commencing in 2001. TransCanada effectively owns 50 per cent of the 706 MW Sundance B PPA through a partnership arrangement, which increased the company’s power supply by 353 MW for approximately 19 years commencing in 2002.

 

Carseland Commercial operation of this 80 MW natural gas-fired cogeneration plant near Carseland, Alberta commenced in January 2002.

 

Cancarb The 27 MW Cancarb facility at Medicine Hat, Alberta is fuelled by waste heat from TransCanada’s adjacent thermal carbon black facility.

 

Bruce Power In February 2003, TransCanada acquired a 31.6 per cent equity interest in Bruce Power, which operates the Bruce nuclear power facility located near Lake Huron, Ontario. This investment indirectly increased TransCanada’s nominal generating capacity initially by approximately 1,000 MW, with an additional 474 MW added with the restart of two laid-up units in late 2003 and early 2004.

 

OSP The OSP plant is a 560 MW natural gas-fired, combined-cycle facility in Rhode Island.

 

36


 

Bécancour The 550 MW Bécancour natural gas-fired cogeneration power plant located near Trois-Rivières, Québec is under construction and is expected to be in-service in late 2006. The entire power output will be supplied to Hydro-Québec under a 20 year power purchase contract. Steam will also be supplied to local businesses.

 

Cartier Wind Cartier Wind, 62 per cent owned by TransCanada, announced in fourth quarter 2004 it was awarded six wind projects by Hydro-Québec totalling 739.5 MW to be commissioned between 2006 and 2012. Construction on the first project is expected to commence in late 2005.

 

Grandview Construction of the 90 MW Grandview natural gas-fired cogeneration power plant located in Saint John, New Brunswick was completed by the end of 2004. Under a 20 year tolling arrangement, 100 per cent of the plant’s heat and electricity output will be sold to Irving Oil.

 

USGen In fourth quarter 2004, TransCanada announced it intends to purchase hydroelectric generation assets from USGen. The assets expected to be purchased have a total generating capacity of 518 MW and are situated on two rivers in New England. The output is not sold under long-term contracts. The transaction is expected to close in the first half of 2005.

 

Curtis Palmer The 60 MW Curtis Palmer hydroelectric facility near Corinth, New York was sold to Power LP in second quarter 2004. All output from this facility is sold through a fixed-priced, long-term agreement.

 

ManChief The 300 MW simple-cycle ManChief facility near Brush, Colorado was sold to Power LP in second quarter 2004. The entire capacity of this natural gas-fired plant is sold under long-term tolling contracts that expire in 2012.

 

Williams Lake Power LP owns a 66 MW wood waste-fired power plant at Williams Lake, B.C.

 

Nipigon, Kapuskasing, Tunis and North Bay These efficient, enhanced combined-cycle facilities are fuelled by a combination of natural gas and waste heat exhaust from adjacent compressor stations on the Canadian Mainline and are owned by Power LP.

 

Calstock Calstock, a 35 MW plant, is fuelled by a combination of wood waste and waste heat exhaust from the adjacent Canadian Mainline compressor station and is owned by Power LP.

 

Castleton Castleton is a 64 MW combined-cycle plant located at Castleton-on-Hudson, New York and is owned by Power LP.

 

Mamquam and Queen Charlotte The 50 MW Mamquam and 6 MW Queen Charlotte hydroelectric facilities are located in B.C. All energy produced from these facilities is contracted long term to B.C. Hydro and Power Authority. The assets were purchased by Power LP in third quarter 2004.

 

Paiton Paiton owns a power project consisting of two 615 MW coal-fired power units located in Indonesia. TransCanada effectively holds an approximate 11 per cent interest in Paiton.

 

37


 

Power Plants – Nominal Generating Capacity and Fuel Type

 

 

 

MW

 

Fuel Type

 

 

 

 

 

 

 

Western operations

 

 

 

 

 

Sundance A (1)

 

560

 

Coal

 

Sundance B (1)

 

353

 

Coal

 

MacKay River

 

165

 

Natural gas

 

Carseland

 

80

 

Natural gas

 

Bear Creek

 

80

 

Natural gas

 

Redwater

 

40

 

Natural gas

 

Cancarb

 

27

 

Natural gas

 

 

 

1,305

 

 

 

Eastern operations

 

 

 

 

 

OSP

 

560

 

Natural gas

 

Bécancour (2)

 

550

 

Natural gas

 

Cartier Wind (3)

 

458

 

Wind

 

USGen (4)

 

518

 

Hydro

 

Grandview (5)

 

90

 

Natural gas

 

 

 

2,176

 

 

 

Bruce Power investment (6)

 

1,487

 

Nuclear

 

Power LP investment (7)

 

 

 

 

 

ManChief

 

300

 

Natural gas

 

Williams Lake

 

66

 

Wood waste

 

Castleton

 

64

 

Natural gas/waste heat

 

Curtis Palmer

 

60

 

Hydro

 

Mamquam and Queen Charlotte

 

56

 

Hydro

 

Tunis

 

43

 

Natural gas/waste heat

 

Nipigon

 

40

 

Natural gas/waste heat

 

Kapuskasing

 

40

 

Natural gas/waste heat

 

North Bay

 

40

 

Natural gas/waste heat

 

Calstock

 

35

 

Wood waste/waste heat

 

 

 

744

 

 

 

Total Nominal Generating Capacity

 

5,712

 

 

 

 

(1)   TransCanada directly or indirectly acquires 560 MW from Sundance A and 353 MW from Sundance B through long-term PPAs, which represents 100 per cent of the Sundance A and 50 per cent of the Sundance B power plant output, respectively.

(2)   Currently under construction.

(3)   Currently in pre-construction design phase. Represents TransCanada’s 62 per cent of 739.5 MW.

(4)   The purchase transaction is expected to close in the first half of 2005. The 518 MW excludes the Bellows Falls facility.

(5)   Placed in-service in first quarter 2005.

(6)   Represents TransCanada’s 31.6 per cent equity interest in Bruce Power. Bruce A consists of four 750 MW reactors. Bruce A Unit 4 was returned to service in fourth quarter 2003. Bruce A Unit 3 was returned to service in first quarter 2004. Bruce A Units 1 and 2 remain in a laid-up state. Bruce B consists of four reactors, which are currently in operation, with a capacity of approximately 3,200 MW. The generating capacity includes 2 MW from TransCanada’s 17 per cent indirect share in Huron Wind L.P. which owns a 9 MW wind farm near Bruce Power.

(7)   At December 31, 2004, TransCanada operated and managed Power LP and held a 30.6 per cent ownership interest in Power LP. The volumes in the table represent 100 per cent of plant capacity.

 

38


 

POWER – EARNINGS ANALYSIS

 

Western Operations The focus of Western Operations is to optimize and expand its existing asset base and maximize asset value through a combination of long- and short-term contracts for power and steam sales. The asset portfolio is among the lowest cost, most competitive generation in the market area. Western Operations directly controls more than 1,300 MW of power supply in Alberta from its five gas-fired co-generation facilities and two Sundance long-term PPAs.

 

Western Operations has two integrated functions – marketing and plant operations. Based in Calgary, Alberta, the marketing function purchases and resells electricity related to the Sundance PPAs, markets uncommitted generation from the Alberta plants and purchases and resells power and gas to maximize the value of its asset base. Plant operations primarily consists of the Alberta power plants and fees earned to manage and operate the Power LP.

 

The marketing function is integral to optimizing Power’s return from its assets and managing risks around uncontracted volumes. A significant portion of plant generation is sold under long-term contract to mitigate price risk. Some output is intentionally not committed under long-term contract to assist in managing Power’s overall portfolio of generation. This approach to portfolio management assists in minimizing costs in situations where TransCanada would otherwise have to purchase power in the open market to fulfil its contractual obligations. In 2004, 86 per cent of total sales volumes were sold under medium- to long-term contracts. The marketing function’s primary role is to manage these open positions and it will also, at times, purchase and re-sell both power and gas in an effort to optimize contributions from each of the generation facilities. In order to mitigate market price risk, Western Operations has sold approximately 81 per cent of the total generation for 2005 and 65 per cent of the expected, average combined total power supply for the next three years. Western Operations’ largest power supply comes from its Sundance PPAs. TransCanada has sold essentially all of the Sundance PPAs’ power supply in 2005 and 80 per cent and 52 per cent of the expected combined power supply for 2006 and 2007, respectively.

 

With the placing in-service of the MacKay River cogeneration facility in 2004, plant operations currently consists of five plants in Alberta with a total generating capacity of approximately 400 MW. The expansion of Alberta generation is consistent with TransCanada’s focus on capitalizing on the company’s expertise in developing new projects and maintaining its position in a region it knows well. In second quarter 2004, and consistent with TransCanada’s portfolio management strategy to divest mature assets and redeploy capital, TransCanada sold the 300 MW ManChief power facility to Power LP.

 

Operating and other income for 2004 of $138 million was $22 million lower compared to the same period in 2003. The decrease was mainly due to a positive $31 million pre-tax ($19 million after-tax) settlement in June 2003 with a former counterparty that defaulted in 2001 under power forward contracts, as well as reduced income from ManChief following the sale of the plant to Power LP in April 2004. Partially offsetting these decreases were contributions from the MacKay

 

 

39


 

River plant which was placed in-service in 2004, fees earned with respect to Power LP’s asset acquisitions in 2004 and the impact of higher net margins achieved in second and third quarter 2004 on the overall portfolio.

 

In 2003, operating and other income from Western Operations increased by 22 per cent to $160 million from $131 million in 2002 due primarily to the 2003 settlement with a former counterparty. A full year of earnings from the ManChief plant, which was acquired in late 2002, higher contributions from the Sundance PPAs reflecting lower transmission costs and higher earnings from the Alberta plants also contributed to higher operating income. Offsetting these increases were the effects in 2003 of lower prices achieved on the overall sale of power and the higher cost of natural gas fuel at the Cancarb carbon black facility.

 

Eastern Operations Eastern Operations is focused on the New England and New York deregulated power markets in the U.S. and on development opportunities in Ontario, Québec and New Brunswick. TransCanada Power Marketing Limited (TCPM), located in Westborough, Massachusetts, continues to navigate through New England’s deregulation process and firmly establish itself as a leading energy provider and marketer in the New England power market.

 

TransCanada’s success in the Northeast U.S. is the direct result of a knowledgeable region-specific marketing operation which is conducted through TCPM. TCPM is focused on selling power under contract to wholesale, commercial and industrial customers while managing a portfolio of power supplies sourced from its own generation, wholesale power purchases and power purchased from the output of Power LP’s 64 MW Castleton plant in New York State. In fourth quarter 2004, TransCanada closed a transaction with Boston Edison Company (Boston Edison) resulting in the company assuming the remaining 23.5 per cent share of the OSP power purchase contracts. All of the OSP output is now marketed by TCPM. TCPM is a full service provider offering varied products and services to assist customers in managing their power supply and power prices in deregulated power markets.

 

Eastern Operations’ power generation assets include OSP and Grandview. OSP is a 560 MW natural gas-fired plant located in Rhode Island. Grandview is a 90 MW natural gas-fired cogeneration facility on the site of the Irving Oil Refinery in Saint John, New Brunswick. Construction of the Grandview facility was complete at the end of 2004 and it was commissioned in first quarter 2005. Under a 20 year tolling arrangement, Irving will provide fuel for the plant and contract for 100 per cent of the plant’s heat and electricity output. On April 30, 2004, and consistent with TransCanada’s portfolio management strategy to divest mature assets and redeploy capital, TransCanada sold the 60 MW Curtis Palmer hydroelectric power facility to Power LP.

 

Operating and other income for 2004 was $108 million or $19 million lower than the $127 million earned in 2003. This decrease was mainly due to a reduction in income as a result of the sale of the Curtis Palmer hydroelectric facilities to Power LP in April 2004, the unfavourable impact of higher natural gas fuel costs at OSP and a weaker U.S. dollar in 2004. Partially offsetting these decreases was a $16 million positive impact from the restructuring transaction related to the power purchase contracts between OSP and Boston Edison. TransCanada recognized earnings from the transaction’s effective date of April 1, 2004.

 

Operating and other income for 2003 from Eastern Operations was $127 million compared to $149 million in 2002. The $22 million decrease was primarily due to the impact of higher natural gas fuel costs at OSP resulting from an arbitration process and the unfavourable impact of a weaker U.S. dollar. Partially offsetting these decreases were incremental earnings from the growth in volumes and margins on sales to wholesale, commercial and industrial customers. In addition, 2003 had higher earnings from Curtis Palmer as a result of above average water flows and revenue earned from a temporary generation facility operated in Cobourg, Ontario during the summer of 2003.

 

40


 

In late 2004, management conducted a review of the operating plan for OSP with respect to the negative impacts of a third arbitration received in August 2004 whereby OSP’s cost of fuel gas substantially increased to a price in excess of market. The outcome of a fourth arbitration is expected by the end of third quarter 2005. At December 31, 2004, there was determined to be no impairment of OSP; however, there existed uncertainty with respect to the outcome of this arbitration process and future market conditions. Should the fourth arbitration decision continue to support a pricing mechanism for fuel gas in excess of market price and if anticipated market conditions do not change substantially, management expects the negative impact of the continued above-market gas prices could result in an asset impairment write-down of the OSP facility. The net carrying value of OSP at December 31, 2004 was approximately US$150 million.

 

Bruce Power Investment On February 14, 2003, the company completed the acquisitions of a 31.6 per cent interest in Bruce Power and 33.3 per cent interest in Bruce Power Inc., the general partner of Bruce Power, for $409 million. TransCanada also funded, through a loan arrangement, a one-third share ($75 million) of a $225 million accelerated deferred rent payment made by Bruce Power to Ontario Power Generation (OPG). TransCanada acquired the interests as part of a consortium (the Consortium) that includes Cameco Corporation (Cameco) and BPC Generation Infrastructure Trust, a trust established by the Ontario Municipal Employees Retirement System. Under the agreement, the Consortium acquired British Energy (Canada) Ltd., which owned a 79.8 per cent interest in Bruce Power as well as a 50 per cent interest in the nine MW Huron Wind L.P. power facility. Located in Ontario, the Bruce Power facility is comprised of two nuclear plants – Bruce A and Bruce B. Bruce B consists of four reactors with a capacity of approximately 3,200 MW. Bruce A consists of four reactors which, up until 2003, were not operating. In fourth quarter 2003, Bruce Power completed commissioning of Bruce A Unit 4 and in first quarter 2004, it completed commissioning of Unit 3. These two Bruce A units added 1,500 MW of capacity, bringing Bruce Power’s total capacity to approximately 4,700 MW.

 

Bruce Power is the tenant under a lease with OPG on the Bruce nuclear power facility. The lease expires in 2018 with an option to extend the lease by up to 25 years. The Bruce Power nuclear facility continues

 

Bruce Power Results-at-a-Glance

 

Year ended December 31 (millions of dollars)

 

2004

 

2003

 

 

 

 

 

 

 

Bruce Power (100 per cent basis)

 

 

 

 

 

Revenues

 

1,583

 

1,208

 

Operating expenses

 

(1,178

)

(853

)

Operating income

 

405

 

355

 

Financial charges

 

(67

)

(69

)

Income before income taxes

 

338

 

286

 

TransCanada’s interest in Bruce Power income before income taxes (1)

 

107

 

65

 

Adjustments (2)

 

23

 

34

 

TransCanada’s income from Bruce Power before income taxes

 

130

 

99

 

 

(1)   TransCanada acquired its interest in Bruce Power on February 14, 2003. Bruce Power’s 100 per cent income before income taxes from February 14 to December 31, 2003 was $205 million.

(2)   See Note 8 to the December 31, 2004 consolidated financial statements for an explanation of the purchase price amortizations. The amount allocated to the investment in Bruce Power includes a purchase price allocation of $301 million to the initial lease of the Bruce Power plant which is being amortized on a straight-line basis over the lease term that 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.

 

41


 

to be managed and operated by the management and staff of Bruce Power. Spent fuel and decommissioning liabilities remain the responsibility of OPG but the lease agreement with OPG provides for adjustments to the base rent every five years contingent upon the projected decommissioning costs for the Bruce Power facility.

 

TransCanada’s share of power output from Bruce Power in 2004 was 10,608 gigawatt hours (GWh). This includes power output from Unit 3 from March 1, 2004. Unit 3 began producing electricity to the Ontario electricity grid on January 8, 2004 and was considered commercially in-service March 1, 2004. Bruce Power’s cumulative restart cost for Units 3 and 4 was approximately $720 million.

 

Pre-tax equity income for 2004 was $130 million compared to $99 million for the same period in 2003. This increase was primarily due to higher output in 2004 as a result of the return to service of Units 3 and 4 as well as a full year of earnings in 2004 compared to earnings from February 14 to December 31 in 2003, reflecting TransCanada’s period of ownership in 2003.

 

Adjustments to TransCanada’s interest in Bruce Power income before income taxes for 2004 were lower than the same period in 2003 primarily due to the cessation of interest capitalization upon the return to service of Units 3 and 4. Operating costs for 2004 were $35 per MWh compared to $36 per MWh for the period February 14 to December 31, 2003. Average realized prices in 2004 were $47 per MWh compared to $48 per MWh during TransCanada’s period of ownership in 2003. Approximately 52 per cent of Bruce Power’s output in 2004 was sold into Ontario’s wholesale spot market.

 

TransCanada has not made any cash contributions to, and has not received any cash distributions from, Bruce Power subsequent to the acquisition of the company’s ownership interest in February 2003.

 

Equity income from Bruce Power is directly impacted by fluctuations in wholesale spot market prices for electricity as well as overall plant availability which, in turn, is impacted by scheduled and unscheduled maintenance. To reduce its exposure to spot market prices, Bruce Power has entered into fixed price sales contracts for approximately 36 per cent of planned output for 2005. Bruce Power’s operating expenses in 2005 are expected to increase from 2004 due to higher depreciation and amortization on the Bruce A units, higher outage costs and higher fuel costs.

 

The average availability in 2005 is expected to be 85 per cent compared to 82 per cent achieved in 2004. Unit 3 began its first planned maintenance outage on January 8, 2005 and is expected to be offline for approximately two months. Unit 4 is scheduled to go offline later in first quarter 2005 for a similar inspection program. Maintenance outages of approximately two to three months each are also planned for two other units in 2005. One outage is expected to begin in second quarter 2005 and the other outage is expected to begin in third quarter 2005.

 

Power LP Investment Power LP Investment includes the earnings generated from TransCanada’s 30.6 per cent investment in Power LP, which is one of Canada’s largest publicly-held, power-based income funds. Power LP owns 11 power plants, eight in Canada and three in the U.S., that are hydroelectric or fuelled by natural gas, waste heat, wood waste or a combination thereof. Power LP increased its generating capacity in 2004 from 328 MW to 744 MW through the acquisition of four power facilities, Curtis Palmer and ManChief from TransCanada and Mamquam and Queen Charlotte through the acquisition of Hydro Investment Corporation.

 

TransCanada’s investment in Power LP decreased in 2004 from 35.6 per cent to 30.6 per cent. In 2004, Power LP issued 8.1 million subscription receipts to partially finance the purchase of the Curtis Palmer and ManChief power generation facilities from TransCanada. TransCanada purchased 540,000 of these subscription receipts for $20 million. All of the subscription receipts were converted to limited partnership units on April 30, 2004 upon Power LP’s acquisition of the Curtis Palmer and ManChief facilities, thereby reducing TransCanada’s ownership of the partnership to 30.6 per cent. TransCanada continues to be the largest unitholder and the manager of Power LP, owning approximately 14.5 million units at December 31, 2004.

 

42


 

TransCanada is the manager of Power LP and its power plant operations. In this capacity, TransCanada manages the operations and maintenance requirements of all Power LP plants, the fuel supply and associated price exposure and, when market conditions warrant, enhances the overall operating profits of Power LP (i.e. by curtailing certain plants during off-peak hours and selling the displaced natural gas at attractive market prices), resulting in increased overall net earnings for Power LP and maximized investment value for unitholders, including TransCanada.

 

Operating and other income from the investment in Power LP of $29 million for 2004 was $6 million lower compared to 2003. Additional earnings from Power LP’s April 2004 acquisition of the Curtis Palmer and ManChief facilities were more than offset by the impact of TransCanada’s reduced ownership interest in Power LP and the recognition of $132 million of previously deferred gains resulting from the removal of the Power LP redemption obligation. Prior to the removal of the redemption obligation, TransCanada was recognizing into income the amortization of these deferred gains over a period through to 2017.

 

The cash distributions to TransCanada from Power LP in 2004 were approximately $36 million compared to $35 million in 2003. At December 31, 2004, Power LP units closed at $35.40 on the Toronto Stock Exchange.

 

POWER SALES VOLUMES AND PLANT AVAILABILITY

 

Power Sales Volumes

 

(GWh)

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

Western operations (1)

 

11,695

 

12,296

 

12,065

 

Eastern operations (1)

 

6,198

 

6,906

 

5,630

 

Bruce Power investment (2)

 

10,608

 

6,655

 

 

 

Power LP investment (1)  (3)

 

2,419

 

2,153

 

2,416

 

Total

 

30,920

 

28,010

 

20,111

 

 

(1)   ManChief and Curtis Palmer are included in Power LP Investment, effective April 30, 2004.

(2)   Acquired on February 14, 2003. Sales volumes in 2003 reflect TransCanada’s 31.6 per cent share of Bruce Power output from the date of acquisition.

(3)   At December 31, 2004, TransCanada operated and managed Power LP and held a 30.6 per cent ownership interest in Power LP. The volumes in the table represent 100 per cent of Power LP’s sales volumes.

 

Power sales volumes increased 10 per cent in 2004 to 30,920 GWh compared to 28,010 GWh in 2003 primarily due to TransCanada’s full year of ownership in Bruce Power, in addition to the restart of Bruce Power Units 3 and 4.

 

Sales volumes for Western Operations were lower in 2004 compared to 2003 due to the sale of ManChief to Power LP in April 2004, and lower portfolio management trading activity, partially offset by new volumes from the MacKay River plant placed in-service in 2004. Eastern Operations’ sales volumes decreased in 2004 compared to 2003 primarily as a result of the sale of Curtis Palmer to Power LP in April 2004, lower utilization of OSP and a reduction in contract volumes due to lower demand. Sales volumes for the Bruce Power investment increased by 59 per cent as a result of the restart of Bruce Power Units 3 and 4 and TransCanada’s full year of ownership in 2004 partially offset by decreased plant availability. Volumes for Power LP increased due to the purchase of Curtis Palmer and ManChief in April 2004 and Mamquam and Queen Charlotte in July 2004.

 

43


 

Weighted Average Plant Availability (1)

 

 

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

Western operations (2)

 

95

%

93

%

99

%

Eastern operations (2)

 

95

%

94

%

95

%

Bruce Power investment (3)

 

82

%

83

%

 

 

Power LP investment (2)

 

97

%

96

%

94

%

All plants, excluding Bruce Power investment

 

96

%

94

%

96

%

All plants

 

90

%

90

%

96

%

 

(1)   Plant availability represents the percentage of time in the year that the plant is available to generate power, whether actually running or not, and is reduced by planned and unplanned outages.

(2)   ManChief and Curtis Palmer are included in Power LP Investment effective April 30, 2004.

(3)   The comparative 2003 percentage is calculated from the February 14, 2003 date of acquisition. Unit 4 is included effective November 1, 2003 and Unit 3 is included effective March 1, 2004.

 

POWER – OPPORTUNITIES AND DEVELOPMENTS

 

TransCanada is committed to develop, acquire, own and operate the lowest-cost power sources or have facilities with secure long-term contracts in markets it knows. TransCanada seeks to build or acquire low-cost, base-load facilities with low operating costs and high reliability. TransCanada seeks to avoid high-cost facilities that sell into volatile merchant markets without long-term contracts. Power intends to execute its strategy by:

 

•       Focusing on markets and regions where it has a competitive advantage – primarily Western Canada and the Northwestern U.S., and Eastern Canada and the Northeastern U.S.

 

•       Focusing on low-cost, base-load generation.

 

•       Focusing on new projects underpinned by secure long-term contracts.

 

•       Structuring deals to keep risks low.

 

•       Using solid disciplined marketing and trading operations to sell power that is not contracted and optimize and protect power-generation cash flows.

 

In fourth quarter 2004, TransCanada announced that it will purchase hydroelectric generation assets from USGen with a total generating capacity of 567 MW for US$505 million. The purchase is subject to the sale of the 49 MW Bellows Falls hydroelectric facility to Vermont Hydroelectric, which exercised its pre-existing option to purchase the facility. This would result in a US$72 million reduction in purchase price to US$433 million for generating capacity of 518 MW. All bankruptcy court approvals have been granted for TransCanada’s USGen acquisition. However, other regulatory approvals and conditions will need to be met prior to closing. The transaction is expected to close in the first half of 2005.

 

Cartier Wind, owned 62 per cent by TransCanada, announced in fourth quarter 2004 it was awarded six wind energy projects in Québec by Hydro-Québec representing a total of 739.5 MW. The six projects are expected to be commissioned between 2006 and 2012 and are expected to cost a total of more than $1.1 billion. Long-term electricity supply contracts with Hydro-Québec for each of the six facilities were executed on February 25, 2005.

 

Construction of the 550 MW Bécancour natural gas-fired cogeneration power plant in Québec began in third quarter 2004, to be in-service in late 2006. In mid-2003, TransCanada announced its plans to develop the power plant which is located in the Bécancour Industrial Park, near Trois-Rivières. The entire power output will be supplied to Hydro-Québec under a 20 year power purchase contract. The plant will also supply steam to certain major businesses located within the industrial park.

 

Late in fourth quarter 2004, TransCanada responded to the Ontario government’s Request For Proposals for 2,500 MWs of new electricity generation capacity, of which Portlands Energy Centre L.P. (Portlands Energy) was one of the submitted projects by TransCanada. Portlands Energy is a 550 MW natural gas-fuelled facility in downtown Toronto and would be developed through a partnership with OPG.

 

44


 

Following the successful restart of Bruce A Units 3 and 4, Bruce Power began conducting a technical review to assess the feasibility of refurbishing Bruce A Units 1 and 2. Units 1 and 2 were laid-up in 1995 and 1997, respectively. Information has been gathered to evaluate the condition of the units to fully understand the project scope and cost, and environmental assessment of the project continues to be performed. In September 2004, the province of Ontario appointed a special negotiator to work with Bruce Power to negotiate an agreement for additional electricity supply. While no decision has been finalized with respect to the refurbishment of Units 1 and 2, the return to service of these units would be a significant step towards satisfying the province of Ontario’s future energy requirements. This technical review will also establish improvements that will be required to extend the lives of the six operating units which are scheduled to be taken out of service over the next 15 years. In 2004, Bruce Power expensed $16 million related to this project.

 

TransCanada, together with its Bruce Power partners, is evaluating a potential investment in the Point Lepreau nuclear generating station in New Brunswick. Point Lepreau, which is indirectly owned by the New Brunswick provincial government, is a 680 MW nuclear power plant with a CANDU reactor similar to the Bruce reactors in Ontario. No decision has been made by TransCanada and its partners as to whether Bruce Power will proceed with investment in the Point Lepreau facility. Discussions are ongoing with New Brunswick Power.

 

POWER – BUSINESS RISKS

 

Plant Availability Maintaining plant availability is critical to the continued success of the Power business and this risk is mitigated through a commitment to an operational excellence model that provides low-cost, reliable operating performance at each of the company’s operated power plants. This same commitment to operational excellence will be applied in 2005 and future years. However, unexpected plant outages and/or the duration of outages may require purchases at market prices to enable TransCanada to meet the company’s contractual power supply obligations and/or increase maintenance costs.

 

Fluctuating Market Prices TransCanada operates in highly competitive, deregulated power markets. Volatility in electricity prices is caused by market factors such as power plant fuel costs, fluctuating supply and market demand which are greatly affected by weather, power consumption and plant availability. TransCanada manages these inherent market risks through:

 

•     long-term purchase and sales contracts for both electricity and plant fuels;

 

•     control of generation output;

 

•     matching physical plant contracts or PPA supply with customer demand;

 

•     fee-for-service managed accounts rather than direct commodity exposure; and

 

•     the company’s overall risk management program with respect to general market and counterparty risks.

 

The company’s risk management practices are described further in the section on Risk Management. TransCanada’s largest exposure to sales price fluctuations is on Bruce Power’s uncontracted volumes. See the section below “Power – Business Risks – Uncontracted Volumes”.

 

Regulatory TransCanada operates in both regulated and deregulated power markets. As electricity markets evolve across North America, there is the potential for regulatory bodies to implement new rules that could negatively impact TransCanada as a generator and marketer of electricity. These may be in the form of market rule changes, price caps, unfair cost allocations to generators or attempts to control the wholesale market by encouraging new plant construction. TransCanada continues to monitor regulatory issues and reform as well as participate in and lead discussions around these topics.

 

Weather Temperature and weather events may create power and gas demand and price volatility, and may also impact the ability to transmit power to markets. Seasonal changes in temperature also affect the efficiency and output capability of natural gas-fired power plants.

 

45


 

Hydrology Power is subject to hydrology risk with its ownership, directly and indirectly, of hydroelectric power generation facilities. Weather changes, local river management and potential dam failures at these plants or upstream plants pose potential risks to the company.

 

Uncontracted Volumes Although TransCanada seeks to secure sales under medium- to long-term contracts, TransCanada retains an amount of unsold generation in the short term in order to provide flexibility in managing the company’s portfolio of owned assets. Bruce Power has a significant amount of its uncontracted volumes sold into the Ontario wholesale spot market. The sale of this power in the open market is subject to market price volatility which directly impacts earnings.

 

POWER – OTHER

 

Operational Excellence TransCanada is committed to its operational excellence model to provide low cost, reliable operating performance at each of its plants in an effort to achieve and sustain high performance as measured against broad industry standards. Weighted average plant availability, excluding Bruce Power, averaged 96 per cent in 2004, exceeding the comparative industry average of 90 per cent. Forced outage rates (unplanned outages) in 2004 were 1.6 per cent as compared to a comparative industry average of 5.5 per cent.

 

POWER – OUTLOOK

 

Contributions from Eastern Operations are expected to be lower in 2005 due to higher natural gas costs at OSP resulting from the 2004 arbitration decision, no earnings in 2005 from Curtis Palmer as a result of its sale to Power LP in April 2004, the expiration of long-term contracts held by TCPM at the end of 2004 and the expected non-recurrence of earnings recognized from the Boston Edison transaction in 2004. Partially offsetting these reductions are earnings from Grandview and the USGen acquisition expected to close in the first half of 2005. Should the fourth arbitration decision at OSP, expected in 2005, result in a continued pricing mechanism for fuel gas in excess of market price and if anticipated market conditions do not change substantially, management expects there could be an asset impairment write-down of this facility. The net carrying value of OSP at December 31, 2004 was approximately US$150 million.

 

Bruce Power earnings are subject to potential variability as a result of prices realized, plant availability and operating expense levels. A $1.00 per MWh change in the spot price for electricity in Ontario would change TransCanada’s after-tax equity income from Bruce Power by approximately $5 million. The average availability of Bruce Power in 2005 is expected to be 85 per cent compared to 82 per cent in 2004. Bruce Power operating expenses are expected to increase in 2005 due to higher outage costs, higher depreciation on the Bruce A units and recent capital programs, and higher fuel costs.

 

Earnings opportunities in Power may be affected by factors such as plant availability, fluctuating market prices for power and gas and ultimately market heat rates, regulatory changes, weather, sales of uncontracted volumes, currency movements and overall stability of the power industry. Please see “Power – Business Risks” for a complete discussion of these factors.

 

46


 

CORPORATE

 

HIGHLIGHTS

 

Net Expenses Net expenses in 2004 decreased $39 million compared to 2003.

 

Corporate Results-at-a-Glance

 

Year ended December 31 (millions of dollars)

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

Indirect financial and preferred equity charges

 

79

 

89

 

91

 

Interest income and other

 

(34

)

(21

)

(14

)

Income taxes

 

(43

)

(27

)

(25

)

Net expenses, after tax

 

2

 

41

 

52

 

 

The Corporate segment reflects net expenses not allocated to specific business segments, including:

 

•       Indirect Financial and Preferred Equity Charges Direct financial charges are reported in their respective business segments and are primarily associated with the debt and preferred securities related to the company’s Wholly-Owned Pipelines. Indirect financial charges, including the related foreign exchange impacts, primarily reside in the Corporate segment. These costs are directly impacted by the amount of debt TransCanada maintains and the degree to which TransCanada is impacted by fluctuations in interest rates and foreign exchange.

 

•       Interest Income and Other Interest income is earned on invested cash balances. Gains and losses on foreign exchange related to working capital in the Corporate segment are included in interest income and other.

 

Net expenses, after tax, in the Corporate segment were $2 million in 2004 compared to $41 million in 2003 and $52 million in 2002.

 

The decrease in net expenses in 2004 from 2003 was primarily due to the positive impacts of income tax related items, including refunds received and the recognition of income tax benefits relating to additional loss carryforwards utilized, the release in 2004 of previously established restructuring provisions and positive impacts of foreign exchange related items.

 

The decrease in net expenses in 2003 from 2002 was primarily due to the positive impacts of a weaker U.S. dollar compared to the prior year.

 

In 2005, the Corporate segment is expected to incur a more normalized level of net expenses with higher net expenses than in 2004.

 

47


 

LIQUIDITY AND CAPITAL RESOURCES

 

HIGHLIGHTS

 

Investing Activities Total capital expenditures and acquisitions, including assumed debt, were approximately $4.7 billion over the past three years.

 

Dividend TransCanada’s Board of Directors has increased quarterly common share dividend payments for the past five consecutive years, including a 5.2 per cent increase to $0.305 per share from $0.29 per share for the quarter ending March 31, 2005.

 

 

 

Funds Generated from Continuing Operations Funds generated from continuing operations were approximately $1.7 billion for 2004 compared to approximately $1.8 billion for both 2003 and 2002. The decrease in 2004 was mainly as a result of higher current income tax expenses in 2004 compared to the two prior years. The Gas Transmission business was the primary source of funds generated from operations for each of the three years. As a result of rapid growth in the Power business in the last few years, the Power segment’s funds from operations increased in 2004 compared to the two prior years.

 

At December 31, 2004, TransCanada’s ability to generate adequate amounts of cash in the short term and the long term when needed, and to maintain financial capacity and flexibility to provide for planned growth, was consistent with the past few years.

 

Investing Activities Capital expenditures, excluding acquisitions, totalled $476 million in 2004 compared to $391 million and $599 million in 2003 and 2002, respectively. Expenditures in all three years related primarily to maintenance and capacity capital in TransCanada’s Gas Transmission business and construction of new power plants in Canada.

 

During 2004, TransCanada acquired GTN for approximately US$1.2 billion, excluding assumed debt of approximately US$0.5 billion, and sold the ManChief and Curtis Palmer power facilities for US$402.6 million, excluding closing adjustments.

 

During 2003, TransCanada acquired a 31.6 per cent interest in Bruce Power for $409 million, the remaining interests in Foothills previously not held by the company for $105 million, excluding assumed debt of $154 million, and increased its interest in Portland to 61.7 per cent from 33.3 per cent for US$51 million, excluding assumed debt of US$78 million.

 

During 2002, TransCanada acquired the ManChief power plant for $209 million and a general partnership interest in Northern Border Partners, L.P. for $19 million.

 

Financing Activities In 2004, TransCanada retired long-term debt of $997 million. The company issued $200 million of 4.10 per cent medium-term notes due 2009, US$350 million of 5.60 per cent senior unsecured notes due 2034 and US$300 million of 4.875 per cent senior unsecured notes due 2015. The company increased its notes payable by $179 million during 2004.

 

In 2003, TransCanada repaid long-term debt of $744 million, reduced notes payable by $62 million and redeemed all of its outstanding US$160 million, 8.75 per cent Junior Subordinated Debentures. The company issued $450 million of ten year, 5.65 per cent medium-term notes and US$350 million of ten year, 4.00 per cent senior unsecured notes.

 

In 2002, the company funded long-term debt maturities of $486 million and reduced notes payable by $46 million.

 

48


 

Dividends and preferred securities charges amounting to $623 million were paid in 2004 compared to $588 million in 2003 and $546 million in 2002.

 

In February 2005, TransCanada’s Board of Directors approved an increase in the quarterly common share dividend payment to $0.305 per share from $0.29 per share for the quarter ending March 31, 2005. This was the fifth consecutive year of dividend increase since the $0.20 per share declared in fourth quarter 2000.

 

Financing activities include a net increase in TransCanada’s proportionate share of non-recourse debt of joint ventures of $120 million in 2004 compared to net reductions of $11 million in 2003 and $36 million in 2002.

 

Credit Activities In December 2004, TCPL renewed shelf prospectuses that qualified for issuance $1.5 billion of medium-term notes in Canada and US$1 billion of debt securities in the U.S. In January 2005, $300 million of 5.10 per cent medium-term notes due 2017 were issued under the Canadian shelf prospectus.

 

At December 31, 2004, total credit facilities of $2.0 billion were available to support the company’s commercial paper program 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, TransCanada had used approximately $61 million of its total lines of credit for letters of credit and to support ongoing commercial arrangements. If drawn, interest on the lines of credit would be charged at prime rates of Canadian chartered and U.S. banks or at other negotiated financial bases.

 

Credit ratings on TCPL’s senior unsecured debt assigned by Dominion Bond Rating Service Limited (DBRS), Moody’s Investors Service (Moody’s) and Standard & Poor’s are currently A, A2 and A-, respectively. DBRS and Moody’s both maintain a ‘stable’ outlook on their ratings and Standard & Poor’s maintains a ‘negative’ outlook on its rating.

 

CONTRACTUAL OBLIGATIONS

 

Obligations and Commitments Total long-term debt at December 31, 2004 was approximately $10.5 billion compared to approximately $10.0 billion at December 31, 2003. TransCanada’s share of total non-recourse debt of joint ventures at December 31, 2004 was $862 million compared to $780 million at December 31, 2003. Total notes payable, including the proportionate share of joint ventures, at December 31, 2004 were $546 million compared to $367 million at December 31, 2003. The debt and notes payable of joint ventures are non-recourse to TransCanada. The security provided by each joint venture is limited to the rights and assets of that joint venture and do not extend to the rights and assets of TransCanada, except to the extent of TransCanada’s investment.

 

Effective January 1, 2005, under new Canadian accounting standards, the non-controlling interest component of preferred securities, amounting to $670 million at December 31, 2004, will be classified as debt.

 

 

49


 

At December 31, 2004, principal repayments related to long-term debt and the company’s proportionate share of the non-recourse debt of joint ventures are as follows.

 

Principal Repayments

 

Year ended December 31 (millions of dollars)

 

2005

 

2006

 

2007

 

2008

 

2009

 

2010+

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term debt

 

766

 

387

 

615

 

545

 

753

 

7,413

 

Non-recourse debt of joint ventures

 

83

 

49

 

18

 

18

 

141

 

553

 

Total principal repayments

 

849

 

436

 

633

 

563

 

894

 

7,966

 

 

At December 31, 2004, future annual payments, net of sub-lease receipts, under the company’s operating leases for various premises and a natural gas storage facility are approximately as follows.

 

Operating Lease Payments

 

Year ended December 31 (millions of dollars)

 

2005

 

2006

 

2007

 

2008

 

2009

 

2010+

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Minimum lease payments

 

37

 

45

 

51

 

53

 

53

 

697

 

Amounts recoverable under sub-leases

 

(9

)

(10

)

(9

)

(9

)

(9

)

(21

)

Net payments

 

28

 

35

 

42

 

44

 

44

 

676

 

 

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.

 

At December 31, 2004, the company’s future purchase obligations are approximately as follows.

 

Purchase Obligations (1)

 

Year ended December 31 (millions of dollars)

 

2005

 

2006

 

2007

 

2008

 

2009

 

2010+

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Transmission

 

 

 

 

 

 

 

 

 

 

 

 

 

Transportation by others (2)

 

186

 

177

 

142

 

121

 

82

 

198

 

Other

 

94

 

46

 

42

 

40

 

2

 

3

 

Power

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity purchases (3)

 

429

 

255

 

259

 

266

 

277

 

2,658

 

Capital expenditures (4)

 

288

 

70

 

—

 

—

 

—

 

—

 

Other (5)

 

93

 

100

 

89

 

84

 

88

 

223

 

Corporate

 

 

 

 

 

 

 

 

 

 

 

 

 

Information technology and other

 

9

 

9

 

7

 

7

 

7

 

—

 

Total purchase obligations

 

1,099

 

657

 

539

 

518

 

456

 

3,082

 

 

(1)   The amounts in this table exclude funding contributions to the company’s pension plans and funding to APG.

(2)   Rates are based on known 2005 levels. Beyond 2005, demand rates are subject to change. The contract obligations in the table are based on known or contracted demand volumes only and exclude commodity charges incurred when volumes flow.

(3)   Commodity purchases include fixed and variable components. The variable components are estimates and are subject to variability in plant production, market prices and regulatory tariffs.

(4)   Amounts are estimates and are subject to variability based on timing of construction and project enhancements.

(5)   Includes estimates of certain amounts which are subject to change depending on plant fired hours, the consumer price index, actual plant maintenance costs, plant salaries as well as changes in regulated rates for transportation.

 

50


 

During 2005, TransCanada expects to make funding contributions to the company’s pension plans and other benefit plans in the amount of approximately $67 million and $6 million, respectively. The expected decrease in total funding in 2005 from $88 million in 2004 is due to investment performance above long-term expectations in 2004 partially offset by continued reductions in discount rates used to calculate plan obligations.

 

On June 18, 2003, the Mackenzie Delta gas producers, the 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 on the balance sheet. The ability to recover this investment is dependent upon the outcome of the project.

 

TransCanada had a $50 million operating line of credit to Power LP, available on a revolving basis. In August 2004, the amount borrowed against this line of credit was fully repaid by Power LP and the operating line of credit was terminated.

 

At December 31, 2004, TransCanada held a 33.4 per cent interest in TC PipeLines, LP which is a publicly-held limited partnership. On May 28, 2003, TC PipeLines, LP renewed its US$40 million unsecured two-year revolving credit facility with TransCanada. At December 31, 2004, the partnership had US$6.5 million outstanding under this credit facility (December 31, 2003 – nil).

 

TransCanada and its affiliates have long-term natural gas transportation and natural gas purchase arrangements as well as other purchase obligations, all of which are or were transacted at market prices and in the normal course of business.

 

Guarantees TransCanada had no outstanding guarantees related to the long-term debt of unrelated third parties at December 31, 2004.

 

Upon acquisition of Bruce Power, the company, together with Cameco 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. 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.

 

51


 

Contingencies The Canadian Alliance of Pipeline Landowners’ Associations and two individual landowners commenced an action in 2003 under Ontario’s Class Proceedings Act, 1992, against 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.

 

FINANCIAL AND OTHER INSTRUMENTS

 

The company issues short-term and long-term debt, including amounts in foreign currencies, purchases and sells energy commodities and invests in foreign operations. These activities result in exposures to interest rates, energy commodity prices and foreign currency exchange rates. The company utilizes derivative and other financial instruments to manage its exposure to the risks that result from these activities.

 

A derivative must be designated and effective to be accounted for as a hedge. Gains or losses relating to derivatives that are hedges are deferred and recognized in the same period and in the same financial statement category as the corresponding hedged transactions. The recognition of gains and losses on derivatives used as hedges for Canadian Mainline, Alberta System, GTN and the Foothills System exposures is determined through the regulatory process.

 

The carrying amounts of derivatives, which hedge the price risk of foreign currency denominated assets and liabilities of self-sustaining foreign operations, are recorded on the balance sheet at their fair value. Gains and losses on these derivatives, realized and unrealized, are included in the foreign exchange adjustment account in Shareholders’ Equity as an offset to the corresponding gains and losses on the translation of the assets and liabilities of the foreign subsidiaries. As of January 1, 2004, carrying amounts for interest rate swaps are recorded on the balance sheet at their fair value. Foreign currency transactions hedged by foreign exchange contracts are recorded at the contract rate. Power, natural gas and heat rate derivatives are recorded on the balance sheet at their fair value.

 

The fair values of foreign exchange and interest rate derivatives have been estimated using year-end market rates. The fair values of power, natural gas and heat rate derivatives have been calculated using estimated forward prices for the relevant period.

 

Notional principal amounts are not recorded in the financial statements because these amounts are not exchanged by the company and its counterparties and are not a measure of the company’s exposure. Notional amounts are used only as the basis for calculating payments for certain derivatives.

 

Foreign Investments At December 31, 2004 and 2003, the company had foreign currency denominated assets and liabilities which created an exposure to changes in exchange rates. The company uses foreign currency derivatives to hedge this net exposure on an after-tax basis. The foreign currency derivatives have a floating interest rate exposure which the company partially hedges by entering into interest rate swaps and forward rate agreements. The fair values shown in the table below for those derivatives that have been designated as and are effective as hedges for foreign exchange risk are offset by translation gains or losses on the net assets and are recorded in the foreign exchange adjustment account in Shareholders’ Equity.

 

52


 

Net Investment in Foreign Assets

 

Asset/(Liability)

 

 

 

 

 

2004

 

2003

 

December 31 (millions of dollars)

 

Accounting
Treatment

 

Fair
Value

 

Notional or
Principal
Amount (U.S.)

 

Fair
Value

 

Notional or
Principal
Amount (U.S.)

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S. dollar cross-currency swaps (maturing 2006 to 2009)

 

Hedge

 

95

 

400

 

65

 

250

 

U.S. dollar forward foreign exchange contracts (maturing 2005)

 

Hedge

 

(1

)

305

 

3

 

125

 

U.S. dollar options (maturing 2005)

 

Non-hedge

 

1

 

100

 

—

 

—

 

 

In accordance with the company’s accounting policy, each of the above derivatives is recorded on the consolidated balance sheet at its fair value in 2004. For derivatives that have been designated as and are effective as hedges of the net investment in foreign operations, the offsetting amounts are included in the foreign exchange adjustment account.

 

In addition, at December 31, 2004, the company had interest rate swaps associated with the cross-currency swaps with notional principal amounts of $375 million (2003 – $311 million) and US$250 million (2003 – US$200 million). The carrying amount and fair value of these interest rate swaps was $4 million (2003 – $3 million) and $4 million (2003 – $1 million), respectively.

 

Reconciliation of Foreign Exchange Adjustment Gains/(Losses)

 

December 31 (millions of dollars)

 

2004

 

2003

 

 

 

 

 

 

 

Balance at beginning of year

 

(40

)

14

 

Translation losses on foreign currency denominated net assets

 

(64

)

(136

)

Foreign exchange gains on derivatives, net of income taxes

 

33

 

82

 

 

 

(71

)

(40

)

 

53


 

Foreign Exchange Gains/(Losses) Foreign exchange gains/(losses) included in Other Expenses/(Income) for the year ended December 31, 2004 are $4 million (2003 – nil; 2002 – $(11) million).

 

Foreign Exchange and Interest Rate Management Activity The company manages certain of the foreign exchange risks of U.S. dollar debt, U.S. dollar expenses and the interest rate exposures of the Canadian Mainline, the Alberta System, GTN and the Foothills System through the use of foreign currency and interest rate derivatives. Certain of the realized gains and losses on these derivatives are shared with shippers on predetermined terms. The details of the foreign exchange and interest rate derivatives are shown in the table below.

 

Asset/(Liability)

 

 

 

 

 

2004

 

2003

 

December 31 (millions of dollars)

 

Accounting
Treatment

 

Fair
Value

 

Notional or
Principal
Amount

 

Fair
Value

 

Notional or
Principal
Amount

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign Exchange

 

 

 

 

 

 

 

 

 

 

 

Cross-currency swaps

 

 

 

 

 

 

 

 

 

 

 

(maturing 2010 to 2012)

 

Hedge

 

(39

)

U.S.

157

 

(26

)

U.S.

282

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Rate

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest rate swaps

 

 

 

 

 

 

 

 

 

 

 

 

 

Canadian dollars

 

 

 

 

 

 

 

 

 

 

 

 

 

(maturing 2005 to 2008)

 

Hedge

 

7

 

 

145

 

(1

)

 

340

 

(maturing 2006 to 2009)

 

Non-hedge

 

9

 

 

374

 

10

 

 

624

 

 

 

 

 

16

 

 

 

 

9

 

 

 

 

U.S. dollars

 

 

 

 

 

 

 

 

 

 

 

 

 

(maturing 2010 to 2015)

 

Hedge

 

(2

)

U.S.

275

 

11

 

U.S.

 50

 

(maturing 2007 to 2009)

 

Non-hedge

 

7

 

U.S.

100

 

(3

)

U.S.

 50

 

 

 

 

 

5

 

 

 

8

 

 

 

 

In accordance with the company’s accounting policy, each of the above derivatives is recorded on the consolidated balance sheet at its fair value in 2004. At December 31, 2004, the company also had interest rate swaps associated with the cross-currency swaps with notional principal amounts of $227 million (2003 – $390 million) and US$157 million (2003 – US$282 million). The carrying amount and fair value of these interest rate swaps was $(4) million (2003 – nil) and $(4) million (2003 – $6 million), respectively.

 

54


 

 

The company manages the foreign exchange and interest rate exposures of its other businesses through the use of foreign currency and interest rate derivatives. The details of these foreign currency and interest rate derivatives are shown in the table below.

 

Asset/(Liability)

 

 

 

 

 

2004

 

2003

 

December 31 (millions of dollars)

 

Accounting
Treatment

 

Fair
Value

 

Notional or
Principal
Amount

 

Fair
Value

 

Notional or
Principal
Amount

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign Exchange

 

 

 

 

 

 

 

 

 

 

 

Options (maturing 2005)

 

Non-hedge

 

2

 

U.S.

225

 

1

 

U.S.

25

 

Forward foreign exchange contracts
(maturing 2005)

 

Non-hedge

 

1

 

U.S.

29

 

1

 

U.S.

19

 

Cross-currency swaps
(maturing 2013)

 

Hedge

 

(16

)

U.S.

100

 

(7

)

U.S.

100

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Rate

 

 

 

 

 

 

 

 

 

 

 

Options (maturing 2005)

 

Non-hedge

 

—

 

U.S.

50

 

(2

)

U.S.

50

 

Interest rate swaps

 

 

 

 

 

 

 

 

 

 

 

Canadian dollar

 

 

 

 

 

 

 

 

 

 

 

(maturing 2007 to 2009)

 

Hedge

 

4

 

100

 

2

 

50

 

(maturing 2005 to 2011)

 

Non-hedge

 

1

 

110

 

2

 

100

 

 

 

 

 

5

 

 

 

4

 

 

 

U.S. dollar

 

 

 

 

 

 

 

 

 

 

 

(maturing 2006 to 2013)

 

Hedge

 

5

 

U.S.

100

 

40

 

U.S.

250

 

(maturing 2006 to 2010)

 

Non-hedge

 

22

 

U.S.

250

 

(3

)

U.S.

200

 

 

 

 

 

27

 

 

 

37

 

 

 

 

In accordance with the company’s accounting policy, each of the above derivatives is recorded on the consolidated balance sheet at its fair value in 2004. At December 31, 2004, the company also had interest rate swaps associated with the cross-currency swaps with notional principal amounts of $136 million (2003 – $136 million) and US$100 million (2003 – US$100 million). The carrying amount and fair value of these interest rate swaps was $(10) million (2003 – nil) and $(10) million (2003 – $(7) million), respectively.

 

Certain of the company’s joint ventures use interest rate derivatives to manage interest rate exposures. The company’s proportionate share of the fair value of the outstanding derivatives at December 31, 2004 was $1 million (2003 – $(1) million).

 

55


 

Energy Price Risk Management The company executes power, natural gas and heat rate derivatives for overall management of its asset portfolio. Heat rate contracts are contracts for the sale or purchase of power that are priced based on a natural gas index. The fair values and notional volumes of the swap, option, forward and heat rate contracts are shown in the tables below. In accordance with the company’s accounting policy, each of the derivatives in the table below is recorded on the balance sheet at its fair value in 2004 and 2003.

 

Power

 

Asset/(Liability)

 

 

 

 

 

 

 

 

 

2004

 

2003

 

December 31 (millions of dollars)

 

 

 

 

 

Accounting
Treatment

 

Fair
Value

 

Fair
Value

 

 

 

 

 

 

 

 

 

 

 

 

 

Power – swaps

 

 

 

 

 

 

 

 

 

 

 

(maturing 2005 to 2011)

 

 

 

 

 

Hedge

 

7

 

(5

)

(maturing 2005)

 

 

 

 

 

Non-hedge

 

(2

)

—

 

Gas – swaps, forwards and options

 

 

 

 

 

 

 

 

 

 

 

(maturing 2005 to 2016)

 

 

 

 

 

Hedge

 

(39

)

(34

)

(maturing 2005)

 

 

 

 

 

Non-hedge

 

(2

)

(1

)

Heat rate contracts

 

 

 

 

 

 

 

 

 

 

 

(maturing 2005 to 2006)

 

 

 

 

 

Hedge

 

(1

)

(1

)

 

Notional Volumes

 

 

 

Accounting
Treatment

 

Power (GWh)

 

Gas (Bcf)

 

December 31, 2004

 

 

Purchases

 

Sales

 

Purchases

 

Sales

 

 

 

 

 

 

 

 

 

 

 

 

 

Power – swaps

 

 

 

 

 

 

 

 

 

 

 

(maturing 2005 to 2011)

 

Hedge

 

3,314

 

7,029

 

—

 

—

 

(maturing 2005)

 

Non-hedge

 

438

 

—

 

—

 

—

 

Gas – swaps, forwards and options

 

 

 

 

 

 

 

 

 

 

 

(maturing 2005 to 2016)

 

Hedge

 

—

 

—

 

80

 

84

 

(maturing 2005)

 

Non-hedge

 

—

 

—

 

5

 

8

 

Heat rate contracts

 

 

 

 

 

 

 

 

 

 

 

(maturing 2005 to 2006)

 

Hedge

 

—

 

229

 

2

 

—

 

 

December 31, 2003

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Power – swaps

 

Hedge

 

1,331

 

4,787

 

—

 

—

 

 

 

Non-hedge

 

59

 

77

 

—

 

—

 

Gas – swaps, forwards and options

 

Hedge

 

—

 

—

 

79

 

81

 

 

 

Non-hedge

 

—

 

—

 

—

 

7

 

Heat rate contracts

 

Hedge

 

—

 

735

 

1

 

—

 

 

56


 

U.S. Dollar Transaction Hedges To reduce risk and protect margins when purchase and sale contracts are denominated in different currencies, the company may enter into forward foreign exchange contracts and foreign exchange options which establish the foreign exchange rate for the cash flows from the related purchase and sale transactions.

 

RISK MANAGEMENT

 

Risk Management Overview TransCanada and its subsidiaries are exposed to market, financial and counterparty risks in the normal course of their business activities. The risk management function assists in managing these various business activities and the risks associated with them. A strong commitment to a risk management culture by TransCanada’s management supports this function. TransCanada’s primary risk management objective is to protect earnings and cash flow and ultimately, shareholder value.

 

The risk management function is guided by the following principles that are applied to all businesses and risk types:

 

•     Board Oversight Risk strategies, policies and limits are subject to review and approval by TransCanada’s Board of Directors.

 

•     Independent Review Risk-taking activities are subject to independent review, separate from the business lines that initiate the activity.

 

•     Assessment Processes are in place to ensure that risks are properly assessed at the transaction and counterparty levels.

 

•     Review and Reporting Market positions and exposures, and the creditworthiness of counterparties are subject to ongoing review and reporting to executive management.

 

•     Accountability Business lines are accountable for all risks and the related returns for their particular businesses.

 

•     Audit Review Individual risks are subject to internal audit review, with independent reporting to the Audit Committee of TransCanada’s Board of Directors.

 

The processes within TransCanada’s risk management function are designed to ensure that risks are properly identified, quantified, reported and managed. Risk management strategies, policies and limits are designed to ensure TransCanada’s risk taking is consistent with the company’s business objectives and risk tolerance. Risks are managed within limits ultimately established by the company’s Board of Directors and implemented by senior management, monitored by risk management personnel and audited by internal audit personnel.

 

TransCanada manages market risk exposures in accordance with the company’s corporate market risk policies and position limits. The company’s primary market risks result from volatility in commodity prices, interest rates and foreign currency exchange rates.

 

Senior management reviews these exposures and reports on a regular basis to the Audit Committee of TransCanada’s Board of Directors.

 

Market Risk Management In order to manage market risk exposures created by fixed and variable pricing arrangements at different pricing indices and delivery points, the company enters into offsetting physical positions and derivative financial instruments. Market risks are quantified using value-at-risk methodology and are reviewed weekly by senior management.

 

Financial Risk Management TransCanada monitors the financial market risk exposures relating to the company’s investments in foreign currency denominated net assets, regulated and non-regulated long-term debt portfolios and foreign currency exposure on transactions. The market risk exposures created by these business activities are managed by establishing offsetting positions or through the use of derivative financial instruments.

 

Counterparty Risk Management Counterparty risk is the financial loss that the company would experience if the counterparty failed to meet its obligations in accordance with the terms and conditions of its contracts with the company. Counterparty risk is mitigated by conducting financial and other assessments to establish a counterparty’s creditworthiness, setting exposure limits and monitoring exposures against these limits, and, where warranted, obtaining financial assurances.

 

57


 

The company’s counterparty risk management practices and positions are further described in Note 14 to the consolidated financial statements.

 

Risks and Risk Management Related to the Kyoto Protocol TransCanada believes that the natural gas that is transported and the electricity that is generated by its facilities play a critical role in meeting continental energy demand. The company also recognizes, however, that its facilities produce emissions that can also contribute to climate change and air related issues. For this reason, the management of air emissions and climate change issues is a key area of the company’s environmental stewardship work.

 

Climate change policy development is well under way in North America. In December 2002, the Canadian government registered its instrument of ratification with the United Nations, making Canada the 100th country to ratify the Kyoto Protocol. Following ratification, the federal government initiated discussions with industry regarding emissions reductions from sources in three broad categories: the oil and gas sector, the electricity sector and the mining/manufacturing sector. The mechanism that is proposed for achieving the reduction is a domestic emissions trading system that would cap emissions from sectors at predetermined emissions intensity levels.

 

As direct emitters of greenhouse gas emissions, TransCanada’s facilities will be impacted by climate change policy developments in Canada. The fossil-fired power plants, pipeline systems and carbon black facilities are expected to be captured under the proposed federal government plan for industrial emitters. At present, however, the details of the target allocation within sectors and allowable compliance options have not been finalized. Until the allocation of targets within the sector are set and until compliance options are fully developed, it is difficult to determine the level of impact to the company’s Canadian asset base.

 

Over the next year, TransCanada will continue to participate in climate change policy discussions in the jurisdictions where the company has assets and business interests. Climate change is a strategic issue for TransCanada and management of this important environmental concern has been ongoing for several years. TransCanada has a comprehensive climate change strategy in place that includes five key areas of activities:

 

•     participation in policy forums;

 

•     implementation of direct emissions reduction programs;

 

•     assessment of new technology;

 

•     evaluation of emissions trading mechanisms; and

 

•     assessment of business opportunities.

 

Activities are ongoing in each of these areas and the company is committed to sharing its progress on key activities publicly. Over the past several years, TransCanada has documented its technical activities and research and development work in yearly reports to Canada’s Climate Change Voluntary Challenge & Registry Inc. The Canadian government has legislated mandatory greenhouse gas emissions reporting beginning in 2005. TransCanada will continue to report on the activities that are under way to manage greenhouse gas emissions.

 

Disclosure Controls and Procedures and Internal Controls Pursuant to regulations adopted by the U.S. Securities and Exchange Commission (SEC), under the Sarbanes-Oxley Act of 2002, TransCanada’s management evaluates the effectiveness of the design and operation of the company’s disclosure controls and procedures (disclosure controls). This evaluation is done under the supervision of, and with the participation of, the President and Chief Executive Officer and the Chief Financial Officer.

 

As of the end of the period covered by this Annual Report, TransCanada’s management evaluated the effectiveness of its disclosure controls. Based on that evaluation, the President and Chief Executive Officer and the Chief Financial Officer have concluded that TransCanada’s disclosure controls are effective in ensuring that material information relating to TransCanada is made known to management on a timely basis, and is included in this Annual Report.

 

To the best of these officers’ knowledge and belief, there have been no significant changes in internal controls over financial reporting or in other factors that could significantly affect internal controls over financial reporting subsequent to the date on which such evaluation was completed in connection with this Annual Report.

 

58


 

CEO and CFO Certifications With respect to the year ending December 31, 2004, TransCanada’s President and Chief Executive Officer has provided the New York Stock Exchange the annual CEO certification regarding TransCanada’s compliance with the New York Stock Exchange’s corporate governance listing standards applicable to foreign issuers. In addition, TransCanada’s President and Chief Executive Officer and Chief Financial Officer have filed with the SEC certifications regarding the quality of TransCanada’s public disclosures relating to its fiscal 2004 reports filed with the SEC.

 

CRITICAL ACCOUNTING POLICY

 

The company accounts for the impacts of rate regulation in accordance with generally accepted accounting principles (GAAP) as outlined in Note 1 to the consolidated financial statements. Three criteria must be met to use these accounting principles: the rates for regulated services or activities must be subject to approval by a regulator; the regulated rates must be designed to recover the cost of providing the services or products; and it must be reasonable to assume that rates set at levels to recover the cost can be charged to and will be collected from customers in view of the demand for services or products and the level of direct and indirect competition. The company’s management believes that all three of these criteria have been met. The most significant impact from the use of these accounting principles is that in order to appropriately reflect the economic impact of the regulators’ decisions regarding the company’s revenues and tolls, and to thereby achieve a proper matching of revenues and expenses, the timing of recognition of certain expenses and revenues in the regulated businesses may differ from that otherwise expected under GAAP. The most significant example of this relates to the recording of income taxes on the taxes payable basis as outlined in Note 15 to the consolidated financial statements.

 

CRITICAL ACCOUNTING ESTIMATE

 

Since a determination of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of the company’s consolidated financial statements requires the use of estimates and assumptions which have been made using careful judgment. TransCanada’s critical accounting estimate is depreciation expense. TransCanada’s plant, property and equipment are depreciated on a straight-line basis over their estimated useful lives. Depreciation expense for the year ended December 31, 2004 was $945 million. Depreciation expense impacts the Gas Transmission and Power segments of the company. In the Gas Transmission business, depreciation rates are approved by the regulators and recoverable based on the cost of providing the services or products. A change in the estimation of the useful lives of the plant, property and equipment in the Gas Transmission segment would, if recovery through rates is permitted by the regulators, have no material impact on TransCanada’s net income but would directly impact funds generated from operations.

 

In 2004, TransCanada recognized in income the remaining amount related to the critical accounting estimate of the after-tax deferred gain recorded on the 2001 sale of the Gas Marketing business, which is further described in Discontinued Operations.

 

ACCOUNTING CHANGES

 

Asset Retirement Obligations In January 2003, the Canadian Institute of Chartered Accountants (CICA) issued a new Handbook Section “Asset Retirement Obligations”. The new section focuses on the recognition and measurement of liabilities for obligations associated with the retirement of property, plant and equipment when those obligations result from the acquisition, construction, development or normal operation of the assets. The section requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset. The liability is accreted at the end of each period through charges to operating expenses. This section was effective for TransCanada as of January 1, 2004 and was applied retroactively with restatement of prior periods. See Note 2 to the consolidated financial statements for the impact of this accounting change.

 

Hedging Relationships Effective January 1, 2004, the company adopted the provisions of the CICA’s new Accounting Guideline “Hedging Relationships” that specifies the circumstances in which hedge accounting

 

59


 

is appropriate, including the identification, documentation, designation and effectiveness of hedges, and the discontinuance of hedge accounting. See Note 2 to the consolidated financial statements for the impact of this accounting change.

 

Generally Accepted Accounting Principles Effective January 1, 2004, the company adopted the new Handbook Section “Generally Accepted Accounting Principles” which establishes standards for financial reporting in accordance with GAAP. It defines primary sources of GAAP and requires that an entity apply every relevant primary source, therefore eliminating the ability to rely on industry practice to support a particular accounting policy and provides an exemption for rate-regulated operations. This section was applied prospectively. See Note 2 to the consolidated financial statements for the impact of this accounting change.

 

General Standards of Financial Statement Presentation Effective January 1, 2004, the company adopted the new Handbook Section “General Standards of Financial Statement Presentation” which clarifies what constitutes “fair presentation in accordance with GAAP”. The adoption of this section did not have an impact on the company’s consolidated financial statements.

 

Employee Future Benefits In March 2004, the CICA amended the existing Handbook Section “Employee Future Benefits”. The amendments expand the disclosure requirements for employee future benefits and are effective for fiscal years ending on or after June 30, 2004. The company adopted these provisions effective December 31, 2004. The impacts of the amendments have been included in Note 18 to the consolidated financial statements.

 

Impairment of Long-Lived Assets Effective January 1, 2004, the company adopted the new Handbook Section “Impairment of Long-Lived Assets”. This section establishes new standards for the recognition, measurement and disclosure of the impairment of long-lived assets and establishes new write-down provisions. The adoption of this section did not have an impact on the company’s consolidated financial statements.

 

Consolidation of Variable Interest Entities In June 2003, the Accounting Standards Board of the CICA issued a new Accounting Guideline “Consolidation of Variable Interest Entities” which requires enterprises to identify variable interest entities in which they have an interest, determine whether they are the primary beneficiary of such entities and, if so, to consolidate them. For TransCanada, the guideline’s requirements are effective as of January 1, 2005. Adopting the provisions of this guideline is not expected to impact the company’s consolidated financial statements.

 

Financial Instruments – Disclosure and Presentation In November 2004, the CICA amended the existing Handbook Section “Financial Instruments – Disclosure and Presentation” to provide guidance for classifying certain financial instruments that embody obligations that may be settled by the issuance of the issuer’s equity shares as debt when the instrument that embodies the obligations does not establish an ownership relationship. This amendment is effective for fiscal years beginning on or after November 1, 2004. As a result, the non-controlling interest component of preferred securities will be classified as debt effective January 1, 2005.

 

DISCONTINUED OPERATIONS

 

TransCanada’s Board of Directors approved plans in previous years to dispose of the company’s International, Canadian Midstream, Gas Marketing and certain other businesses. As of December 31, 2003, TransCanada’s investments in Gasoducto del Pacifico (Gas Pacifico), INNERGY Holdings S.A. (INNERGY) and P.T. Paiton Energy Company (Paiton), which were previously approved for disposal, were accounted for as part of continuing operations due to the length of time it had taken the company to dispose of these assets. Gas Pacifico and INNERGY are included in the Gas Transmission segment and Paiton is included in the Power segment. It is the intention of the company to continue with its plan to dispose of these investments.

 

In 2004, the company reviewed the provision for loss on discontinued operations and the after-tax deferred gain. As a result of this review, TransCanada recognized in income in 2004 the remaining $52 million of the original $102 million after-tax deferred gain.

 

In 2003, TransCanada recognized in income $50 million of the original $102 million after-tax deferred gain. The company’s net income/(loss) from discontinued operations in 2002 was nil.

 

60


 

SUBSIDIARIES AND INVESTMENTS

 

TransCanada’s subsidiaries and investments that hold significant operating assets are noted below.

 

Subsidiary/Investment

 

Major Operating Assets

 

Organized under
the Laws of

 

Effective
Percentage
Ownership by
TransCanada

 

 

 

 

 

 

 

 

 

TransCanada PipeLines Limited

 

Canadian Mainline, BC System

 

Canada

 

100

 

NOVA Gas Transmission Ltd.

 

Alberta System

 

Alberta

 

100

 

TransCanada Pipeline Ventures Ltd.

 

Ventures LP

 

Alberta

 

100

 

Foothills Pipe Lines Ltd.

 

Foothills System

 

Canada

 

100

 

TransCanada Pipeline USA Ltd.

 

 

 

Nevada

 

100

 

Gas Transmission Northwest Corporation

 

GTN

 

California

 

100

 

TransCanada Power Marketing Ltd.

 

U.S. power operations

 

Delaware

 

100

 

Great Lakes Gas Transmission Limited Partnership

 

Great Lakes

 

Delaware

 

50

 

Iroquois Gas Transmission System L.P.

 

Iroquois

 

Delaware

 

41

 

Portland Natural Gas Transmission System Partnership

 

Portland

 

Maine

 

61.7

 

TC PipeLines, LP

 

TC PipeLines, LP’s assets

 

Delaware

 

33.4

 

Northern Border Pipeline Company

 

Northern Border

 

Texas

 

10

 

Tuscarora Gas Transmission Company

 

Tuscarora

 

Nevada

 

17.4

 

TransCanada Energy Ltd.

 

Canadian power operations

 

Canada

 

100

 

TransCanada Power, L.P.

 

Power LP assets

 

Ontario

 

30.6

 

Bruce Power L.P.

 

Bruce Power

 

Ontario

 

31.6

 

Trans Québec & Maritimes Pipeline Inc.

 

TQM

 

Canada

 

50

 

CrossAlta Gas Storage & Services Ltd.

 

CrossAlta

 

Alberta

 

60

 

TransGas de Occidente S.A.

 

TransGas

 

Colombia

 

46.5

 

 

61


 

Selected Three Year Consolidated Financial Data (1)

 

(millions of dollars except per share amounts)

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

Income Statement

 

 

 

 

 

 

 

Revenues

 

5,107

 

5,357

 

5,214

 

Net income

 

 

 

 

 

 

 

Continuing operations

 

980

 

801

 

747

 

Discontinued operations

 

52

 

50

 

—

 

Total

 

1,032

 

851

 

747

 

 

 

 

 

 

 

 

 

Balance Sheet

 

 

 

 

 

 

 

Total assets

 

22,130

 

20,701

 

20,172

 

Long-term debt

 

9,713

 

9,465

 

8,815

 

Non-recourse debt of joint ventures

 

779

 

761

 

1,222

 

Preferred securities

 

19

 

22

 

238

 

 

 

 

 

 

 

 

 

Per Common Share Data

 

 

 

 

 

 

 

Net income – Basic

 

 

 

 

 

 

 

Continuing operations

 

$

2.02

 

$

1.66

 

$

1.56

 

Discontinued operations

 

0.11

 

0.10

 

—

 

 

 

$

2.13

 

$

1.76

 

$

1.56

 

Net income – Diluted

 

 

 

 

 

 

 

Continuing operations

 

$

2.01

 

$

1.66

 

$

1.55

 

Discontinued operations

 

0.11

 

0.10

 

—

 

 

 

$

2.12

 

$

1.76

 

$

1.55

 

Dividends declared

 

$

1.16

 

$

1.08

 

$

1.00

 

 

(1)     The selected three year consolidated financial data has been prepared in accordance with Canadian GAAP. Certain comparative figures have been reclassified to conform with the current year’s presentation. For a discussion on the factors affecting the comparability of the financial data, including discontinued operations, refer to Note 1 and Note 21 of TransCanada’s 2004 audited consolidated financial statements included in TransCanada’s 2004 Annual Report.

 

62


 

Selected Quarterly Consolidated Financial Data (1)

 

(millions of dollars except per share amounts)

 

Fourth

 

Third

 

Second

 

First

 

 

 

 

 

 

 

 

 

 

 

2004

 

 

 

 

 

 

 

 

 

Revenues

 

1,394

 

1,224

 

1,256

 

1,233

 

Net Income

 

 

 

 

 

 

 

 

 

Continuing operations

 

185

 

193

 

388

 

214

 

Discontinued operations

 

—

 

52

 

—

 

—

 

 

 

185

 

245

 

388

 

214

 

 

 

 

 

 

 

 

 

 

 

Share Statistics

 

 

 

 

 

 

 

 

 

Net income per share – Basic

 

 

 

 

 

 

 

 

 

Continuing operations

 

$

0.38

 

$

0.40

 

$

0.80

 

$

0.44

 

Discontinued operations

 

—

 

0.11

 

—

 

—

 

 

 

$

 0.38

 

$

 0.51

 

$

 0.80

 

$

 0.44

 

Net income per share – Diluted

 

 

 

 

 

 

 

 

 

Continuing operations

 

$

 0.38

 

$

 0.39

 

$

 0.80

 

$

 0.44

 

Discontinued operations

 

—

 

0.11

 

—

 

—

 

 

 

$

 0.38

 

$

 0.50

 

$

 0.80

 

$

 0.44

 

Dividend declared per common share

 

$

 0.29

 

$

 0.29

 

$

 0.29

 

$

 0.29

 

 

 

 

 

 

 

 

 

 

 

2003

 

 

 

 

 

 

 

 

 

Revenues

 

1,319

 

1,391

 

1,311

 

1,336

 

Net Income

 

 

 

 

 

 

 

 

 

Continuing operations

 

193

 

198

 

202

 

208

 

Discontinued operations

 

—

 

50

 

—

 

—

 

 

 

193

 

248

 

202

 

208

 

 

 

 

 

 

 

 

 

 

 

Share Statistics

 

 

 

 

 

 

 

 

 

Net income per share – Basic

 

 

 

 

 

 

 

 

 

Continuing operations

 

$

 0.40

 

$

 0.41

 

$

 0.42

 

$

 0.43

 

Discontinued operations

 

—

 

0.10

 

—

 

—

 

 

 

$

 0.40

 

$

 0.51

 

$

 0.42

 

$

 0.43

 

Net income per share – Diluted

 

 

 

 

 

 

 

 

 

Continuing operations

 

$

 0.40

 

$

 0.41

 

$

 0.42

 

$

 0.43

 

Discontinued operations

 

—

 

0.10

 

—

 

—

 

 

 

$

 0.40

 

$

 0.51

 

$

 0.42

 

$

 0.43

 

Dividend declared per common share

 

$

 0.27

 

$

 0.27

 

$

 0.27

 

$

 0.27

 

 

(1)     The selected quarterly consolidated financial data has been prepared in accordance with Canadian GAAP. Certain comparative figures have been reclassified to conform with the current year’s presentation. For a discussion on the factors affecting the comparability of the financial data, including discontinued operations, refer to Note 1 and Note 21 of TransCanada’s 2004 audited consolidated financial statements included in TransCanada’s 2004 Annual Report.

 

63


 

Factors Impacting Quarterly Financial Information In the Gas Transmission business, which consists primarily of the company’s investments in regulated pipelines, annual revenues and net earnings fluctuate over the long term based on regulators’ decisions and negotiated settlements with shippers. Generally, quarter over quarter revenues and earnings during any particular fiscal year remain fairly stable with fluctuations arising as a result of adjustments being recorded due to regulatory decisions and negotiated settlements with shippers and due to items outside of the normal course of operations.

 

In the Power business, which consists primarily of the company’s investments in electrical power generation plants, quarter over quarter revenues and net earnings are affected by seasonal weather conditions, customer demand, market prices, planned and unplanned plant outages as well as items outside of the normal course of operations.

 

Significant items which impacted 2004 and 2003 quarterly net earnings are as follows.

 

•     In first quarter 2003, TransCanada completed the acquisition of a 31.6 per cent interest in Bruce Power, resulting in increased equity income in the Power business from thereon.

 

•     Second quarter 2003 net earnings included a $19 million positive after-tax earnings impact of a June 2003 settlement with a former counterparty that had previously defaulted under power forward contracts.

 

•     Third quarter 2003 net earnings included TransCanada’s $11 million share of a positive future income tax benefit adjustment recognized by TransGas.

 

•     First quarter 2004 net earnings included approximately $12 million of income tax refunds and related interest.

 

•     Second quarter 2004 net earnings included gains related to Power LP of $187 million, of which $132 million were previously deferred and were being amortized into income to 2017.

 

•     In third quarter 2004, the EUB’s decisions on the GCOC and Phase I of the 2004 GRA resulted in lower earnings for the Alberta System compared to the previous quarters. In addition, third quarter 2004 included a $12 million after-tax adjustment related to the release of previously established restructuring provisions and recognition of $8 million of non-capital loss carryforwards.

 

•     In fourth quarter 2004, TransCanada completed the acquisition of GTN, thereby recording $14 million of earnings from the November 1, 2004 acquisition date. Power recorded a $16 million pre-tax positive impact of a restructuring transaction related to power purchase contracts between OSP and Boston Edison in Eastern Operations.

 

FOURTH QUARTER 2004 HIGHLIGHTS

 

Segment Results-at-a-Glance

 

Three months ended December 31 (millions of dollars)

 

2004

 

2003

 

 

 

 

 

 

 

Gas Transmission

 

157

 

160

 

Power

 

31

 

44

 

Corporate

 

(3

)

(11

)

Net income

 

185

 

193

 

 

Net income and net earnings for fourth quarter 2004 for TransCanada were $185 million or $0.38 per share compared to $193 million or $0.40 per share for the same period in 2003. This decrease was primarily due to lower net earnings from the Power and Gas Transmission businesses, partially offset by lower net expenses in the Corporate segment.

 

Power’s net earnings in fourth quarter 2004 of $31 million decreased $13 million compared to $44 million in fourth quarter 2003 primarily due to lower earnings from Western Operations and Eastern Operations. Operating and other income from Western Operations in fourth quarter 2004 of $25 million was $6 million lower compared to the $31 million earned in the same period in 2003. The decrease was mainly due to a

 

64


 

reduction in income from ManChief following the sale of the plant to Power LP in April 2004, cumulative operating cost adjustments settled in fourth quarter 2004 at the MacKay River cogeneration plant and reduced margins resulting from lower market heat rates on uncontracted volumes.

 

Operating and other income from Eastern Operations in fourth quarter 2004 of $31 million was $5 million lower compared to $36 million earned in the same period in 2003. The decrease was primarily due to a reduction in income as a result of the sale of the Curtis Palmer hydroelectric facilities to Power LP in April 2004, the unfavourable impact of higher natural gas fuel costs at OSP, earnings recorded in 2003 on the Cobourg temporary generation facility and a weaker U.S. dollar in 2004 compared to 2003. Partially offsetting these reductions was a $16 million pre-tax positive impact of a restructuring transaction related to power purchase contracts between OSP and Boston Edison. In fourth quarter 2004, TransCanada closed a transaction with Boston Edison resulting in TransCanada assuming a 23.5 per cent share of the OSP power purchase contracts and recognized earnings from the effective date of April 1, 2004.

 

For fourth quarter 2004, Gas Transmission’s net earnings were $157 million compared to $160 million in fourth quarter 2003. The $3 million decrease was due to a $5 million reduction in earnings from Wholly-Owned Pipelines, partially offset by a $2 million increase in net earnings from the Other Gas Transmission businesses. The reduction in earnings from Wholly-Owned Pipelines was primarily due to a decline in the Canadian Mainline and the Alberta System net earnings. Regulatory decisions in 2004, as well as lower returns and investment bases, resulted in lower earnings for the Canadian Mainline and the Alberta System. These decreases were partially offset by net earnings of $14 million during the quarter from TransCanada’s investment in GTN which was acquired in November 2004. The increase in earnings from Other Gas Transmission was primarily due to higher earnings from CrossAlta as a result of favourable gas market storage conditions as well as higher earnings from Ventures LP. These increases were partially offset by the impact of a weaker U.S. dollar.

 

Net expenses, after tax, in the Corporate segment for the quarter ended December 31, 2004 were $3 million compared to $11 million for the corresponding period in 2003. The $8 million decrease in Corporate net expenses for the three months ended December 31, 2004 compared to the same period in 2003 was primarily due to the positive impacts of income tax and foreign exchange related items.

 

SHARE INFORMATION

 

As at March 1, 2005, TransCanada had 485,240,166 issued and outstanding common shares. In addition, there were approximately 10,694,000 outstanding options to purchase common shares, of which approximately 8,443,000 were exercisable as at March 1, 2005.

 

OTHER INFORMATION

 

Additional information relating to TransCanada, including the company’s Annual Information Form and continuous disclosure documents, is posted on SEDAR at www.sedar.com under TransCanada Corporation.

 

Other selected consolidated financial information for the years ended December 31, 2004, 2003, 2002, 2001 and 2000 is found under the heading “Five-Year Financial Highlights” on pages 108 and 109 of this Annual Report.

 

FORWARD-LOOKING INFORMATION

 

Certain information in this Management’s Discussion and Analysis is forward-looking and is subject to important risks and uncertainties. The results or events predicted in this information may differ from actual results or events. Factors which could cause actual results or events to differ materially from current expectations include, among other things, the ability of TransCanada to successfully implement its strategic initiatives and whether such strategic initiatives will yield the expected benefits, the availability and price of energy commodities, regulatory decisions, competitive factors in the pipeline and power industry sectors and the prevailing economic conditions in North America. For additional information on these and other factors, see the reports filed by TransCanada with Canadian securities regulators and with the SEC. TransCanada disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

 

65


 

GLOSSARY OF TERMS

 

2004 Application 2004 Canadian Mainline Tolls and Tariff Application

APG Aboriginal Pipeline Group

ATCO ATCO Pipelines

B.C. British Columbia

Bcf/d Billion cubic feet per day

Boston Edison Boston Edison Company

Bruce Power Bruce Power L.P.

Cameco Cameco Corporation

CAPP Canadian Association of Petroleum Producers

Cartier Wind Cartier Wind Energy

CBM Coalbed methane

CICA Canadian Institute of Chartered Accountants

CrossAlta CrossAlta Gas Storage & Services Ltd.

DBRS Dominion Bond Rating Service Limited

Disclosure controls Disclosure controls and procedures

EUB Alberta Energy and Utilities Board

FCA Federal Court of Appeal

FERC U.S. Federal Energy Regulatory Commission

Foothills Foothills Pipe Lines Ltd.

FT Firm transportation

FT-NR Non-renewable firm transportation

FT-RAM Firm transportation service enhancement

GAAP Generally accepted accounting principles

Gas Pacifico Gasoducto del Pacifico

GCOC Generic Cost of Capital

GRA General Rate Application

Great Lakes Great Lakes Gas Transmission System

GTN Gas Transmission Northwest System and the North Baja System, collectively

GUA Gas Utilities Act (Alberta)

GWh Gigawatt hours

Hydro-Québec Hydro-Québec Distribution

INNERGY INNERGY Holdings S.A.

Iroquois Iroquois Gas Transmission System

Keystone Keystone Pipeline

Km Kilometres

LNG Liquefied natural gas

Millennium Millennium Pipeline project

MMcf/d Million cubic feet per day

Moody’s Moody’s Investors Service

MW Megawatts

MWh Megawatt hour

NBJ North Bay Junction

NEB National Energy Board

Net earnings Net income from continuing operations

Northern Border Northern Border Pipeline

NPA Northern Pipeline Act of Canada

OM&A Operating, maintenance and administration

OPG Ontario Power Generation

OSP Ocean State Power

Paiton P.T. Paiton Energy Company

Portland Portland Natural Gas Transmission System

Portlands Energy Portlands Energy Centre L.P.

Power LP TransCanada Power, L.P.

PPAs Power purchase arrangements

ROE Rate of return on common equity

SEC U.S. Securities and Exchange Commission

Shell Shell US Gas & Power LLC

Simmons Simmons Pipeline System

TCPL TransCanada PipeLines Limited

TCPM TransCanada Power Marketing Limited

The Consortium The consortium that includes Cameco and BPC Generation Infrastructure Trust

TQM Trans Québec & Maritimes System

TransCanada or the company TransCanada Corporation

TransGas TransGas de Occidente S.A.

Tuscarora Tuscarora Gas Transmission System

U.S. United States

USGen USGen New England

Ventures LP TransCanada Pipeline Ventures Limited Partnership

Vermont Hydroelectric Vermont Hydroelectric Power Authority

WCSB Western Canada Sedimentary Basin

 

66


 

 

67


 

REPORT OF MANAGEMENT

 

The consolidated financial statements included in this Annual Report are the responsibility of Management and have been approved by the Board of Directors of the Company. These consolidated financial statements have been prepared by Management in accordance with generally accepted accounting principles (GAAP) in Canada and include amounts that are based on estimates and judgments. Financial information contained elsewhere in this Annual Report is consistent with the consolidated financial statements.

 

Management has prepared Management’s Discussion and Analysis which is based on the Company’s financial results prepared in accordance with Canadian GAAP. It compares the Company’s financial performance in 2004 to 2003 and should be read in conjunction with the consolidated financial statements and accompanying notes. In addition, significant changes between 2003 and 2002 are highlighted. Note 22 to the consolidated financial statements describes the impact on the consolidated financial statements of significant differences between Canadian and United States GAAP.

 

Management has developed and maintains a system of internal accounting controls, including a program of internal audits. Management believes that these controls provide reasonable assurance that financial records are reliable and form a proper basis for preparation of financial statements. The internal accounting control process includes Management’s communication to employees of policies which govern ethical business conduct.

 

The Board of Directors has appointed an Audit Committee consisting of unrelated, non-management directors which meets at least five times during the year with Management and independently with each of the internal and external auditors and as a group to review any significant accounting, internal control and auditing matters. The Audit Committee reviews the Annual Report, including the consolidated financial statements, before the consolidated financial statements are submitted to the Board of Directors for approval. The internal and external auditors have free access to the Audit Committee without obtaining prior Management approval.

 

With respect to the external auditors, KPMG LLP, the Audit Committee approves the terms of engagement and reviews the annual audit plan, the Auditors’ Report and results of the audit. It also recommends to the Board of Directors the firm of external auditors to be appointed by the shareholders.

 

The independent external auditors, KPMG LLP, have been appointed by the shareholders to express an opinion as to whether the consolidated financial statements present fairly, in all material respects, the Company’s financial position, results of operations and cash flows in accordance with Canadian GAAP. The report of KPMG LLP on page 69 outlines the scope of their examination and their opinion on the consolidated financial statements.

 

 

/s/ Harold N. Kvisle

 

 

/s/ Russell K. Girling

 

Harold N. Kvisle

 

Russell K. Girling

President and

 

Executive Vice-President, Corporate Development

Chief Executive Officer

 

and Chief Financial Officer

 

 

 

February 28, 2005

 

 

 

68


 

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 statements of consolidated income, consolidated retained earnings and consolidated cash flows for each of the years in the three-year period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

 

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

 

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2004 and 2003 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2004 in accordance with Canadian generally accepted accounting principles.

 

 

/s/ KPMG LLP

 

Chartered Accountants

Calgary, Canada

February 28, 2005

 

69


 

CONSOLIDATED INCOME

 

Year ended December 31 (millions of dollars except per share amounts)

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

Revenues

 

5,107

 

5,357

 

5,214

 

 

 

 

 

 

 

 

 

Operating Expenses

 

 

 

 

 

 

 

Cost of sales

 

539

 

692

 

627

 

Other costs and expenses

 

1,635

 

1,682

 

1,546

 

Depreciation

 

945

 

914

 

848

 

 

 

3,119

 

3,288

 

3,021

 

 

 

 

 

 

 

 

 

Operating Income

 

1,988

 

2,069

 

2,193

 

 

 

 

 

 

 

 

 

Other Expenses/(Income)

 

 

 

 

 

 

 

Financial charges (Note 9)

 

810

 

821

 

867

 

Financial charges of joint ventures

 

60

 

77

 

90

 

Equity income (Note 7)

 

(171

)

(165

)

(33

)

Interest income and other

 

(65

)

(60

)

(53

)

Gains related to Power LP (Note 8)

 

(197

)

—

 

—

 

 

 

437

 

673

 

871

 

Income from Continuing Operations before Income Taxes and
Non-Controlling Interests

 

1,551

 

1,396

 

1,322

 

Income Taxes (Note 15)

 

 

 

 

 

 

 

Current

 

431

 

305

 

270

 

Future

 

77

 

230

 

247

 

 

 

508

 

535

 

517

 

Non-Controlling Interests (Note 12)

 

63

 

60

 

58

 

Net Income from Continuing Operations

 

980

 

801

 

747

 

Net Income from Discontinued Operations (Note 21)

 

52

 

50

 

—

 

Net Income

 

1,032

 

851

 

747

 

 

 

 

 

 

 

 

 

Net Income Per Share (Note 13)

 

 

 

 

 

 

 

Basic

 

 

 

 

 

 

 

Continuing operations

 

$

2.02

 

$

1.66

 

$

1.56

 

Discontinued operations

 

0.11

 

0.10

 

—

 

 

 

$

 2.13

 

$

 1.76

 

$

 1.56

 

Diluted

 

 

 

 

 

 

 

Continuing operations

 

$

 2.01

 

$

 1.66

 

$

 1.55

 

Discontinued 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.

 

70


 

CONSOLIDATED CASH FLOWS

 

Year ended December 31 (millions of dollars)

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

Cash Generated from Operations

 

 

 

 

 

 

 

Net income from continuing operations

 

980

 

801

 

747

 

Depreciation

 

945

 

914

 

848

 

Future income taxes

 

77

 

230

 

247

 

Gains related to Power LP

 

(197

)

—

 

—

 

Equity income in excess of distributions received (Note 7)

 

(123

)

(119

)

(6

)

Non-controlling interests

 

63

 

60

 

58

 

Pension funding in excess of expense

 

(29

)

(65

)

(33

)

Other

 

(42

)

(11

)

(34

)

Funds generated from continuing operations

 

1,674

 

1,810

 

1,827

 

Decrease in operating working capital (Note 19)

 

34

 

112

 

33

 

Net cash provided by continuing operations

 

1,708

 

1,922

 

1,860

 

Net cash (used in)/provided by discontinued operations

 

(6

)

(17

)

59

 

 

 

1,702

 

1,905

 

1,919

 

 

 

 

 

 

 

 

 

Investing Activities

 

 

 

 

 

 

 

Capital expenditures

 

(476

)

(391

)

(599

)

Acquisitions, net of cash acquired (Note 8)

 

(1,516

)

(570

)

(228

)

Disposition of assets (Note 8)

 

410

 

—

 

—

 

Deferred amounts and other

 

(24

)

(138

)

(112

)

Net cash used in investing activities

 

(1,606

)

(1,099

)

(939

)

 

 

 

 

 

 

 

 

Financing Activities

 

 

 

 

 

 

 

Dividends and preferred securities charges

 

(623

)

(588

)

(546

)

Notes payable issued/(repaid), net

 

179

 

(62

)

(46

)

Long-term debt issued

 

1,042

 

930

 

—

 

Reduction of long-term debt

 

(997

)

(744

)

(486

)

Non-recourse debt of joint ventures issued

 

233

 

60

 

44

 

Reduction of non-recourse debt of joint ventures

 

(113

)

(71

)

(80

)

Partnership units of joint ventures issued

 

88

 

—

 

—

 

Common shares issued

 

32

 

65

 

50

 

Redemption 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 Investments

 

 

 

 

 

 

 

Beginning of year

 

338

 

212

 

299

 

 

 

 

 

 

 

 

 

Cash and Short-Term Investments

 

 

 

 

 

 

 

End of year

 

188

 

338

 

212

 

 

The accompanying notes to the consolidated financial statements are an integral part of these statements.

 

71


 

CONSOLIDATED BALANCE SHEET

 

December 31 (millions of dollars)

 

2004

 

2003

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

Current Assets

 

 

 

 

 

Cash and short-term investments

 

188

 

338

 

Accounts receivable

 

627

 

605

 

Inventories

 

174

 

165

 

Other

 

120

 

88

 

 

 

1,109

 

1,196

 

Long-Term Investments (Note 7)

 

840

 

733

 

Plant, Property and Equipment (Notes 4, 9 and 10)

 

18,704

 

17,415

 

Other Assets (Note 5)

 

1,477

 

1,357

 

 

 

22,130

 

20,701

 

 

 

 

 

 

 

LIABILITIES AND SHAREHOLDERS’ EQUITY

 

 

 

 

 

Current Liabilities

 

 

 

 

 

Notes payable (Note 16)

 

546

 

367

 

Accounts payable

 

1,135

 

1,087

 

Accrued interest

 

214

 

208

 

Current portion of long-term debt (Note 9)

 

766

 

550

 

Current portion of non-recourse debt of joint ventures (Note 10)

 

83

 

19

 

 

 

2,744

 

2,231

 

Deferred Amounts (Note 11)

 

666

 

561

 

Long-Term Debt (Note 9)

 

9,713

 

9,465

 

Future Income Taxes (Note 15)

 

509

 

427

 

Non-Recourse Debt of Joint Ventures (Note 10)

 

779

 

761

 

Preferred Securities (Note 12)

 

19

 

22

 

 

 

14,430

 

13,467

 

 

 

 

 

 

 

Non-Controlling Interests (Note 12)

 

1,135

 

1,143

 

 

 

 

 

 

 

Shareholders’ Equity

 

 

 

 

 

Common shares (Note 13)

 

4,711

 

4,679

 

Contributed surplus

 

270

 

267

 

Retained earnings

 

1,655

 

1,185

 

Foreign exchange adjustment (Note 14)

 

(71

)

(40

)

 

 

6,565

 

6,091

 

Commitments, 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. Schaefer

 

Harold N. Kvisle

 

Harry G. Schaefer

Director

 

Director

 

72


 

CONSOLIDATED RETAINED EARNINGS

 

Year ended December 31 (millions of dollars)

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

Balance at beginning of year

 

1,185

 

854

 

586

 

Net income

 

1,032

 

851

 

747

 

Common 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.

 

73


 

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 Presentation  Pursuant 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.

 

74


 

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.

 

Regulation  The Canadian Mainline, the BC System, the Foothills System, and Trans Québec & Maritimes Pipeline Inc. (Trans Québec & Maritimes) are subject to the authority of the National Energy Board (NEB) and the Alberta System is regulated by the Alberta Energy and Utilities Board (EUB). These Canadian natural gas transmission operations are regulated with respect to the determination of revenues, tolls, construction and operations. The NEB approved interim tolls for 2004 for the Canadian Mainline. The tolls will remain interim pending a decision on Phase II of the 2004 Tolls and Tariff Application, which will address capital structure, for the Canadian Mainline. Any adjustments to the interim tolls will be recorded in accordance with the NEB decision. The Gas Transmission Northwest System, the North Baja System and the other natural gas pipelines in the U.S. are subject to the authority of the Federal Energy Regulatory Commission (FERC). In order to appropriately reflect the economic impact of the regulators’ decisions regarding the Company’s revenues and tolls, and to thereby achieve a proper matching of revenues and expenses, the timing of recognition of certain revenues and expenses in these regulated businesses may differ from that otherwise expected under GAAP.

 

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

 

Inventories  Inventories are carried at the lower of average cost or net realizable value and primarily consist of materials and supplies including spare parts and storage gas.

 

Plant, Property and Equipment

 

Gas Transmission  Plant, property and equipment of natural gas transmission operations are carried at cost. Depreciation is calculated on a straight-line basis. Pipeline and compression equipment are depreciated at annual rates ranging from two to six per cent and metering and other plant are depreciated at various rates. An allowance for funds used during construction, using the rate of return on rate base approved by the regulators, is capitalized and included in the cost of gas transmission plant.

 

Power  Plant, property and equipment in the Power business are recorded at cost and depreciated on a straight-line basis over estimated service lives at average annual rates generally ranging from two to four per cent. The cost of major overhauls of equipment is capitalized and depreciated over the estimated service lives. Interest is capitalized on capital projects.

 

Corporate  Corporate plant, property and equipment are recorded at cost and depreciated on a straight-line basis over estimated useful lives at average annual rates ranging from three to 20 per cent.

 

Power Purchase Arrangements  Power purchase arrangements (PPAs) are long-term contracts to purchase or sell power on a predetermined basis. The initial payments for PPAs acquired by 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 Options  TransCanada’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.

 

75


 

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

 

Canadian income taxes are not provided on the unremitted earnings of foreign investments as the Company does not intend to repatriate these earnings in the foreseeable future.

 

Foreign Currency Translation  Most of the Company’s foreign operations are self-sustaining and are translated into Canadian dollars using the current rate method. Under this method, assets and liabilities are translated at period end exchange rates and items included in the statements of consolidated income, consolidated retained earnings and consolidated cash flows are translated at the exchange rates in effect at the time of the transaction. Translation adjustments are reflected in the foreign exchange adjustment in Shareholders’ Equity.

 

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

 

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

 

Employee Benefit and Other Plans  The Company sponsors defined benefit pension plans (DB Plans). The cost of defined benefit pensions and other post-employment benefits earned by employees is actuarially determined using the projected benefit method pro-rated on service and Management’s best estimate of expected plan investment performance, salary escalation, retirement ages of employees and expected health care costs. Pension plan assets are measured at fair value. The expected return on pension plan assets is determined using market-related values based on a five-year moving average value for all plan assets. Adjustments arising from plan amendments are amortized on a straight-line basis over the average remaining service period of employees active at the date of amendment. The excess of the net actuarial gain or loss over 10 per cent of the greater of the benefit obligation and the fair value of plan assets is amortized over the average remaining service period of the active employees. When the restructuring of a benefit plan gives rise to both a curtailment and a settlement, the curtailment is accounted for prior to the settlement. The Company previously sponsored two additional plans, a defined contribution plan and a combination of the defined benefit and defined contribution plans, which were effectively terminated at December 31, 2002.

 

76


 

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 Obligations  Effective January 1, 2004, the Company adopted the new standard of the Canadian Institute of Chartered Accountants (CICA) Handbook Section “Asset Retirement Obligations”, which addresses financial accounting and reporting for obligations associated with asset retirement costs. This section requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset. The liability is accreted at the end of each period through charges to operating expenses. This accounting change was applied retroactively with restatement of prior periods.

 

The plant, property and equipment of the regulated natural gas transmission operations consists primarily of underground pipelines and above ground compression equipment and other facilities. No amount has been recorded for asset retirement obligations relating to these assets as it is not possible to make a reasonable estimate of the fair value of the liability due to the indeterminate timing and scope of the asset retirements. Management believes it is reasonable to assume that all retirement costs associated with the regulated pipelines will be recovered through tolls in future periods. For Gas Transmission, excluding regulated natural gas transmission operations, the impact of this accounting change resulted in an increase of $2 million in plant, property and equipment and in the estimated fair value of the liability as at January 1, 2003 and December 31, 2003.

 

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 Relationships  Effective January 1, 2004, the Company adopted the provisions of the CICA’s new Accounting Guideline “Hedging Relationships” that specifies the circumstances in which hedge accounting is appropriate, including the identification, documentation, designation and effectiveness of hedges, and the discontinuance of hedge accounting. The adoption of the new guideline, which TransCanada applied prospectively, had no significant impact on net income for the year ended December 31, 2004.

 

Generally Accepted Accounting Principles  Effective January 1, 2004, the Company adopted the new standard of the CICA Handbook Section “Generally Accepted Accounting Principles” that defines primary sources of GAAP and the other sources that need to be considered in the application of GAAP. The new standard eliminates the ability to rely on industry practice to support a particular accounting policy and provides an exemption for rate-regulated operations.

 

This accounting change was applied prospectively and there was no impact on net income in the year ended December 31, 2004. In prior years, in accordance with industry practice, certain assets and liabilities related to the Company’s regulated activities, and offsetting deferral accounts, were not recognized on the balance sheet. The impact of the change on the consolidated balance sheet as at January 1, 2004 is as follows.

 

(millions of dollars)

 

Increase/(Decrease)

 

 

 

 

 

Other assets

 

153

 

 

 

 

 

Deferred amounts

 

80

 

Long-term debt

 

76

 

Preferred securities

 

(3

)

Total liabilities

 

153

 

 

77


 

NOTE 3  Segmented Information

 

Net Income/(Loss) (1)

 

Year ended December 31, 2004 (millions of dollars)

 

Gas
Transmission

 

Power

 

Corporate

 

Total

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

3,917

 

1,190

 

—

 

5,107

 

Cost of sales (2)

 

—

 

(539

)

—

 

(539

)

Other costs and expenses

 

(1,225

)

(407

)

(3

)

(1,635

)

Depreciation

 

(873

)

(72

)

—

 

(945

)

Operating income/(loss)

 

1,819

 

172

 

(3

)

1,988

 

Financial charges and non-controlling interests

 

(785

)

(9

)

(79

)

(873

)

Financial charges of joint ventures

 

(56

)

(4

)

—

 

(60

)

Equity income

 

41

 

130

 

—

 

171

 

Interest income and other

 

14

 

14

 

37

 

65

 

Gains related to Power LP

 

—

 

197

 

—

 

197

 

Income taxes

 

(447

)

(104

)

43

 

(508

)

Continuing operations

 

586

 

396

 

(2

)

980

 

Discontinued operations

 

 

 

 

 

 

 

52

 

Net Income

 

 

 

 

 

 

 

1,032

 

 

 

 

 

 

 

 

 

 

 

Year ended December 31, 2003 (millions of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

3,956

 

1,401

 

—

 

5,357

 

Cost of sales (2)

 

—

 

(692

)

—

 

(692

)

Other costs and expenses

 

(1,270

)

(405

)

(7

)

(1,682

)

Depreciation

 

(831

)

(82

)

(1

)

(914

)

Operating income/(loss)

 

1,855

 

222

 

(8

)

2,069

 

Financial charges and non-controlling interests

 

(781

)

(11

)

(89

)

(881

)

Financial charges of joint ventures

 

(76

)

(1

)

—

 

(77

)

Equity income

 

66

 

99

 

—

 

165

 

Interest income and other

 

17

 

14

 

29

 

60

 

Income taxes

 

(459

)

(103

)

27

 

(535

)

Continuing operations

 

622

 

220

 

(41

)

801

 

Discontinued operations

 

 

 

 

 

 

 

50

 

Net Income

 

 

 

 

 

 

 

851

 

 

 

 

 

 

 

 

 

 

 

Year ended December 31, 2002 (millions of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

3,921

 

1,293

 

—

 

5,214

 

Cost of sales (2)

 

—

 

(627

)

—

 

(627

)

Other costs and expenses

 

(1,166

)

(371

)

(9

)

(1,546

)

Depreciation

 

(783

)

(65

)

—

 

(848

)

Operating income/(loss)

 

1,972

 

230

 

(9

)

2,193

 

Financial charges and non-controlling interests

 

(821

)

(13

)

(91

)

(925

)

Financial charges of joint ventures

 

(90

)

—

 

—

 

(90

)

Equity income

 

33

 

—

 

—

 

33

 

Interest income and other

 

17

 

13

 

23

 

53

 

Income taxes

 

(458

)

(84

)

25

 

(517

)

Continuing operations

 

653

 

146

 

(52

)

747

 

Discontinued operations

 

 

 

 

 

 

 

—

 

Net Income

 

 

 

 

 

 

 

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.

 

78


 

 

Total Assets

 

December 31 (millions of dollars)

 

2004

 

2003

 

 

 

 

 

 

 

Gas Transmission

 

18,428

 

17,064

 

Power

 

2,802

 

2,753

 

Corporate

 

893

 

873

 

Continuing operations

 

22,123

 

20,690

 

Discontinued operations

 

7

 

11

 

 

 

22,130

 

20,701

 

 

Geographic Information

 

Year ended December 31 (millions of dollars)

 

2004

 

2003

 

2002 (4)

 

 

 

 

 

 

 

 

 

Revenues (3)

 

 

 

 

 

 

 

Canada – domestic

 

3,147

 

3,257

 

2,731

 

Canada – export

 

1,261

 

1,293

 

1,641

 

United States

 

699

 

807

 

842

 

 

 

5,107

 

5,357

 

5,214

 

 

(3)   Revenues are attributed to countries based on country of origin of product or service.

(4)   Canada – domestic revenues were reduced in 2002 as a result of transportation service credits of $662 million. These services were discontinued in 2003.

 

Plant, Property and Equipment

 

December 31 (millions of dollars)

 

2004

 

2003

 

 

 

 

 

 

 

Canada

 

14,757

 

15,156

 

United States

 

3,947

 

2,259

 

 

 

18,704

 

17,415

 

 

Capital Expenditures

 

Year ended December 31 (millions of dollars)

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

Gas Transmission

 

187

 

256

 

382

 

Power

 

285

 

132

 

193

 

Corporate and Other

 

4

 

3

 

24

 

 

 

476

 

391

 

599

 

 

79


 

NOTE 4  Plant, Property and Equipment

 

 

 

2004

 

2003

 

December 31 (millions of dollars)

 

Cost

 

Accumulated
Depreciation

 

Net
Book Value

 

Cost

 

Accumulated
Depreciation

 

Net
Book Value

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Transmission

 

 

 

 

 

 

 

 

 

 

 

 

 

Canadian Mainline

 

 

 

 

 

 

 

 

 

 

 

 

 

Pipeline

 

8,695

 

3,421

 

5,274

 

8,683

 

3,176

 

5,507

 

Compression

 

3,322

 

947

 

2,375

 

3,318

 

832

 

2,486

 

Metering and other

 

366

 

125

 

241

 

404

 

132

 

272

 

 

 

12,383

 

4,493

 

7,890

 

12,405

 

4,140

 

8,265

 

Under construction

 

16

 

—

 

16

 

12

 

—

 

12

 

 

 

12,399

 

4,493

 

7,906

 

12,417

 

4,140

 

8,277

 

Alberta System

 

 

 

 

 

 

 

 

 

 

 

 

 

Pipeline

 

4,978

 

2,055

 

2,923

 

4,934

 

1,908

 

3,026

 

Compression

 

1,496

 

599

 

897

 

1,507

 

549

 

958

 

Metering and other

 

861

 

262

 

599

 

862

 

211

 

651

 

 

 

7,335

 

2,916

 

4,419

 

7,303

 

2,668

 

4,635

 

Under construction

 

20

 

—

 

20

 

13

 

—

 

13

 

 

 

7,355

 

2,916

 

4,439

 

7,316

 

2,668

 

4,648

 

GTN (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

Pipeline

 

1,131

 

9

 

1,122

 

 

 

 

 

 

 

Compression

 

726

 

2

 

724

 

 

 

 

 

 

 

Metering and other

 

187

 

1

 

186

 

 

 

 

 

 

 

 

 

2,044

 

12

 

2,032

 

 

 

 

 

 

 

Under construction

 

17

 

—

 

17

 

 

 

 

 

 

 

 

 

2,061

 

12

 

2,049

 

 

 

 

 

 

 

Foothills System

 

 

 

 

 

 

 

 

 

 

 

 

 

Pipeline

 

815

 

346

 

469

 

834

 

317

 

517

 

Compression

 

373

 

114

 

259

 

378

 

99

 

279

 

Metering and other

 

78

 

35

 

43

 

60

 

35

 

25

 

 

 

1,266

 

495

 

771

 

1,272

 

451

 

821

 

Joint Ventures and other

 

3,213

 

1,053

 

2,160

 

3,361

 

1,052

 

2,309

 

 

 

26,294

 

8,969

 

17,325

 

24,366

 

8,311

 

16,055

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Power (2)

 

 

 

 

 

 

 

 

 

 

 

 

 

Power generation facilities

 

1,397

 

375

 

1,022

 

1,439

 

381

 

1,058

 

Other

 

77

 

45

 

32

 

84

 

41

 

43

 

 

 

1,474

 

420

 

1,054

 

1,523

 

422

 

1,101

 

Under construction

 

288

 

—

 

288

 

209

 

—

 

209

 

 

 

1,762

 

420

 

1,342

 

1,732

 

422

 

1,310

 

Corporate

 

124

 

87

 

37

 

122

 

72

 

50

 

 

 

28,180

 

9,476

 

18,704

 

26,220

 

8,805

 

17,415

 

 

(1)     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.

 

80


 

NOTE 5  Other Assets

 

December 31 (millions of dollars)

 

2004

 

2003

 

 

 

 

 

 

 

Derivative contracts

 

253

 

118

 

PPAs – Canada (1)

 

274

 

278

 

PPAs – U.S. (1)

 

98

 

248

 

Pension and other benefit plans

 

209

 

201

 

Regulatory deferrals

 

199

 

212

 

Loans and advances (2)

 

135

 

111

 

Goodwill

 

58

 

—

 

Other

 

251

 

189

 

 

 

1,477

 

1,357

 

 

(1)     The following amounts related to the PPAs are included in the consolidated financial statements.

 

 

 

2004

 

2003

 

December 31 (millions of dollars)

 

Cost

 

Accumulated
Amortization

 

Net
Book Value

 

Cost

 

Accumulated
Amortization

 

Net
Book Value

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

PPAs – Canada

 

345

 

71

 

274

 

329

 

51

 

278

 

PPAs – U.S.

 

102

 

4

 

98

 

276

 

28

 

248

 

 

The aggregate amortization expense with respect to the PPAs was $24 million for the year ended December 31, 2004 (2003 – $37 million; 2002 – $28 million). The amortization expense with respect to the Company’s PPAs approximate: 2005 – $26 million; 2006 – $26 million; 2007 – $26 million; 2008 – $26 million; and 2009 – $26 million. In April 2004, the Company disposed of all its PPAs – U.S. to Power LP and, as a result of its joint venture investment in Power LP, recorded US$74 million of PPAs – U.S. In 2004, TransCanada also recorded $16 million of PPAs – Canada.

 

(2)   Includes a $75 million unsecured note receivable from Bruce Power L.P. (Bruce Power) bearing interest at 10.5 per cent per annum, due February 14, 2008.

 

NOTE 6 Joint Venture Investments

 

 

 

 

 

TransCanada’s Proportionate Share

 

 

 

 

 

Income Before Income Taxes
Year ended December 31

 

Net Assets
December 31

 

(millions of dollars)

 

Ownership Interest

 

2004

 

2003

 

2002

 

2004

 

2003

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Transmission

 

 

 

 

 

 

 

 

 

 

 

 

 

Great Lakes

 

50.0

%(1)

86

 

81

 

102

 

379

 

419

 

Iroquois

 

41.0

%(1)

28

 

31

 

30

 

175

 

169

 

TC PipeLines, LP

 

33.4

%

22

 

21

 

24

 

124

 

130

 

Trans Québec & Maritimes

 

50.0

%

13

 

14

 

13

 

75

 

77

 

CrossAlta

 

60.0

%(1)

20

 

11

 

21

 

24

 

25

 

Foothills

 

 

   (2)

—

 

19

 

29

 

—

 

—

 

Other

 

Various

 

6

 

7

 

7

 

27

 

22

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Power

 

 

 

 

 

 

 

 

 

 

 

 

 

Power LP

 

30.6

%(3)

32

 

25

 

26

 

289

 

234

 

ASTC Power Partnership

 

50.0

%(4)

—

 

—

 

—

 

93

 

99

 

 

 

 

 

207

 

209

 

252

 

1,186

 

1,175

 

 

(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).

 

81


 

Summarized Financial Information of Joint Ventures

 

Year ended December 31 (millions of dollars)

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

Income

 

 

 

 

 

 

 

Revenues

 

559

 

623

 

680

 

Other costs and expenses

 

(238

)

(275

)

(251

)

Depreciation

 

(88

)

(96

)

(119

)

Financial charges and other

 

(26

)

(43

)

(58

)

Proportionate share of income before income taxes of joint ventures

 

207

 

209

 

252

 

 

 

 

 

 

 

 

 

Year ended December 31 (millions of dollars)

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

Cash Flows

 

 

 

 

 

 

 

Operations

 

269

 

272

 

323

 

Investing activities

 

(179

)

(114

)

(124

)

Financing activities

 

(76

)

(156

)

(210

)

Effect of foreign exchange rate changes on cash and short-term investments

 

(5

)

(10

)

(1

)

Proportionate share of increase/(decrease) in cash and short-term investments of joint ventures

 

9

 

(8

)

(12

)

 

 

 

 

 

 

 

 

December 31 (millions of dollars)

 

2004

 

2003

 

 

 

 

 

 

 

 

 

 

 

Balance Sheet

 

 

 

 

 

 

 

Cash and short-term investments

 

64

 

55

 

 

 

Other current assets

 

133

 

106

 

 

 

Long-term investments

 

105

 

118

 

 

 

Plant, property and equipment

 

1,644

 

1,693

 

 

 

Other assets and deferred amounts (net)

 

221

 

109

 

 

 

Current liabilities

 

(153

)

(94

)

 

 

Non-recourse debt

 

(779

)

(761

)

 

 

Future income taxes

 

(49

)

(51

)

 

 

Proportionate share of net assets of joint ventures

 

1,186

 

1,175

 

 

 

 

82


 

NOTE 7  Long-Term Investments

 

 

 

 

 

TransCanada’s Share

 

 

 

 

 

Distributions From
Equity Investments
Year ended December 31

 

Income From
Equity Investments
Year ended December 31

 

Equity Investments
December 31

 

(millions of dollars)

 

Ownership Interest

 

2004

 

2003

 

2002

 

2004

 

2003

 

2002

 

2004

 

2003

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Power

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Bruce Power

 

31.6

%

—

 

—

 

—

 

130

 

99

 

—

 

642

 

513

 

Gas Transmission

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Northern Border

 

10.0

%(1)

27

 

22

 

26

 

23

 

22

 

25

 

91

 

103

 

TransGas de Occidente S.A.

 

46.5

%

8

 

8

 

—

 

11

 

27

 

5

 

78

 

80

 

Portland

 

61.7

%(2)

—

 

10

 

—

 

—

 

14

 

2

 

—

 

—

 

Other

 

Various

 

13

 

6

 

1

 

7

 

3

 

1

 

29

 

37

 

 

 

 

 

48

 

46

 

27

 

171

 

165

 

33

 

840

 

733

 

 

(1)     The Northern Border equity investment effective ownership interest of 10.0 per cent is the result of the Company holding a 33.4 per cent interest in TC PipeLines, LP, which holds a 30.0 per cent interest in Northern Border Pipeline Company (Northern Border).

(2)     In September 2003, the Company increased its ownership interest in Portland to 43.4 per cent from 33.3 per cent. In December 2003, the Company increased its ownership interest to 61.7 per cent and the investment was fully consolidated subsequent to that date.

 

Consolidated retained earnings at December 31, 2004 include undistributed earnings from these equity investments of $285 million (2003 – $166 million).

 

NOTE 8  Acquisitions and Dispositions

 

Acquisitions

 

GTN  On November 1, 2004, 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

 

45

 

Plant, property and equipment

 

1,712

 

Other non-current assets

 

30

 

Goodwill

 

48

 

Current liabilities

 

(54

)

Long-term debt

 

(528

)

Other non-current liabilities

 

(51

)

 

 

1,202

 

 

Goodwill, which is attributable to the North Baja System, will be re-evaluated on an annual basis for impairment. Factors that contributed to goodwill include opportunities for expansion, a strong competitive position, strong demand for gas 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.

 

83


 

Bruce Power  On February 14, 2003, the Company acquired a 31.6 per cent interest in Bruce Power for $409 million, including closing adjustments. As part of the acquisition, the Company also funded a one-third share ($75 million) of a $225 million accelerated deferred rent payment made by Bruce Power to Ontario Power Generation. The resulting note receivable from Bruce Power is recorded in other assets.

 

The purchase price of the Company’s 31.6 per cent interest in Bruce Power was allocated as follows.

 

Purchase Price Allocation

 

(millions of dollars)

 

 

 

 

 

 

 

Net book value of assets acquired

 

281

 

Capital lease

 

301

 

Power sales agreements

 

(131

)

Pension liability and other

 

(42

)

 

 

409

 

 

The amount allocated to the investment in Bruce Power includes a purchase price allocation of $301 million to the capital lease of the Bruce Power plant which is being amortized on a straight-line basis over the lease term which extends to 2018, resulting in an annual amortization expense of $19 million. The amount allocated to the power sales agreements is being amortized to income over the remaining term of the underlying sales contracts. The amortization of the fair value allocated to these contracts is: 2003 – $38 million; 2004 – $37 million; 2005 – $25 million; 2006 – $29 million; and 2007 – $2 million.

 

Dispositions

 

Power LP  On April 30, 2004, 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.

 

84


 

NOTE 9  Long-Term Debt

 

 

 

 

 

2004

 

2003

 

 

 

Maturity
Dates

 

Outstanding
December 31 (1)

 

Weighted
Average
Interest
Rate (2)

 

Outstanding
December 31 (1)

 

Weighted
Average
Interest
Rate (2)

 

 

 

 

 

 

 

 

 

 

 

 

 

Canadian Mainline (3)

 

 

 

 

 

 

 

 

 

 

 

First Mortgage Pipe Line Bonds

 

 

 

 

 

 

 

 

 

 

 

Pounds Sterling (2004 and 2003 – £25)

 

2007

 

58

 

16.5

%

58

 

16.5

%

Debentures

 

 

 

 

 

 

 

 

 

 

 

Canadian dollars

 

2008 to 2020

 

1,354

 

10.9

%

1,354

 

10.9

%

U.S. dollars (2004 – US$600; 2003 – US$800)

 

2012 to 2021

 

722

 

9.5

%

1,034

 

9.2

%

Medium-Term Notes

 

 

 

 

 

 

 

 

 

 

 

Canadian dollars

 

2005 to 2031

 

2,167

 

6.9

%

2,312

 

6.9

%

U.S. dollars (2004 and 2003 – US$120)

 

2010

 

144

 

6.1

%

155

 

6.1

%

Foreign exchange differential recoverable through the tollmaking process (8)

 

 

 

—

 

 

 

(60

)

 

 

 

 

 

 

4,445

 

 

 

4,853

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Alberta System (4)

 

 

 

 

 

 

 

 

 

 

 

Debentures and Notes

 

 

 

 

 

 

 

 

 

 

 

Canadian dollars

 

2007 to 2024

 

607

 

11.6

%

627

 

11.6

%

U.S. dollars (2004 – US$375; 2003 – US$500)

 

2012 to 2023

 

451

 

8.2

%

646

 

8.3

%

Medium-Term Notes

 

 

 

 

 

 

 

 

 

 

 

Canadian dollars

 

2005 to 2030

 

767

 

7.4

%

767

 

7.4

%

U.S. dollars (2004 and 2003 – US$233)

 

2026 to 2029

 

280

 

7.7

%

301

 

7.7

%

Foreign exchange differential recoverable through the tollmaking process (8)

 

 

 

—

 

 

 

(16

)

 

 

 

 

 

 

2,105

 

 

 

2,325

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

GTN (5)

 

 

 

 

 

 

 

 

 

 

 

Unsecured Debentures and Notes (2004 – US$525)

 

2005 to 2025

 

632

 

7.2

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Foothills System (3)

 

 

 

 

 

 

 

 

 

 

 

Senior Secured Notes

 

 

 

—

 

 

 

80

 

4.3

%

Senior Unsecured Notes

 

2009 to 2014

 

400

 

4.9

%

300

 

4.7

%

 

 

 

 

400

 

 

 

380

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Portland (6)

 

 

 

 

 

 

 

 

 

 

 

Senior Secured Notes

 

 

 

 

 

 

 

 

 

 

 

U.S. dollars (2004 – US$256; 2003 – US$271)

 

2018

 

308

 

5.9

%

350

 

5.9

%

 

 

 

 

 

 

 

 

 

 

 

 

Other

 

 

 

 

 

 

 

 

 

 

 

Medium-Term Notes (3)

 

 

 

 

 

 

 

 

 

 

 

Canadian dollars

 

2005 to 2030

 

592

 

6.2

%

592

 

6.2

%

U.S. dollars (2004 – US$521; 2003 – US$665)

 

2006 to 2025

 

627

 

6.9

%

859

 

6.8

%

Subordinated Debentures (3)

 

 

 

 

 

 

 

 

 

 

 

U.S. dollars (2004 and 2003 – US$57)

 

2006

 

68

 

9.1

%

74

 

9.1

%

Unsecured Loans, Debentures and Notes (7)

 

 

 

 

 

 

 

 

 

 

 

U.S. dollars (2004 – US$1,082; 2003 – US$446)

 

2005 to 2034

 

1,302

 

5.1

%

582

 

4.9

%

 

 

 

 

2,589

 

 

 

2,107

 

 

 

 

 

 

 

10,479

 

 

 

10,015

 

 

 

Less: Current Portion of Long-Term Debt

 

 

 

766

 

 

 

550

 

 

 

 

 

 

 

9,713

 

 

 

9,465

 

 

 

 

85


 

(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 Repayments Principal repayments on the long-term debt of the Company approximate: 2005 – $766 million; 2006 – $387 million; 2007 – $615 million; 2008 – $545 million; and 2009 – $753 million.

 

Debt Shelf Programs At December 31, 2004, $1.5 billion of medium-term note debentures could be issued under a base shelf program in Canada and US$1 billion of debt securities could be issued under a debt shelf program in the U.S. In January 2005, the Company issued $300 million of 12-year medium-term notes bearing interest of 5.1 per cent under the Canadian base shelf program.

 

CANADIAN MAINLINE

 

First Mortgage Pipe Line Bonds The Deed of Trust and Mortgage securing the Company’s First Mortgage Pipe Line Bonds limits the specific and floating charges to those assets comprising the present and future Canadian Mainline and TCPL’s present and future gas transportation contracts.

 

ALBERTA SYSTEM

 

Debentures Debentures amounting to $225 million have retraction provisions which entitle the holders to require redemption of up to 8 per cent of the then outstanding principal plus accrued and unpaid interest on specified repayment dates. No redemptions have been made to December 31, 2004.

 

Medium-Term Notes Medium-term notes amounting to $50 million have a provision entitling the holders to extend the maturity of the medium-term notes from the initial repayment date of 2007 to 2027. If extended, the interest rate would increase from 6.1 per cent to 7.0 per cent and the medium-term notes would become redeemable at the option of the Company.

 

GAS TRANSMISSION NORTHWEST CORPORATION

 

Senior Unsecured Notes Senior unsecured notes amounting to US$250 million are redeemable by the Company at any time on or after June 1, 2005.

 

OTHER

 

Medium-Term Notes Medium-term notes amounting to $150 million have retraction provisions which entitle the holders to require redemption of the principal plus accrued and unpaid interest in 2005.

 

Financial Charges

 

Year ended December 31 (millions of dollars)

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

Interest on long-term debt

 

805

 

801

 

850

 

Regulatory deferrals and amortizations

 

(31

)

(14

)

(17

)

Short-term interest and other financial charges

 

36

 

34

 

34

 

 

 

810

 

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).

 

86


 

NOTE 10 Non-Recourse Debt of Joint Ventures

 

 

 

 

 

2004

 

2003

 

 

 

Maturity
Dates

 

Outstanding
December 31 (1)

 

Weighted
Average
Interest
Rate (2)

 

Outstanding
December 31 (1)

 

Weighted
Average
Interest
Rate (2)

 

Great Lakes

 

 

 

 

 

 

 

 

 

 

 

Senior Unsecured Notes

 

 

 

 

 

 

 

 

 

 

 

(2004 – US$235; 2003 – US$240)

 

2011 to 2030

 

283

 

7.9

%

310

 

7.9

%

Iroquois

 

 

 

 

 

 

 

 

 

 

 

Senior Unsecured Notes

 

 

 

 

 

 

 

 

 

 

 

(2004 and 2003 – US$151)

 

2010 to 2027

 

182

 

7.5

%

196

 

7.5

%

Bank Loan

 

 

 

 

 

 

 

 

 

 

 

(2004 – US$36; 2003 – US$43)

 

2008

 

43

 

2.5

%

56

 

2.3

%

Trans Québec & Maritimes

 

 

 

 

 

 

 

 

 

 

 

Bonds

 

2005 to 2010

 

143

 

7.3

%

143

 

7.3

%

Term Loan

 

2006

 

29

 

3.2

%

34

 

3.5

%

TransCanada Power, L.P.

 

 

 

 

 

 

 

 

 

 

 

Senior Unsecured Notes (2004 – US$58)

 

2014

 

70

 

5.9

%

—

 

 

 

Credit Facility

 

2009

 

64

 

3.2

%

—

 

 

 

Term Loan

 

2010

 

2

 

11.3

%

—

 

 

 

Other

 

2005 to 2012

 

46

 

4.9

%

41

 

5.4

%

 

 

 

 

862

 

 

 

780

 

 

 

Less: Current Portion of Non-Recourse Debt of Joint Ventures

 

 

 

83

 

 

 

19

 

 

 

 

 

 

 

779

 

 

 

761

 

 

 

 

(1)     Amounts outstanding represent 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

 

2003

 

 

 

 

 

 

 

Derivative contracts

 

209

 

40

 

Regulatory deferrals

 

229

 

131

 

Other benefit plans

 

63

 

32

 

Deferred revenue

 

58

 

215

 

Asset retirement obligation

 

36

 

9

 

Other

 

71

 

134

 

 

 

666

 

561

 

 

87


 

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

 

2003

 

 

 

 

 

 

 

Preferred securities of subsidiary

 

670

 

672

 

Preferred shares of subsidiary

 

389

 

389

 

Other

 

76

 

82

 

 

 

1,135

 

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

 

2002

 

 

 

 

 

 

 

 

 

Preferred securities charges

 

31

 

36

 

36

 

Preferred share dividends

 

22

 

22

 

22

 

Other

 

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 Subsidiary

 

 

 

 

 

 

 

 

 

 

 

Series U

 

4,000

 

$

2.80

 

$

50.00

 

195

 

195

 

Series Y

 

4,000

 

$

2.80

 

$

50.00

 

194

 

194

 

 

 

 

 

 

 

 

 

389

 

389

 

 

The authorized number of preferred shares 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.

 

Other Other 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).

 

88


 

NOTE 13 Common Shares

 

 

 

Number

 

 

 

 

 

of Shares

 

Amount

 

 

 

(thousands)

 

(millions of dollars)

 

 

 

 

 

 

 

Outstanding at January 1, 2002

 

476,631

 

4,564

 

Exercise of options

 

2,871

 

50

 

Outstanding at December 31, 2002

 

479,502

 

4,614

 

Exercise of options

 

3,698

 

65

 

Outstanding at December 31, 2003

 

483,200

 

4,679

 

Exercise of options

 

1,714

 

32

 

Outstanding at December 31, 2004

 

484,914

 

4,711

 

 

Common Shares Issued and Outstanding The Company is authorized to issue an unlimited number of common shares of no par value.

 

Net Income Per Share Basic 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

 

11,376

 

Granted

 

1,946

 

$

21.43

 

 

 

Exercised

 

(2,871

)

$

17.18

 

 

 

Cancelled or expired

 

(633

)

$

23.16

 

 

 

Outstanding at December 31, 2002

 

12,892

 

$

18.92

 

10,258

 

Granted

 

1,503

 

$

22.42

 

 

 

Exercised

 

(3,698

)

$

17.59

 

 

 

Cancelled or expired

 

(342

)

$

24.07

 

 

 

Outstanding at December 31, 2003

 

10,355

 

$

19.73

 

7,588

 

Granted

 

1,331

 

$

26.85

 

 

 

Exercised

 

(1,714

)

$

18.42

 

 

 

Cancelled or expired

 

(7

)

$

24.25

 

 

 

Outstanding at December 31, 2004

 

9,965

 

$

20.90

 

7,239

 

 

89


 

The following table summarizes information for stock options outstanding at December 31, 2004.

 

 

 

Options Outstanding

 

Options Exercisable

 

Range 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

 

$

26.85

 

 

 

9,965

 

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 Plan The 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 Derivatives The carrying amounts of derivatives, which hedge the price risk of foreign currency denominated assets and liabilities of self-sustaining foreign operations, are recorded on the balance sheet at their fair value. Gains and losses on these derivatives, realized and unrealized, are included in the foreign exchange adjustment account in Shareholders’ Equity as an offset to the corresponding gains and losses on the translation of the assets and liabilities of the foreign subsidiaries. As of January 1, 2004, carrying amounts for interest rate swaps are recorded on the balance sheet at their fair value. Foreign currency transactions hedged by foreign exchange contracts are recorded at the contract rate. Power, natural gas and heat rate derivatives are recorded on the balance sheet at their fair value. The carrying amounts shown in the tables that follow are recorded in the consolidated balance sheet.

 

Fair Values of Financial Instruments Cash and short-term investments and notes payable are valued at their carrying amounts due to the short period to maturity. The fair values of long-term debt, non-recourse long-term debt of joint ventures and junior subordinated debentures are determined using market prices for the same or similar issues.

 

The fair values of foreign exchange and interest rate derivatives have been estimated using year-end market rates. The fair values of power, natural gas and heat rate derivatives have been calculated using estimated forward prices for the relevant period.

 

Credit Risk Credit risk results from the possibility that a counterparty to a derivative in which the Company has an unrealized gain fails to perform according to the terms of the contract. Credit exposure is minimized through the use of established credit management techniques, including formal assessment processes, contractual and collateral requirements, master netting arrangements and credit exposure limits. At December 31, 2004, for foreign currency and interest rate derivatives, total credit risk and the largest credit exposure to a single counterparty were $127 million and $40 million, respectively. At December 31, 2004, for power, natural gas and heat rate derivatives, total credit risk and the largest credit exposure to a single counterparty were $19 million and $7 million, respectively.

 

90


 

Notional or Notional Principal Amounts Notional principal amounts are not recorded in the financial statements because these amounts are not exchanged by the Company and its counterparties and are not a measure of the Company’s exposure. Notional amounts are used only as the basis for calculating payments for certain derivatives.

 

Foreign Investments At December 31, 2004 and 2003, the Company had foreign currency denominated assets and liabilities which created an exposure to changes in exchange rates. The Company uses foreign currency derivatives to hedge this net exposure on an after-tax basis. The foreign currency derivatives have a floating interest rate exposure which the Company partially hedges by entering into interest rate swaps and forward rate agreements. The fair values shown in the table below for those derivatives that have been designated as and are effective as hedges for foreign exchange risk are offset by translation gains or losses on the net assets and are recorded in the foreign exchange adjustment account in Shareholders’ Equity.

 

Net Investment in Foreign Assets

 

Asset/(Liability)

 

 

 

 

 

2004

 

2003

 

December 31 (millions of dollars)

 

Accounting
Treatment

 

Fair
Value

 

Notional or
Notional Principal
Amount (U.S.)

 

Fair
Value

 

Notional or
Notional Principal
Amount (U.S.)

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S. dollar cross-currency swaps (maturing 2006 to 2009)

 

Hedge

 

95

 

400

 

65

 

250

 

U.S. dollar forward foreign exchange contracts (maturing 2005)

 

Hedge

 

(1

)

305

 

3

 

125

 

U.S. dollar options (maturing 2005)

 

Non-hedge

 

1

 

100

 

—

 

—

 

 

In accordance with the Company’s accounting policy, each of the above derivatives is recorded on the consolidated balance sheet at its fair value in 2004. For derivatives that have been designated as and are effective as hedges of the net investment in foreign operations, the offsetting amounts are included in the foreign exchange adjustment account.

 

In addition, at December 31, 2004, the Company had interest rate swaps associated with the cross-currency swaps with notional principal amounts of $375 million (2003 – $311 million) and US$250 million (2003 – US$200 million). The carrying amount and fair value of these interest rate swaps was $4 million (2003 – $3 million) and $4 million (2003 – $1 million), respectively.

 

Reconciliation of Foreign Exchange Adjustment Gains/(Losses)

 

December 31 (millions of dollars)

 

2004

 

2003

 

 

 

 

 

 

 

Balance at beginning of year

 

(40

)

14

 

Translation losses on foreign currency denominated net assets

 

(64

)

(136

)

Foreign exchange gains on derivatives, net of income taxes

 

33

 

82

 

 

 

(71

)

(40

)

 

Foreign Exchange Gains/(Losses) Foreign exchange gains/(losses) included in Other Expenses/(Income) for the year ended December 31, 2004 are $4 million (2003 – nil; 2002 – $(11) million).

 

91


 

Foreign Exchange and Interest Rate Management Activity The Company manages certain of the foreign exchange risk of U.S. dollar debt, U.S. dollar expenses and the interest rate exposures of the Canadian Mainline, the Alberta System, GTN and the Foothills System through the use of foreign currency and interest rate derivatives. Certain of the realized gains and losses on these derivatives are shared with shippers on predetermined terms. The details of the foreign exchange and interest rate derivatives are shown in the table below.

 

Asset/(Liability)

 

 

 

 

 

2004

 

2003

 

December 31 (millions of dollars)

 

Accounting
Treatment

 

Fair
Value

 

Notional
or Notional
Principal Amount

 

Fair
Value

 

Notional
or Notional
Principal Amount

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign Exchange

 

 

 

 

 

 

 

 

 

 

 

 

Cross-currency swaps

 

 

 

 

 

 

 

 

 

 

 

 

(maturing 2010 to 2012)

 

Hedge

 

(39

)

U.S.

157

 

(26

)

U.S.

282

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Rate

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest rate swaps

 

 

 

 

 

 

 

 

 

 

 

 

 

Canadian dollars

 

 

 

 

 

 

 

 

 

 

 

 

 

(maturing 2005 to 2008)

 

Hedge

 

7

 

 

145

 

(1

)

 

340

 

(maturing 2006 to 2009)

 

Non-hedge

 

9

 

 

374

 

10

 

 

624

 

 

 

 

 

16

 

 

 

 

9

 

 

 

 

U.S. dollars

 

 

 

 

 

 

 

 

 

 

 

 

 

(maturing 2010 to 2015)

 

Hedge

 

(2

)

U.S.

275

 

11

 

U.S.

50

 

(maturing 2007 to 2009)

 

Non-hedge

 

7

 

U.S.

100

 

(3

)

U.S.

50

 

 

 

 

 

5

 

 

 

 

8

 

 

 

 

 

In accordance with the Company’s accounting policy, each of the above derivatives is recorded on the consolidated balance sheet at its fair value in 2004. At December 31, 2004, the Company also had interest rate swaps associated with the cross-currency swaps with notional principal amounts of $227 million (2003 – $390 million) and US$157 million (2003 – US$282 million). The carrying amount and fair value of these interest rate swaps was $(4) million (2003 – nil) and $(4) million (2003 – $6 million), respectively.

 

92


 

The Company manages the foreign exchange and interest rate exposures of its other businesses through the use of foreign currency and interest rate derivatives. The details of these foreign currency and interest rate derivatives are shown in the table below.

 

Asset/(Liability)

 

 

 

 

 

2004

 

2003

 

December 31 (millions of dollars)

 

Accounting
Treatment

 

Fair
Value

 

Notional
or Notional
Principal Amount

 

Fair
Value

 

Notional
or Notional
Principal Amount

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign Exchange

 

 

 

 

 

 

 

 

 

 

 

Options (maturing 2005)

 

Non-hedge

 

2

 

U.S.

225

 

1

 

U.S.

25

 

Forward foreign exchange

 

 

 

 

 

 

 

 

 

 

 

contracts (maturing 2005)

 

Non-hedge

 

1

 

U.S.

29

 

1

 

U.S.

19

 

Cross-currency swaps

 

 

 

 

 

 

 

 

 

 

 

(maturing 2013)

 

Hedge

 

(16

)

U.S.

100

 

(7

)

U.S.

100

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Rate

 

 

 

 

 

 

 

 

 

 

 

Options (maturing 2005)

 

Non-hedge

 

—

 

U.S.

50

 

(2

)

U.S.

50

 

Interest rate swaps

 

 

 

 

 

 

 

 

 

 

 

Canadian dollar

 

 

 

 

 

 

 

 

 

 

 

(maturing 2007 to 2009)

 

Hedge

 

4

 

100

 

2

 

50

 

(maturing 2005 to 2011)

 

Non-hedge

 

1

 

110

 

2

 

100

 

 

 

 

 

5

 

 

 

4

 

 

 

U.S. dollar

 

 

 

 

 

 

 

 

 

 

 

(maturing 2006 to 2013)

 

Hedge

 

5

 

U.S.

100

 

40

 

U.S.

250

 

(maturing 2006 to 2010)

 

Non-hedge

 

22

 

U.S.

250

 

(3

)

U.S.

200

 

 

 

 

 

27

 

 

 

37

 

 

 

 

In accordance with the Company’s accounting policy, each of the above derivatives is recorded on the consolidated balance sheet at its fair value in 2004. At December 31, 2004, the Company also had interest rate swaps associated with the cross-currency swaps with notional principal amounts of $136 million (2003 – $136 million) and US$100 million (2003 – US$100 million). The carrying amount and fair value of these interest rate swaps was $(10) million (2003 – nil) and $(10) million (2003 – $(7) million), respectively.

 

Certain of the Company’s joint ventures use interest rate derivatives to manage interest rate exposures. The Company’s proportionate share of the fair value of the outstanding derivatives at December 31, 2004 was $1 million (2003 – $(1) million).

 

Energy Price Risk Management The Company executes power, natural gas and heat rate derivatives for overall management of its asset portfolio. Heat rate contracts are contracts for the sale or purchase of power that are priced based on a natural gas index. The fair values and notional volumes of the swap, option, forward and heat rate contracts are shown in the tables below. In accordance with the Company’s accounting policy, each of the derivatives in the table below is recorded on the balance sheet at its fair value in 2004 and 2003.

 

Power

 

Asset/(Liability)

 

 

 

 

 

2004

 

2003

 

December 31 (millions of dollars)

 

Accounting
Treatment

 

Fair
Value

 

Fair
Value

 

 

 

 

 

 

 

 

 

Power – swaps

 

 

 

 

 

 

 

(maturing 2005 to 2011)

 

Hedge

 

7

 

(5

)

(maturing 2005)

 

Non-hedge

 

(2

)

—

 

Gas – swaps, forwards and options

 

 

 

 

 

 

 

(maturing 2005 to 2016)

 

Hedge

 

(39

)

(34

)

(maturing 2005)

 

Non-hedge

 

(2

)

(1

)

Heat rate contracts

 

 

 

 

 

 

 

(maturing 2005 to 2006)

 

Hedge

 

(1

)

(1

)

 

93


 

Notional Volumes

 

 

 

Accounting

 

Power (GWh) (1)

 

Gas (Bcf) (1)

 

December 31, 2004

 

Treatment

 

Purchases

 

Sales

 

Purchases

 

Sales

 

 

 

 

 

 

 

 

 

 

 

 

 

Power – swaps

 

 

 

 

 

 

 

 

 

 

 

(maturing 2005 to 2011)

 

Hedge

 

3,314

 

7,029

 

—

 

—

 

(maturing 2005)

 

Non-hedge

 

438

 

—

 

—

 

—

 

Gas – swaps, forwards and options

 

 

 

 

 

 

 

 

 

 

 

(maturing 2005 to 2016)

 

Hedge

 

—

 

—

 

80

 

84

 

(maturing 2005)

 

Non-hedge

 

—

 

—

 

5

 

8

 

Heat rate contracts

 

 

 

 

 

 

 

 

 

 

 

(maturing 2005 to 2006)

 

Hedge

 

—

 

229

 

2

 

—

 

 

December 31, 2003

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Power – swaps

 

Hedge

 

1,331

 

4,787

 

—

 

—

 

 

 

Non-hedge

 

59

 

77

 

—

 

—

 

Gas – swaps, forwards and options

 

Hedge

 

—

 

—

 

79

 

81

 

 

 

Non-hedge

 

—

 

—

 

—

 

7

 

Heat rate contracts

 

Hedge

 

—

 

735

 

1

 

—

 

 

(1)     Gigawatt hours (GWh); billion cubic feet (Bcf).

 

U.S. Dollar Transaction Hedges To reduce risk and protect margins when purchase and sale contracts are denominated in different currencies, the Company may enter into forward foreign exchange contracts and foreign exchange options which establish the foreign exchange rate for the cash flows from the related purchase and sale transactions.

 

Other Fair Values

 

 

 

2004

 

2003

 

December 31 (millions of dollars)

 

Carrying
Amount

 

Fair
Value

 

Carrying
Amount

 

Fair
Value

 

 

 

 

 

 

 

 

 

 

 

Long-Term Debt

 

 

 

 

 

 

 

 

 

Canadian Mainline

 

4,445

 

5,473

 

4,853

 

5,922

 

Alberta System

 

2,105

 

2,668

 

2,325

 

2,893

 

GTN (1)

 

632

 

627

 

 

 

 

 

Foothills System

 

400

 

413

 

380

 

382

 

Portland

 

308

 

328

 

350

 

348

 

Other

 

2,589

 

2,687

 

2,107

 

2,214

 

Non-Recourse Debt of Joint Ventures

 

862

 

967

 

780

 

889

 

Preferred Securities

 

19

 

19

 

19

 

19

 

 

(1)     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.

 

94


 

NOTE 15 Income Taxes

 

Provision for Income Taxes

 

Year ended December 31 (millions of dollars)

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

Current

 

 

 

 

 

 

 

Canada

 

390

 

264

 

229

 

Foreign

 

41

 

41

 

41

 

 

 

431

 

305

 

270

 

Future

 

 

 

 

 

 

 

Canada

 

34

 

183

 

193

 

Foreign

 

43

 

47

 

54

 

 

 

77

 

230

 

247

 

 

 

508

 

535

 

517

 

 

Geographic Components of Income

 

Year ended December 31 (millions of dollars)

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

Canada

 

1,255

 

1,115

 

1,042

 

Foreign

 

296

 

281

 

280

 

Income 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

 

2002

 

 

 

 

 

 

 

 

 

Income from continuing operations before income taxes and non-controlling interests

 

1,551

 

1,396

 

1,322

 

Federal and provincial statutory tax rate

 

33.9

%

36.7

%

39.2

%

Expected income tax expense

 

526

 

512

 

518

 

Income tax differential related to regulated operations

 

62

 

29

 

(8

)

Higher (lower) effective foreign tax rates

 

2

 

(2

)

(13

)

Large corporations tax

 

21

 

28

 

30

 

Lower effective tax rate on equity in earnings of affiliates

 

(9

)

(11

)

(2

)

Non-taxable portion of gains related to Power LP

 

(66

)

—

 

—

 

Change in valuation allowance

 

(7

)

(3

)

8

 

Other

 

(21

)

(18

)

(16

)

Actual income tax expense

 

508

 

535

 

517

 

 

Future Income Tax Assets and Liabilities

 

December 31 (millions of dollars)

 

2004

 

2003

 

 

 

 

 

 

 

Deferred costs

 

71

 

50

 

Deferred revenue

 

18

 

29

 

Alternative minimum tax credits

 

10

 

29

 

Net operating and capital loss carryforwards

 

7

 

28

 

Other

 

72

 

24

 

 

 

178

 

160

 

Less: Valuation allowance

 

17

 

24

 

Future income tax assets, net of valuation allowance

 

161

 

136

 

Difference in accounting and tax bases of plant, equipment and PPAs

 

456

 

396

 

Investments in subsidiaries and partnerships

 

114

 

108

 

Unrealized foreign exchange gains on long-term debt

 

45

 

15

 

Other

 

55

 

44

 

Future income tax liabilities

 

670

 

563

 

Net future income tax liabilities

 

509

 

427

 

 

95


 

As permitted by Canadian GAAP, the Company follows the taxes payable method of accounting for income taxes related to the operations of the Canadian natural gas transmission operations. If the liability method of accounting had been used, additional future income tax liabilities in the amount of $1,692 million at December 31, 2004 (2003 – $1,758 million) would have been recorded and would be recoverable from future revenues.

 

Unremitted Earnings of Foreign Investments Income taxes have not been provided on the unremitted earnings of foreign investments which the Company does not intend to repatriate in the foreseeable future. If provision for these taxes had been made, future income tax liabilities would increase by approximately $57 million at December 31, 2004 (2003 – $54 million).

 

Income Tax Payments Income tax payments of $419 million were made during the year ended December 31, 2004 (2003 – $220 million; 2002 – $257 million).

 

NOTE 16 Notes Payable

 

 

 

2004

 

2003

 

 

 

Outstanding
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 Paper

 

 

 

 

 

 

 

 

 

Canadian dollars

 

546

 

2.6

%

367

 

2.7

%

 

Total credit facilities of $2.0 billion at December 31, 2004, were available to support the Company’s commercial paper programs and for general corporate purposes. Of this total, $1.5 billion is a committed syndicated credit facility established in December 2002. This facility is comprised of a $1.0 billion tranche with a five year term and a $500 million tranche with a 364 day term with a two year term out option. Both tranches are extendible on an annual basis and are revolving unless during a term out period. Both tranches were extended in December 2004, the $1.0 billion tranche to December 2009 and the $500 million tranche to December 2005. The remaining amounts are either demand or non-extendible facilities.

 

At December 31, 2004, the Company had used approximately $61 million of its total lines of credit for letters of credit and to support its ongoing commercial arrangements. If drawn, interest on the lines of credit would be charged at prime rates of Canadian chartered and U.S. banks and at other negotiated financial bases. The cost to maintain the unused portion of the lines of credit is approximately $2 million for the year ended December 31, 2004 (2003 – $2 million).

 

NOTE 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.

 

96


 

Reconciliation of Asset Retirement Obligations

 

(millions of dollars)

 

Gas Transmission

 

Power

 

Total

 

 

 

 

 

 

 

 

 

Balance at December 31, 2002

 

2

 

6

 

8

 

Revisions in estimated cash flows

 

—

 

1

 

1

 

Balance at December 31, 2003

 

2

 

7

 

9

 

New obligations and revisions in estimated cash flows

 

9

 

21

 

30

 

Removal of Power LP redemption obligations

 

—

 

(5

)

(5

)

Accretion expense

 

1

 

1

 

2

 

Balance at December 31, 2004

 

12

 

24

 

36

 

 

NOTE 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.

 

97


 

 

 

Pension Benefit Plans

 

Other Benefit Plans

 

(millions of dollars)

 

2004

 

2003

 

2004

 

2003

 

 

 

 

 

 

 

 

 

 

 

Change in Benefit Obligation

 

 

 

 

 

 

 

 

 

Benefit obligation – beginning of year

 

960

 

841

 

106

 

95

 

Current service cost

 

28

 

25

 

3

 

2

 

Interest cost

 

58

 

52

 

7

 

6

 

Employee contributions

 

2

 

2

 

—

 

—

 

Benefits paid

 

(66

)

(45

)

(4

)

(4

)

Actuarial loss

 

46

 

66

 

(12

)

7

 

Acquisition of subsidiary

 

72

 

19

 

23

 

—

 

Benefit obligation – end of year

 

1,100

 

960

 

123

 

106

 

 

 

 

 

 

 

 

 

 

 

Change in Plan Assets

 

 

 

 

 

 

 

 

 

Plan assets at fair value – beginning of year

 

799

 

621

 

—

 

—

 

Actual return on plan assets

 

97

 

89

 

1

 

—

 

Employer contributions

 

84

 

110

 

4

 

4

 

Employee contributions

 

2

 

2

 

—

 

—

 

Benefits paid

 

(66

)

(45

)

(4

)

(4

)

Acquisition of subsidiary

 

54

 

22

 

25

 

—

 

Plan assets at fair value – end of year

 

970

 

799

 

26

 

—

 

Funded status – plan deficit

 

(130

)

(161

)

(97

)

(106

)

Unamortized net actuarial loss

 

255

 

263

 

25

 

39

 

Unamortized past service costs

 

39

 

41

 

7

 

6

 

Unamortized transitional obligation related to regulated business

 

—

 

—

 

—

 

25

 

Accrued benefit asset/(liability), net of valuation allowance of nil

 

164

 

143

 

(65

)

(36

)

 

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

 

 

 

Pension Benefit Plans

 

Other Benefit Plans

 

 

 

2004

 

2003

 

2004

 

2003

 

 

 

 

 

 

 

 

 

 

 

Other assets

 

206

 

201

 

3

 

—

 

Accounts payable

 

(42

)

(58

)

(5

)

(4

)

Deferred amounts

 

—

 

—

 

(63

)

(32

)

Total

 

164

 

143

 

(65

)

(36

)

 

Included in the above accrued benefit obligation and fair value of plan assets at year end are the following amounts in respect

of plans that are not fully funded.

 

 

 

Pension Benefit Plans

 

Other Benefit Plans

 

 

 

2004

 

2003

 

2004

 

2003

 

 

 

 

 

 

 

 

 

 

 

Accrued benefit obligation

 

(1,084

)

(942

)

(100

)

(106

)

Fair value of plan assets

 

952

 

778

 

—

 

—

 

Funded status – plan deficit

 

(132

)

(164

)

(100

)

(106

)

 

The Company’s expected contributions for the year ended December 31, 2005 are approximately $67 million for the pension benefit plans and approximately $6 million for the other benefit plans.

 

The following are estimated future benefit payments, which reflect expected future service.

 

(millions of dollars)

 

Pension Benefits

 

Other Benefits

 

 

 

 

 

 

 

2005

 

52

 

6

 

2006

 

53

 

6

 

2007

 

56

 

7

 

2008

 

58

 

7

 

2009

 

60

 

7

 

Years 2010 to 2014

 

343

 

40

 

 

98


 

The significant weighted average actuarial assumptions adopted in measuring the Company’s benefit obligations at December 31 are as follows.

 

 

 

Pension Benefit Plans

 

Other Benefit Plans

 

 

 

2004

 

2003

 

2004

 

2003

 

 

 

 

 

 

 

 

 

 

 

Discount rate

 

5.75

%

6.00

%

6.00

%

6.25

%

Rate of compensation increase

 

3.50

%

3.50

%

 

 

 

 

 

The significant weighted average actuarial assumptions adopted in measuring the Company’s net benefit plan cost for years ended December 31 are as follows.

 

 

 

Pension Benefit Plans

 

Other Benefit Plans

 

 

 

2004

 

2003

 

2002

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Discount rate

 

6.00

%

6.25

%

6.75

%

6.25

%

6.50

%

6.85

%

Expected long-term rate of return on plan assets

 

6.90

%

7.25

%

7.52

%

 

 

 

 

 

 

Rate of compensation increase

 

3.50

%

3.75

%

3.50

%

 

 

 

 

 

 

 

The overall expected long-term rate of return on plan assets is based on historical and projected rates of return for both the portfolio in aggregate and for each asset class in the portfolio. Assumed projected rates of return are selected after analyzing historical experience and future expectations of the level and volatility of returns. Asset class benchmark returns, asset mix and anticipated benefit payments from plan assets are also considered in the determination of the overall expected rate of return.

 

For measurement purposes, a 9.0 per cent annual rate of increase in the per capita cost of covered health care benefits was assumed for 2005. The rate was assumed to decrease gradually to 5.0 per cent for 2014 and remain at that level thereafter. A one percentage point increase or decrease in assumed health care cost trend rates would have the following effects.

 

(millions of dollars)

 

Increase

 

Decrease

 

 

 

 

 

 

 

Effect on total of service and interest cost components

 

2

 

(1

)

Effect on post-employment benefit obligation

 

12

 

(11

)

 

The Company’s net benefit cost is as follows.

 

 

 

Pension Benefit Plans

 

Other Benefit Plans

 

Year ended December 31 (millions of dollars)

 

2004

 

2003

 

2002

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current service cost

 

28

 

25

 

11

 

3

 

2

 

2

 

Interest cost

 

58

 

52

 

43

 

7

 

6

 

4

 

Actual return on plan assets

 

(97

)

(89

)

(9

)

1

 

—

 

—

 

Actuarial loss

 

46

 

66

 

93

 

(12

)

7

 

26

 

Plan amendment

 

—

 

—

 

92

 

—

 

—

 

7

 

Elements of net benefit cost prior to adjustments to recognize the long-term nature of net benefit cost

 

35

 

54

 

230

 

(1

)

15

 

39

 

Difference between expected and actual return on plan assets

 

39

 

38

 

(36

)

(1

)

—

 

—

 

Difference between actuarial loss recognized and actual actuarial loss on accrued benefit obligation

 

(32

)

(58

)

(91

)

13

 

(6

)

(26

)

Difference between amortization of past service costs and actual plan amendments

 

3

 

3

 

(92

)

—

 

1

 

(7

)

Amortization of transitional obligation related to regulated business

 

—

 

—

 

—

 

2

 

2

 

2

 

Net benefit cost recognized

 

45

 

37

 

11

 

13

 

12

 

8

 

 

99


 

The Company’s pension plan weighted average asset allocation at December 31, by asset category, and weighted average target allocation at December 31, by asset category, is as follows.

 

 

 

Percentage of Plan Assets

 

Target Allocation

 

Asset Category

 

2004

 

2003

 

2004

 

 

 

 

 

 

 

 

 

Debt securities

 

44

%

47

%

35% to 60

%

Equity securities

 

56

%

53

%

40% to 65

%

 

 

100

%

100

%

 

 

 

The assets of the pension plan are managed on a going concern basis subject to legislative restrictions. The plan’s investment policy is to maximize returns within an acceptable risk tolerance. Pension assets are invested in a diversified manner with consideration given to the demographics of the plan participants.

 

NOTE 19 Changes in Operating Working Capital

 

Year ended December 31 (millions of dollars)

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

Decrease/(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

)

14

 

 

 

34

 

112

 

33

 

 

NOTE 20 Commitments, Contingencies and Guarantees

 

Commitments Future annual payments, net of sub-lease receipts, under the Company’s operating leases for various premises and a natural gas storage facility are approximately as follows.

 

Year ended December 31 (millions of dollars)

 

Minimum
Lease
Payments

 

Amounts
Recoverable
under Sub-Leases

 

Net
Payments

 

 

 

 

 

 

 

 

 

2005

 

37

 

(9

)

28

 

2006

 

45

 

(10

)

35

 

2007

 

51

 

(9

)

42

 

2008

 

53

 

(9

)

44

 

2009

 

53

 

(9

)

44

 

 

The operating lease agreements for premises expire at various dates through 2011, with an option to renew certain lease agreements for five years. The operating lease agreement for the natural gas storage facility expires in 2030 with lessee termination rights every fifth anniversary commencing in 2010 and with the lessor having the right to terminate the agreement every five years commencing in 2015. Net rental expense on operating leases for the year ended December 31, 2004 was $7 million (2003 – $2 million; 2002 – $7 million).

 

On June 18, 2003, the Mackenzie Delta gas producers, the Aboriginal Pipeline Group (APG) and 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.

 

100


 

Contingencies The Canadian Alliance of Pipeline Landowners’ Associations and two individual landowners commenced an action in 2003 under Ontario’s Class Proceedings Act, 1992, against 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.

 

Guarantees Upon acquisition of Bruce Power, the Company, together with Cameco Corporation and BPC Generation Infrastructure Trust, guaranteed on a several pro-rata basis certain contingent financial obligations of Bruce Power related to operator licenses, the lease agreement, power sales agreements and contractor services. 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.

 

101


 

NOTE 22 U.S. GAAP

 

The Company’s consolidated financial statements have been prepared in accordance with Canadian GAAP, which, in some respects, differ from U.S. GAAP. The effects of these differences on the Company’s financial statements are as follows.

 

Condensed Statement of Consolidated Income and Comprehensive Income in Accordance with U.S. GAAP (1)

 

Year ended December 31 (millions of dollars except per share amounts)

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

Revenues

 

4,700

 

4,919

 

4,565

 

Cost of sales

 

440

 

592

 

441

 

Other costs and expenses

 

1,638

 

1,663

 

1,532

 

Depreciation

 

857

 

819

 

729

 

 

 

2,935

 

3,074

 

2,702

 

Operating income

 

1,765

 

1,845

 

1,863

 

Other (income)/expenses

 

 

 

 

 

 

 

Equity income (1)

 

(353

)

(334

)

(260

)

Other expenses (2)

 

651

 

863

 

872

 

Income taxes

 

490

 

515

 

499

 

 

 

788

 

1,044

 

1,111

 

Income from continuing operations – U.S. GAAP

 

977

 

801

 

752

 

Net income from discontinued operations – U.S. GAAP

 

52

 

50

 

—

 

Income before cumulative effect of the application of accounting changes in accordance with U.S. GAAP

 

1,029

 

851

 

752

 

Cumulative effect of the application of accounting changes, net of tax (3)

 

—

 

(13

)

—

 

Net Income in Accordance with U.S. GAAP

 

1,029

 

838

 

752

 

Adjustments affecting comprehensive income under U.S. GAAP

 

 

 

 

 

 

 

Foreign currency translation adjustment, net of tax

 

(31

)

(54

)

1

 

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

 

72

 

(2

)

(40

)

Unrealized gain/(loss) on derivatives, net of tax (5)

 

1

 

8

 

(4

)

Comprehensive Income in Accordance with U.S. GAAP

 

1,071

 

790

 

709

 

Net Income Per Share in Accordance with U.S. GAAP

 

 

 

 

 

 

 

Continuing operations

 

$

2.02

 

$

1.67

 

$

1.57

 

Discontinued operations

 

0.11

 

0.10

 

—

 

Income before cumulative effect of the application of accounting changes in accordance with U.S. GAAP

 

$

2.13

 

$

1.77

 

$

1.57

 

Cumulative effect of the application of accounting changes, net of tax (3)

 

—

 

(0.03

)

—

 

Basic

 

$

2.13

 

$

1.74

 

$

1.57

 

Diluted (6)

 

$

2.12

 

$

1.73

 

$

1.56

 

Net Income Per Share in Accordance with Canadian GAAP

 

 

 

 

 

 

 

Basic

 

$

2.13

 

$

1.76

 

$

1.56

 

Diluted

 

$

2.12

 

$

1.76

 

$

1.55

 

Dividends per common share

 

$

1.16

 

$

1.08

 

$

1.00

 

 

102


 

Reconciliation of Income from Continuing Operations

 

Year ended December 31 (millions of dollars)

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

Net Income from Continuing Operations
in Accordance with Canadian GAAP

 

980

 

801

 

747

 

U.S. GAAP adjustments

 

 

 

 

 

 

 

Unrealized (loss)/gain on foreign exchange and interest rate derivatives (5)

 

(12

)

(9

)

30

 

Tax impact of (loss)/gain on foreign exchange and interest rate derivatives

 

4

 

3

 

(12

)

Unrealized gain/(loss) on energy marketing contracts (3)

 

10

 

28

 

(21

)

Tax impact of unrealized gain/(loss) on energy marketing contracts

 

(3

)

(10

)

8

 

Equity loss (7)

 

(2

)

(18

)

—

 

Tax impact of equity loss

 

—

 

6

 

—

 

Income from Continuing Operations in Accordance with U.S. GAAP

 

977

 

801

 

752

 

 

Condensed Statement of Consolidated Cash Flows in Accordance with U.S. GAAP

 

Year ended December 31 (millions of dollars)

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

Cash Generated from Operations

 

 

 

 

 

 

 

Funds generated from continuing operations

 

1,529

 

1,619

 

1,610

 

Decrease in operating working capital

 

45

 

108

 

40

 

Net cash provided by continuing operations

 

1,574

 

1,727

 

1,650

 

Net cash (used in)/provided by discontinued operations

 

(6

)

(17

)

59

 

 

 

1,568

 

1,710

 

1,709

 

Investing Activities

 

 

 

 

 

 

 

Net cash used in investing activities

 

(1,304

)

(943

)

(796

)

Financing Activities

 

 

 

 

 

 

 

Net 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 Investments

 

 

 

 

 

 

 

Beginning of year

 

283

 

149

 

229

 

Cash and Short-Term Investments

 

 

 

 

 

 

 

End of year

 

124

 

283

 

149

 

 

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

 

December 31 (millions of dollars)

 

2004

 

2003

 

 

 

 

 

 

 

Current assets

 

908

 

1,020

 

Long-term investments (7)(8)

 

1,887

 

1,760

 

Plant, property and equipment

 

17,083

 

15,753

 

Regulatory asset (9)

 

2,606

 

2,721

 

Other assets

 

1,235

 

1,385

 

 

 

23,719

 

22,639

 

 

 

 

 

 

 

Current liabilities (10)

 

2,573

 

2,135

 

Deferred amounts (3)(5)(8)

 

803

 

827

 

Long-term debt (5)

 

9,753

 

9,494

 

Deferred income taxes (9)

 

3,048

 

3,039

 

Preferred securities (11)

 

554

 

694

 

Non-controlling interests

 

465

 

471

 

Shareholders’ equity

 

6,523

 

5,979

 

 

 

23,719

 

22,639

 

 

103


 

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

 

(millions of dollars)

 

Cumulative
Translation
Account

 

Minimum
Pension
Liability
(SFAS No. 87)

 

Cash Flow
Hedges
(SFAS No. 133)

 

Total

 

 

 

 

 

 

 

 

 

 

 

Balance at January 1, 2002

 

13

 

(56

)

(9

)

(52

)

Changes in minimum pension liability, net of tax of $22 (4)

 

—

 

(40

)

—

 

(40

)

Unrealized loss on derivatives, net of tax of $(1) (5)

 

—

 

—

 

(4

)

(4

)

Foreign currency translation adjustment, net of tax of nil

 

1

 

—

 

—

 

1

 

Balance at December 31, 2002

 

14

 

(96

)

(13

)

(95

)

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

 

—

 

(2

)

—

 

(2

)

Unrealized gain on derivatives, net of tax of nil (5)

 

—

 

—

 

8

 

8

 

Foreign currency translation adjustment, net of tax of $(64)

 

(54

)

—

 

—

 

(54

)

Balance at December 31, 2003

 

(40

)

(98

)

(5

)

(143

)

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

 

—

 

72

 

—

 

72

 

Unrealized gain on derivatives, net of tax of $(3) (5)

 

—

 

—

 

1

 

1

 

Foreign currency translation adjustment, net of tax of $(44)

 

(31

)

—

 

—

 

(31

)

Balance at December 31, 2004

 

(71

)

(26

)

(4

)

(101

)

 

(1)     In accordance with U.S. GAAP, the Condensed Statement of Consolidated Income and Balance Sheet are prepared using the equity method of accounting for joint ventures. Excluding the impact of other U.S. GAAP adjustments, the use of the proportionate consolidation method of accounting for joint ventures, as required under Canadian GAAP, results in the same net income and shareholders’ equity.

(2)     Other expenses included an allowance for funds used during construction of $3 million for the year ended December 31, 2004 (2003 – $2 million; 2002 – $4 million).

(3)     Subsequent to October 1, 2003, the energy contracts that were accounted for as hedges under the provisions of Statement of Financial Accounting Standards (SFAS) No. 133 qualified as hedges. Substantially all derivative energy contracts are now accounted for as hedges under both U.S. and Canadian GAAP. All gains or losses on the contracts that did not qualify as hedges under SFAS No. 133, and the amounts of any ineffectiveness on the hedging contracts, are included in income each period. Substantially all of the amounts recorded in 2004 and 2003 as differences between U.S. and Canadian GAAP relate to gains and losses on contracts for periods before they were documented as hedges for purposes of U.S. GAAP and to differences in accounting with respect to physical energy trading contracts in the U.S. and Canada.

(4)     Under U.S. GAAP, a net loss recognized pursuant to SFAS No. 87 “Employers’ Accounting for Pensions” as an additional pension liability not yet recognized as net period pension cost, must be recorded as a component of comprehensive income. The net amount recognized at December 31 is as follows.

 

December 31 (millions of dollars)

 

2004

 

2003

 

Prepaid benefit cost

 

206

 

201

 

Accounts payable

 

(42

)

(58

)

Intangible assets

 

(1

)

(41

)

Accumulated other comprehensive income

 

(40

)

(151

)

Net amount recognized

 

123

 

(49

)

 

The accumulated benefit obligation for the Company’s DB Plans was $943 million at December 31, 2004 (2003 – $819 million).

 

104


 

(5)     Effective January 1, 2004, all foreign exchange and interest rate derivatives are recorded in the Company’s consolidated financial statements at fair value under Canadian GAAP. Under the provisions of SFAS No. 133 “Accounting for Derivatives and Hedging Activities”, all derivatives are recognized as assets and liabilities on the balance sheet and measured at fair value. For derivatives designated as fair value hedges, changes in the fair value are recognized in earnings together with an equal or lesser amount of changes in the fair value of the hedged item attributable to the hedged risk. For derivatives designated as cash flow hedges, changes in the fair value of the derivative that are effective in offsetting the hedged risk are recognized in other comprehensive income until the hedged item is recognized in earnings. Any ineffective portion of the change in fair value is recognized in earnings each period. Substantially all of the amounts recorded in 2004 as differences between U.S. and Canadian GAAP, for income from continuing operations, relate to the differences in accounting treatment with respect to the hedged item and, for comprehensive income, relate to cash flow hedges.

During 2004, under the provisions of SFAS 133, net gains of $10 million (2003 – $47 million; 2002 – $38 million) from the hedges of changes in the fair value of long-term debt, and net losses of $18 million (2003 – $53 million; 2002 – $20 million) in the fair value of the hedged item were included in earnings for U.S. GAAP purposes as an adjustment to interest expense and foreign exchange losses. No amounts of the derivatives’ gains or losses were excluded from the assessment of hedge effectiveness in fair value hedging relationships.

No amounts were included in income in 2004, 2003 and 2002 with respect to ineffectiveness of cash flow hedges. For amounts included in other comprehensive income at December 31, 2004, $2 million (2003 – $9 million; 2002 – $(5) million) relates to the hedging of interest rate risk, $(3) million (2003 – $5 million; 2002 – $1 million) relates to the hedging of foreign exchange rate risk, and $2 million (2003 – $(6) million; 2002 – nil) relates to the hedging of energy price risk. Of these amounts, $2 million is expected to be recorded in earnings during 2005.

At December 31, 2004, assets of $(29) million (2003 – $91 million) and liabilities of $(27) million (2003 – $93 million) were (reduced)/added for U.S. GAAP purposes to reflect the fair value of derivatives and the corresponding change in the fair value of hedged items.

(6)     Diluted net income per share in accordance with U.S. GAAP for the year ended December 31, 2004 consists of continuing operations – $2.01 per share (2003 – $1.63 per share; 2002 – $1.56 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).

 

Income Taxes The tax effects of differences between the accounting value and the tax value of assets and liabilities are as follows.

 

December 31 (millions of dollars)

 

2004

 

2003

 

 

 

 

 

 

 

Deferred Tax Liabilities

 

 

 

 

 

Difference in accounting and tax bases of plant, equipment and PPAs

 

1,741

 

1,813

 

Taxes on future revenue requirement

 

914

 

962

 

Investments in subsidiaries and partnerships

 

438

 

373

 

Other

 

140

 

87

 

 

 

3,233

 

3,235

 

 

 

 

 

 

 

Deferred Tax Assets

 

 

 

 

 

Net operating and capital loss carryforwards

 

7

 

28

 

Deferred amounts

 

89

 

79

 

Other

 

106

 

113

 

 

 

202

 

220

 

Less: Valuation allowance

 

17

 

24

 

 

 

185

 

196

 

Net deferred tax liabilities

 

3,048

 

3,039

 

 

105


 

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

 

2002

 

 

 

 

 

 

 

 

 

Income

 

 

 

 

 

 

 

Revenues

 

1,149

 

1,063

 

798

 

Other costs and expenses

 

(575

)

(528

)

(273

)

Depreciation

 

(155

)

(141

)

(146

)

Financial charges and other

 

(66

)

(60

)

(119

)

Proportionate share of income before income taxes of long-term investments

 

353

 

334

 

260

 

 

December 31 (millions of dollars)

 

2004

 

2003

 

 

 

 

 

 

 

Balance Sheet

 

 

 

 

 

Current assets

 

361

 

385

 

Plant, property and equipment

 

3,020

 

2,944

 

Current liabilities

 

(248

)

(204

)

Deferred amounts (net)

 

(199

)

(286

)

Non-recourse debt

 

(1,030

)

(1,060

)

Deferred income taxes

 

(17

)

(19

)

Proportionate share of net assets of long-term investments

 

1,887

 

1,760

 

 

106


 

SUPPLEMENTARY INFORMATION

 

QUARTERLY AND ANNUAL SHARE TRADING INFORMATION

 

Toronto Stock Exchange (Stock trading symbol TRP)

 

First

 

Second

 

Third

 

Fourth

 

Annual

 

 

 

 

 

 

 

 

 

 

 

 

 

2004 (dollars)

 

 

 

 

 

 

 

 

 

 

 

High

 

29.72

 

29.40

 

28.60

 

30.35

 

30.35

 

Low

 

26.45

 

25.70

 

25.37

 

26.98

 

25.37

 

Close

 

28.28

 

26.40

 

27.65

 

29.80

 

29.80

 

Volume (millions of shares)

 

90.4

 

70.1

 

62.8

 

56.8

 

280.1

 

 

 

 

 

 

 

 

 

 

 

 

 

2003 (dollars)

 

 

 

 

 

 

 

 

 

 

 

High

 

23.00

 

25.67

 

25.80

 

28.49

 

28.49

 

Low

 

20.77

 

21.60

 

23.60

 

24.76

 

20.77

 

Close

 

21.55

 

23.75

 

25.07

 

27.88

 

27.88

 

Volume (millions of shares)

 

69.6

 

76.9

 

64.2

 

67.2

 

277.9

 

 

 

 

 

 

 

 

 

 

 

 

 

New York Stock Exchange (Stock trading symbol TRP)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2004 (U.S. dollars)

 

 

 

 

 

 

 

 

 

 

 

High

 

22.38

 

22.39

 

22.30

 

24.91

 

24.91

 

Low

 

19.70

 

18.75

 

19.40

 

21.80

 

18.75

 

Close

 

21.50

 

19.78

 

21.85

 

24.87

 

24.87

 

Volume (millions of shares)

 

12.3

 

9.9

 

5.5

 

5.3

 

33.0

 

 

 

 

 

 

 

 

 

 

 

 

 

2003 (U.S. dollars)

 

 

 

 

 

 

 

 

 

 

 

High

 

15.12

 

19.10

 

18.82

 

21.88

 

21.88

 

Low

 

14.16

 

14.62

 

17.45

 

18.47

 

14.16

 

Close

 

14.74

 

17.57

 

18.58

 

21.51

 

21.51

 

Volume (millions of shares)

 

6.5

 

5.3

 

2.5

 

6.9

 

21.2

 

 

 

107


 

FIVE-YEAR FINANCIAL HIGHLIGHTS

 

(millions of dollars except where indicated)

 

2004

 

2003

 

2002

 

2001

 

2000

 

 

 

 

 

 

 

 

 

 

 

 

 

Income Statement

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

5,107

 

5,357

 

5,214

 

5,275

 

4,384

 

Net income from continuing operations

 

980

 

801

 

747

 

686

 

628

 

Net income/(loss) by segment

 

 

 

 

 

 

 

 

 

 

 

Gas Transmission

 

586

 

622

 

653

 

585

 

623

 

Power

 

396

 

220

 

146

 

168

 

85

 

Corporate

 

(2

)

(41

)

(52

)

(67

)

(80

)

Continuing operations

 

980

 

801

 

747

 

686

 

628

 

Discontinued operations

 

52

 

50

 

—

 

(67

)

61

 

Net income

 

1,032

 

851

 

747

 

619

 

689

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash Flow Statement

 

 

 

 

 

 

 

 

 

 

 

Funds generated from continuing operations

 

1,674

 

1,810

 

1,827

 

1,624

 

1,495

 

Capital expenditures and acquisitions

 

1,992

 

961

 

827

 

1,077

 

1,135

 

Dividends and preferred securities charges

 

623

 

588

 

546

 

517

 

536

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance Sheet

 

 

 

 

 

 

 

 

 

 

 

Assets

 

 

 

 

 

 

 

 

 

 

 

Plant, property and equipment

 

 

 

 

 

 

 

 

 

 

 

Gas Transmission

 

17,325

 

16,055

 

16,071

 

16,481

 

16,864

 

Power

 

1,342

 

1,310

 

1,340

 

1,116

 

776

 

Corporate

 

37

 

50

 

64

 

66

 

111

 

Total assets

 

 

 

 

 

 

 

 

 

 

 

Continuing operations

 

22,123

 

20,690

 

20,033

 

19,865

 

19,917

 

Discontinued operations

 

7

 

11

 

139

 

276

 

5,007

 

 

 

 

 

 

 

 

 

 

 

 

 

Capitalization

 

 

 

 

 

 

 

 

 

 

 

Long-term debt

 

9,713

 

9,465

 

8,815

 

9,347

 

9,928

 

Non-recourse debt of joint ventures

 

779

 

761

 

1,222

 

1,295

 

1,296

 

Preferred securities

 

19

 

22

 

238

 

237

 

243

 

Non-controlling interests

 

 

 

 

 

 

 

 

 

 

 

Preferred securities of subsidiary

 

670

 

672

 

674

 

675

 

969

 

Preferred shares of subsidiary

 

389

 

389

 

389

 

389

 

389

 

Common shareholders’ equity

 

6,565

 

6,091

 

5,747

 

5,426

 

5,211

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S. GAAP Information

 

 

 

 

 

 

 

 

 

 

 

Net income/(loss)

 

 

 

 

 

 

 

 

 

 

 

Continuing operations before extraordinary items

 

977

 

788

 

752

 

693

 

607

 

Discontinued operations

 

52

 

50

 

—

 

(67

)

61

 

Extraordinary item

 

—

 

—

 

—

 

—

 

13

 

Net income

 

1,029

 

838

 

752

 

626

 

681

 

Net income/(loss) per share

 

 

 

 

 

 

 

 

 

 

 

Continuing operations before extraordinary items

 

$

2.02

 

$

1.64

 

$

1.57

 

$

1.46

 

$

1.27

 

Discontinued operations

 

$

0.11

 

$

0.10

 

$

—

 

$

(0.14

)

$

0.13

 

Extraordinary item

 

$

—

 

$

—

 

$

—

 

$

—

 

$

0.03

 

Net income per share – Basic

 

$

2.13

 

$

1.74

 

$

1.57

 

$

1.32

 

$

1.43

 

Net income per share – Diluted

 

$

2.12

 

$

1.73

 

$

1.56

 

$

1.32

 

$

1.43

 

Common shareholders’ equity

 

6,523

 

5,979

 

5,642

 

5,360

 

5,163

 

 

108


 

 

 

2004

 

2003

 

2002

 

2001

 

2000

 

 

 

 

 

 

 

 

 

 

 

 

 

Per Common Share Data (dollars)

 

 

 

 

 

 

 

 

 

 

 

Net income – Basic

 

 

 

 

 

 

 

 

 

 

 

Continuing operations

 

$

2.02

 

$

1.66

 

$

1.56

 

$

1.44

 

$

1.32

 

Discontinued operations

 

0.11

 

0.10

 

—

 

(0.14

)

0.13

 

 

 

$

2.13

 

$

1.76

 

$

1.56

 

$

1.30

 

$

1.45

 

Net income – Diluted

 

 

 

 

 

 

 

 

 

 

 

Continuing operations

 

$

2.01

 

$

1.66

 

$

1.55

 

$

1.44

 

$

1.32

 

Discontinued operations

 

0.11

 

0.10

 

—

 

(0.14

)

0.13

 

 

 

$

2.12

 

$

1.76

 

$

1.55

 

$

1.30

 

$

1.45

 

Dividends declared

 

$

1.16

 

$

1.08

 

$

1.00

 

$

0.90

 

$

0.80

 

Book value (1) (6)

 

$

13.54

 

$

12.61

 

$

11.99

 

$

11.38

 

$

10.97

 

Market price

 

 

 

 

 

 

 

 

 

 

 

Toronto Stock Exchange (Cdn$)

 

 

 

 

 

 

 

 

 

 

 

High

 

30.35

 

28.49

 

23.91

 

21.13

 

17.25

 

Low

 

25.37

 

20.77

 

19.05

 

14.85

 

9.80

 

Close

 

29.80

 

27.88

 

22.92

 

19.87

 

17.20

 

Volume (millions of shares)

 

280.1

 

277.9

 

280.6

 

288.2

 

400.7

 

New York Stock Exchange (US$)

 

 

 

 

 

 

 

 

 

 

 

High

 

24.91

 

21.88

 

15.56

 

13.41

 

11.50

 

Low

 

18.75

 

14.16

 

11.89

 

9.88

 

6.75

 

Close

 

24.87

 

21.51

 

14.51

 

12.51

 

11.50

 

Volume (millions of shares)

 

33.0

 

21.2

 

16.3

 

16.8

 

21.2

 

Shares outstanding (millions)

 

 

 

 

 

 

 

 

 

 

 

Average for the year

 

484.1

 

481.5

 

478.3

 

475.8

 

474.6

 

End of year

 

484.9

 

483.2

 

479.5

 

476.6

 

474.9

 

Registered common shareholders (1)

 

31,837

 

33,133

 

34,902

 

36,350

 

30,758

 

 

 

 

 

 

 

 

 

 

 

 

 

Financial Ratios

 

 

 

 

 

 

 

 

 

 

 

Return on average common shareholders’ equity (2) 

 

16.3

%

14.4

%

13.4

%

11.6

%

13.6

%

Dividend yield (3)

 

3.9

%

3.9

%

4.4

%

4.5

%

4.7

%

Price/earnings multiple (4)(5)

 

14.0

 

15.8

 

14.7

 

15.3

 

11.9

 

Price/book multiple (4)(6)

 

2.2

 

2.2

 

1.9

 

1.7

 

1.6

 

Debt to debt plus shareholders’ equity (7) 

 

62

%

62

%

 62

%

65

%

67

%

Total shareholder return (8)

 

11

%

27

%

21

%

21

%

48

%

Earnings to fixed charges (9)

 

2.5

 

2.3

 

2.3

 

2.1

 

1.9

 

Earnings to fixed charges (per U.S. GAAP) (10)

 

2.4

 

2.1

 

2.1

 

2.0

 

1.9

 

 

(1)     As at December 31.

(2)     The ratio of return on average common shareholders’ equity is determined by dividing net income by average common shareholders’ equity (i.e. opening plus closing shareholders’ equity divided by 2) for each year.

(3)     The ratio of dividend yield is determined by dividing dividends declared during the year by price per share as at December 31.

(4)     Price per share refers to market price per share as reported on the Toronto Stock Exchange as at December 31.

(5)     The price/earnings multiple is determined by dividing price per share by the basic net income per share.

(6)     The price/book multiple is determined by dividing price per share by book value per share as calculated by dividing shareholders’ equity by the number of shares outstanding as at December 31.

(7)     Debt includes total long-term debt plus preferred securities as at December 31 and excludes non-recourse debt of joint ventures. Shareholders’ equity in this ratio is at December 31.

(8)     Total shareholder return is the sum of the change in price per share plus the dividends received plus the impact of dividend re-investment in a calendar year, expressed as a percentage of the value of shares at the end of the previous year.

(9)     The ratio of earnings to fixed charges is determined by dividing the income from continuing operations before financial charges and income taxes, excluding undistributed income from equity investees by the financial charges incurred by the company (including capitalized interest).

(10)   The ratio is determined in the manner described in (9) above, but utilizing similar information determined in accordance with U.S. GAAP. Differences are described in Note 22 to the consolidated financial statements “U.S. GAAP.”

 

109


 

INVESTOR INFORMATION

 

Stock Exchanges, Securities and Symbols

 

TransCanada Corporation

 

Common shares are listed on the Toronto and New York stock exchanges under the symbol: TRP

 

TransCanada PipeLines Limited (TCPL)*

 

Preferred shares are listed on the Toronto Stock Exchange under the following symbols:

 

Cumulative redeemable first preferred Series U: TCA.PR.X and Series Y: TCA.PR.Y

 

8.25% Preferred Securities are listed on the New York Stock Exchange under the following symbol: TCAPr

 

16.50% First Mortgage Pipe Line Bonds due 2007 are listed on the London Stock Exchange

 

NOVA Gas Transmission Ltd. (NGTL)*

 

7.875% Debentures are listed on the New York Stock Exchange under the symbol: NVA 23

 

* TransCanada PipeLines Limited (TCPL) and Nova Gas Transmission Ltd. (NGTL) are wholly-owned subsidiaries of TransCanada Corporation.

 

Annual Meeting The annual meeting of shareholders is scheduled for April 29, 2005 at 10:30 a.m. (Mountain Daylight Time) at the Roundup Centre, Calgary, Alberta.

 

Dividend Payment Dates Scheduled common share dividend payment dates in 2005 are January 31, April 29, July 29 and October 31.

 

Dividend Reinvestment and Share Purchase Plan TransCanada’s dividend reinvestment and share purchase plan allows common shareholders of TransCanada and preferred shareholders of TCPL to purchase additional common shares by reinvesting their cash dividends without incurring brokerage or administrative fees. Participants in the Plan may also buy additional common shares, of up to $10,000 (US$7,000) per quarter. Please contact our Plan agent, Computershare Trust Company of Canada, for more information on the Plan or visit us at www.transcanada.com.

 

TRANSFER AGENTS, REGISTRARS AND TRUSTEE

 

TransCanada Corporation Common Shares Computershare Trust Company of Canada (Montreal, Toronto, Winnipeg, Calgary and Vancouver) and Computershare Trust Company (New York)

 

TCPL Preferred Shares Computershare Trust Company of Canada (Montreal, Toronto, Winnipeg, Calgary and Vancouver)

 

TCPL Preferred Securities The Bank of New York (New York)

 

TCPL First Mortgage Pipe Line Bonds CIBC Mellon Trust Company, as agent for National Trust Company (Toronto). Co-Registrar and Paying Agent U.K. Series, 16.50%: Computershare Services plc (London, England)

 

TCPL Debentures Canadian Series: CIBC Mellon Trust Company (Halifax, Montreal, Toronto, Winnipeg, Regina, Calgary and Vancouver)

 

11.10% series N

10.50% series O

10.50% series P

10.625% series Q

11.85% series R

11.90% series S

11.80% series U

9.80% series V

9.45% series W

 

U.S. Series: The Bank of New York (New York) 9.875% and 8.625%

 

TCPL Subordinated Debentures The Bank of Nova Scotia Trust Company of New York (New York)

 

U.S. Series 9.125%

 

TCPL Canadian Medium Term Notes CIBC Mellon Trust Company (Halifax, Montreal, Toronto, Winnipeg, Regina, Calgary and Vancouver)

 

110


 

TCPL U.S. Medium Term Notes (unsubordinated notes) and Senior Notes The Bank of New York (New York)

 

NGTL Debentures

 

Canadian series: CIBC Mellon Trust Company (Halifax, Montreal, Toronto, Winnipeg, Regina, Calgary and Vancouver)

 

11.95% series 13

11.70% series 15

11.20% series 18

12.625% series 19

12.20% series 20

12.20% series 21

9.90% series 23

 

U.S. Debentures: U.S. Bank Trust National Association Series (New York) 8.50% and 7.875%

 

NGTL Canadian Medium Term Notes CIBC Mellon Trust Company (Halifax, Montreal, Toronto, Winnipeg, Regina, Calgary and Vancouver)

 

NGTL U.S. Medium Term Notes U.S. Bank Trust National Association (New York)

 

REGULATORY FILINGS

 

Annual Information Form TransCanada’s 2004 Renewal Annual Information Form, as filed with Canadian securities commissions and as filed under Form 40-F with the SEC, is available on our web site at www.transcanada.com. A printed copy may be obtained from:

 

Corporate Secretary, TransCanada Corporation, P.O. Box 1000, Station M, Calgary, Alberta, Canada T2P 4K5

 

SHAREHOLDER ASSISTANCE

 

If you are a registered shareholder and have questions regarding your account, please contact our transfer agent in writing, by telephone, fax or e-mail at:

 

Computershare Trust Company of Canada, 100 University Avenue, 9th Floor, Toronto, Ontario, Canada M5J 2Y1

 

Toll-free: 1 (800) 340-5024

Fax:

1 (888) 453-0330 (North America)

Telephone: 1 (514) 982-7959

Fax:

1 (416) 263-9394 (outside North America)

E-mail: transcanada@computershare.com

 

 

If you hold your shares in a brokerage account (beneficial shareholder), questions should be directed to your broker on all administrative matters.

 

If you would like to receive quarterly reports, please contact Computershare or visit us at our web site.

 

Electronic Proxy Voting and Delivery of Documents We will continue the electronic proxy solicitation and voting and electronic delivery of documents program (annual report, management information circular, notice of meeting and view-only proxy form) for registered and beneficial shareholders in 2005.

 

Shareholders can now choose whether or not to receive TransCanada’s annual report by regular mail. Each year, shareholders are required to renew their option and will receive a notification for doing so. The annual report is available on the TransCanada website at www.transcanada.com/investor/financial.html at the same time that the report is mailed to shareholders.

 

This will provide increased convenience to shareholders, benefits to the environment and reduced mailing and printing costs for the Corporation.

 

TransCanada in the Community Copies of the 2004 Corporate Social Responsibility Report, and 2004 Climate Change and Air Issues Annual Report, are available at www.transcanada.com. If you would like to receive a copy of either of these reports by mail, please contact:

 

Communications and Government Relations P.O. Box 1000, Station M, Calgary, Alberta T2P 4K5, 1 (403) 920-2000

 

Visit us on our website to access TransCanada’s corporate and financial information, including quarterly reports, news releases, real-time conference call webcasts and investor presentations. Visit us at www.transcanada.com 

 

Si vous désirez vous procurer un exemplaire de ce rapport en français, veuillez consulter notre site web ou vous adresser par écrit à TransCanada Corporation, bureau du secrétaire.

 

111


 

BOARD OF DIRECTORS

 

Richard F. Haskayne, O.C., F.C.A.*

Chairman

TransCanada Corporation

Calgary, Alberta

 

Harold N. Kvisle, P. Eng.

President and CEO

TransCanada Corporation

Calgary, Alberta

 

Douglas D. Baldwin, P. Eng. (1) (3)

Corporate Director

Calgary, Alberta

 

Wendy K. Dobson (2) (4)

Professor, Rotman School of Management and Director,

Institute for International Business

University of Toronto

Uxbridge, Ontario

 

The Hon. Paule Gauthier, P.C., O.C., O.Q., Q.C. (1) (3)

Senior Partner

Desjardins Ducharme Stein Monast

Québec, Québec

 

Kerry L. Hawkins (3) (4)

President

Cargill Limited

Winnipeg, Manitoba

 

S. Barry Jackson** (1) (4)

Chairman

Resolute Energy Inc.

Deer Creek Energy Limited

Calgary, Alberta

 

Paul L. Joskow (1) (2)

Professor, Department of Economics

Massachusetts Institute of Technology

Cambridge, Massachusetts

 

David P. O’Brien (2) (4)

Chairman

EnCana Corporation

Calgary, Alberta

 

James R. Paul (2) (3)

Chairman

James and Associates

Kingwood, Texas

 

Harry G. Schaefer, F.C.A. (1) (2)

President

Schaefer & Associates Ltd. and Vice-Chairman

TransCanada Corporation

Calgary, Alberta

 

W. Thomas Stephens (3) (4)

Chairman and CEO

Boise Cascade LLC

Boise, Idaho

 

*       Non-voting member of all committees of the Board

**     Chair-elect

(1)     Member, Audit Committee

(2)     Member, Governance Committee

(3)     Member, Health, Safety and Environment Committee

(4)     Member, Human Resources Committee  

 

Corporate Governance Please refer to TransCanada’s Notice of 2005 Annual Meeting of Common Shareholders and Management Proxy Circular for the Company’s report on corporate governance. TransCanada’s Corporate Governance Guidelines, Board charter, Committee charters, and codes of business conduct and ethics are available on our web site at www.transcanada.com. Also available on our web site is a summary of the significant ways in which TransCanada’s corporate governance practices differ from those required to be followed by U.S. domestic companies under the New York Stock Exchange’s listing standards.

 

Additional information relating to the company is filed with securities regulators in Canada on SEDAR at www.sedar.com and in the United States on EDGAR at www.sec.gov. The documents referred to in this Annual Report may be obtained free of charge by contacting TransCanada’s Corporate Secretary at P.O. Box 1000, Station M, Calgary, Alberta, Canada T2P 4K5, or by telephoning
1 (403) 920-2000.

 

Ethics Help-Line The Audit Committee of the Board of Directors has established an anonymous and confidential toll-free telephone number for employees, contractors and others to call with respect to accounting irregularities and ethical violations. The Ethics Help-Line number is 1 (888) 920-2042.

 

112


 

EXECUTIVE OFFICERS

 

 

 

 

 

 

 

 

 

 

 

Harold N. Kvisle

President and
Chief Executive Officer

 

Albrecht W.A. Bellstedt, Q.C.

Executive Vice-President,
Law and General Counsel

 

Russell K. Girling

Executive Vice-President,
Corporate Development
and Chief Financial Officer

 

Dennis J. McConaghy

Executive Vice-President,
Gas Development

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Alexander J. Pourbaix

Executive Vice-President,
Power

 

Sarah E. Raiss

Executive Vice-President,
Corporate Services

 

Ronald J. Turner

Executive Vice-President,
Gas Transmission

 

Donald M. Wishart

Executive Vice-President,
Operations & Engineering

 

Metric Conversion Table

 

Metric

 

Imperial

 

Factor

 

Kilometres

 

miles

 

0.62

 

Millimetres

 

inches

 

0.04

 

Gigajoules

 

million British thermal units

 

0.95

 

cubic metres*

 

cubic feet

 

35.3

 

degrees Celsius

 

degrees Fahrenheit

 

Multiply by 1.8, then add 32 degrees. To convert
to Celsius, subtract 32 degrees, then divide by 1.8

 

 

* The conversion is based on natural gas at a base pressure of 101.325 kilopascals and a base temperature of 15 degrees Celsius.

 

TRANSCANADA CORPORATION

 

TransCanada Tower, 450 – First Street SW, Calgary, Alberta T2P 5H1 1 (403) 920-2000

TransCanada welcomes questions from shareholders and investors. Please contact:

David Moneta, Director, Investor Relations at 1 (800) 361-6522 (Canada and U.S. Mainland)

Visit TransCanada’s web site at www.transcanada.com

 

Please recycle  Printed in Canada March 2005

Designed and produced by smith + associates www.smithandassoc.com

 


 

Our 41,000 kilometre (25,600 mile) pipeline system links the rich natural gas resources of the Western Canada Sedimentary Basin – one of North America’s largest, most cost-competitive sources of natural gas – to markets across Canada and the United States. Including facilities that are under construction or in development, TransCanada owns, operates and/or controls approximately 5,700 megawatts of power generation – enough electricity to meet the needs of about 5.7 million average households. Our 2,450 employees give us a strong competitive advantage because of their industry-leading expertise in pipeline and power operations, project management, depth of market and industry knowledge and financial acumen. Our strategy has five focused elements that are helping us achieve solid performance, creating value for our shareholders today and in the future.

 

 

 


 

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 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, 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.

 

 

 

 

/s/ KPMG LLP

 

Chartered Accountants

 

 

Calgary, Canada

February 28, 2005

 

 



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SIGNATURES
TRANSCANADA CORPORATION RENEWAL ANNUAL INFORMATION FORM MARCH 7, 2005
TABLE OF CONTENTS
PRESENTATION OF INFORMATION
FORWARD-LOOKING INFORMATION
REFERENCE INFORMATION
TRANSCANADA CORPORATION
GENERAL DEVELOPMENT OF THE BUSINESS
BUSINESS OF TRANSCANADA
HEALTH, SAFETY AND ENVIRONMENT
LEGAL PROCEEDINGS
TRANSFER AGENT AND REGISTRAR
INTEREST OF EXPERTS
RISK FACTORS
DIVIDENDS
DESCRIPTION OF CAPITAL STRUCTURE
RATINGS
MARKET FOR SECURITIES
DIRECTORS AND OFFICERS
CORPORATE GOVERNANCE
ADDITIONAL INFORMATION
GLOSSARY
SCHEDULE "A"
SCHEDULE "B" CHARTER OF THE AUDIT COMMITTEE
PART II Specific Mandate of Committee