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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, 2006

Commission File Number 1-8887

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

Canada
(Jurisdiction of incorporation or organization)

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

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

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

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

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

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

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

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

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, 2006, 4,000,000 Cumulative Redeemable First Preferred Shares Series U
and 4,000,000 Cumulative Redeemable First Preferred Shares Series Y
were issued and outstanding
All of the Registrant's common shares are owned by TransCanada Corporation.

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

Yes                            No           X          

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           X             No                         

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 70 through 110 of the TransCanada PipeLines Limited ("TCPL") 2006 Management's Discussion and Analysis and Audited Consolidated Financial Statements included herein. See the related supplementary note entitled "Reconciliation to United States GAAP" for a reconciliation of the differences between Canadian and United States generally accepted accounting principles, including the auditors' report attached as document 13.4.

B.
Management's Discussion & Analysis

        For management's discussion and analysis, see pages 2 through 69 of TCPL's 2006 Management's Discussion and Analysis and Audited Consolidated Financial Statements included herein.

        For the purposes of this Report, only pages 2 through 69 and 70 through 110 of the TCPL 2006 Management's Discussion and Analysis and Audited Consolidated Financial Statements shall be deemed incorporated herein by reference and filed, and the balance of such 2006 Management's Discussion and Analysis and Audited Consolidated Financial Statements, except as otherwise specifically incorporated by reference in the TCPL Annual Information Form, shall be deemed not filed with the Securities and Exchange Commission as part of this Report under the Exchange Act.

C.
Management's Annual Report on Internal Control Over Financial Reporting

        For information on management's internal control over financial reporting, see "Report of Management" included in TCPL's consolidated audited financial statements on page 70, the section entitled "Management's Annual Report on Internal Control over Financial Reporting" under the heading "Controls and Procedures" in Management's Discussion and Analysis on page 62 of TCPL's Management's Discussion and Analysis and Audited Consolidated Financial Statements, and Management's Report on Internal Control Over Financial Reporting filed as document 13.5.

        Management's assessment of the effectiveness of TCPL's internal control over financial reporting as of December 31, 2006 has been audited by TCPL's independent auditors, KPMG LLP, a registered public accounting firm, as stated in their audit report on management's assessment. KPMG LLP has issued a report on the effectiveness of internal control over financial reporting as of December 31, 2006 filed as document 13.6.

UNDERTAKING

        The Registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the staff of the U.S. Securities and Exchange Commission (the "Commission"), 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

        For information on disclosure controls and procedures, see "Controls and Procedures" in Management's Discussion and Analysis on page 62 of TCPL's 2006 Management's Discussion and Analysis and Audited Consolidated Financial Statements.

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 designated an 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 Commission 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, its President and Chief Executive Officer, Chief 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 2006 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 2006 and 2005 fiscal years are shown in the table below:

Fees in millions of Canadian dollars
  2006
   2005
Audit Fees   $ 4.94   $ 3.15
   
 
Audit-Related Fees     0.07     0.11
   
 
Tax Fees     0.22     0.12
   
 
All Other Fees     0.07     0.14
   
 
Total   $ 5.30   $ 3.52
   
 

        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 TransCanada group of companies' 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 certain pension plans.

Tax Fees

        Tax fees were primarily incurred for tax compliance and tax advice. These services consisted of: tax compliance including the review of Canadian and US income tax returns and tax items and tax services related to domestic and international taxation including income tax, capital tax and Goods and Services 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

        TCPL'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. For engagements of $25,000 CDN or less which are not within the annual pre-approved limit approval by the Audit Committee is not required, 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 CDN 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 involving the external auditor on an engagement, the Audit Committee Chair must pre-approve the assignment.

        To date, TCPL 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.

OFF-BALANCE SHEET ARRANGEMENTS

        The Registrant has no off-balance sheet arrangements, as defined in this Form, other than the guarantees described in Note 22 of the Notes to the Audited Consolidated Financial Statements attached to this Form 40-F and incorporated herein by reference.

TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

        For information on Tabular Disclosure of Contractual Obligations, see "Management's Discussion and Analysis — Contractual Obligations", which is incorporated herein by reference on page 52 of TCPL's 2006 Management's Discussion and Analysis and Audited Consolidated Financial Statements.

IDENTIFICATION OF THE AUDIT COMMITTEE

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

Chair:
Members:		   H.G. Schaefer
D.H. Burney
K.E. Benson
P. Gauthier
P.L. Joskow
J.A. MacNaughton

FORWARD-LOOKING INFORMATION

        This document, documents incorporated herein by reference, and other reports and filings made with the securities regulatory authorities contain certain information that is forward-looking and is subject to important risks and uncertainties. The words "anticipate", "expect", "may", "should", "estimate", "project", "outlook", "forecast" or other similar words are used to identify such forward looking information. All forward-looking statements are based on TCPL's beliefs and assumptions based on information available at the time such statements were made. The results or events predicted in this information may differ from actual results or events. Factors which could cause actual results or events to differ materially from current expectations include, among other things, the ability of TCPL to successfully implement its strategic initiatives and whether such strategic initiatives will yield the expected benefits, the availability and price of energy commodities, regulatory decisions, changes in environmental and other laws and regulations, competitive factors in the pipeline and energy industry sectors, construction and completion of capital projects, access to capital markets, interest and currency exchange rates, technological developments and the current economic conditions in North America. By its nature, such forward-looking information is subject to various risks and uncertainties, including those material risks discussed herein, in TCPL's Annual Information Form filed as document 13.1 hereto and in TCPL's Management's Discussion and Analysis filed as document 13.2 hereto, which could cause TCPL's actual results and experience to differ materially from the anticipated results or other expectations expressed. The material assumptions in making these forward-looking statements are disclosed in TCPL's Management's Discussion and Analysis, filed as document 13.2 hereto, under the headings "TCPL Overview", "TCPL's Strategy", "Outlook", "Pipelines — Opportunities and Developments", "Pipelines — Outlook", "Energy — Opportunities and Developments" and "Energy — Outlook". 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 document or otherwise, and TCPL undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, except as required by law.

SIGNATURES

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

    TRANSCANADA PIPELINES LIMITED

 
 
Per:
/s/  GREGORY A. LOHNES      
GREGORY A. LOHNES
Executive Vice-President and Chief Financial Officer

 
 
 
Date: February 28, 2007

DOCUMENTS FILED AS PART OF THIS REPORT

13.1
Annual Information Form for the year ended December 31, 2006.

13.2
Management's Discussion and Analysis (included on pages 2 through 69 of TCPL's 2006 Management's Discussion and Analysis and Audited Consolidated Financial Statements).

13.3
2006 Consolidated Audited Financial Statements (included on pages 70 through 110 of TCPL's 2006 Management's Discussion and Analysis and Audited Consolidated Financial Statements).

13.4
Related supplementary note entitled "Reconciliation to United States GAAP" and the auditors' report thereon.

13.5
Management's Report on Internal Control Over Financial Reporting.

13.6
Report of Independent Registered Public Accounting Firm on Management's Report on Internal Control Over Financial Reporting.

99.1
Comments by Auditors for United States Readers on Canada – United States 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.

LOGO

TRANSCANADA PIPELINES LIMITED

ANNUAL INFORMATION FORM

February 22, 2007


TABLE OF CONTENTS

    Page
TABLE OF CONTENTS   i
PRESENTATION OF INFORMATION   ii
FORWARD-LOOKING INFORMATION   ii
TRANSCANADA PIPELINES LIMITED   1
  Corporate Structure   1
  Significant Subsidiaries   2
GENERAL DEVELOPMENT OF THE BUSINESS   2
  Developments in the Pipelines Business   2
  Developments in the Energy Business   4
  Recent Developments   7
BUSINESS OF TCPL   7
  Pipelines Business   8
  Regulation   10
  Energy Business   11
  Other Interests   12
HEALTH, SAFETY AND ENVIRONMENT   12
LEGAL PROCEEDINGS AND REGULATORY ACTIONS   13
TRANSFER AGENT AND REGISTRAR   13
INTEREST OF EXPERTS   13
RISK FACTORS   14
DIVIDENDS   14
DESCRIPTION OF CAPITAL STRUCTURE   14
DEBT   15
CREDIT RATINGS   16
MARKET FOR SECURITIES   17
DIRECTORS AND OFFICERS   19
  Directors   19
  Officers   21
CORPORATE GOVERNANCE   22
  Compliance with Canadian Governance Guidelines   22
  Audit Committee   22
  Other Board Committees   24
  Conflicts of Interest   25
INDEBTEDNESS OF DIRECTORS AND EXECUTIVE OFFICERS   25
SECURITIES OWNED BY DIRECTORS   25
COMPENSATION OF DIRECTORS   26
EXECUTIVE COMPENSATION AND OTHER INFORMATION   29
  Report on Executive Compensation   29
  Performance Graph   41
  Remuneration of Executive Officers of TCPL   41
  Executive Compensation   41
  Equity Compensation Plan Information   47
  Pension and Retirement Benefits for Executives   49
  Supplemental Disclosure – Total Compensation Awards   54
ADDITIONAL INFORMATION   56
GLOSSARY   57
SCHEDULE "A"   Metric Conversion Table   A-1
SCHEDULE "B"    Disclosure of Corporate Governance Practices   B-1
SCHEDULE "C"    Charter of The Board of Directors   C-1
SCHEDULE "D"   Description of Board Committees and Their Charters   D-1
SCHEDULE "E"    Charter of the Audit Committee   E-1

TRANSCANADA PIPELINES LIMITED        i

PRESENTATION OF INFORMATION

Unless otherwise noted, the information contained in this Annual Information Form ("AIF") for TransCanada PipeLines Limited ("TCPL") is given at or for the year ended December 31, 2006 ("Year End"). Amounts are expressed in Canadian dollars unless otherwise indicated. Financial information is presented in accordance with Canadian generally accepted accounting principles.

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

 TCPL's Management's Discussion and Analysis dated February 22, 2007 ("MD&A") and TCPL's Audited Consolidated Financial Statements dated February 22, 2007 are incorporated by reference into this AIF and can be found on SEDAR at www.sedar.com under TCPL's profile.

 Information relating to metric conversion can be found at Schedule "A" to this AIF.

FORWARD-LOOKING INFORMATION

This AIF, the documents incorporated by reference into this AIF, and other reports and filings made with the securities regulatory authorities contain certain information that is forward-looking and is subject to important risks and uncertainties. The words "anticipate", "expect", "may", "should", "estimate", "project", "outlook", "forecast" or other similar words are used to identify such forward looking information. All forward-looking statements are based on TCPL's beliefs and assumptions based on information available at the time such statements were made. The results or events predicted in this information may differ from actual results or events. Factors which could cause actual results or events to differ materially from current expectations include, among other things, the ability of TCPL to successfully implement its strategic initiatives and whether such strategic initiatives will yield the expected benefits, the availability and price of energy commodities, regulatory decisions, changes in environmental and other laws and regulations, competitive factors in the pipeline and energy industry sectors, construction and completion of capital projects, access to capital markets, interest and currency exchange rates, technological developments and the current economic conditions in North America. By its nature, such forward-looking information is subject to various risks and uncertainties, including those material risks discussed in this AIF under "Risk Factors" and in the MD&A under "Pipelines – Business Risks" and "Energy – Business Risks", which could cause TCPL's actual results and experience to differ materially from the anticipated results or other expectations expressed. The material assumptions in making these forward-looking statements are disclosed in the MD&A under the headings "TCPL Overview", "TCPL's Strategy", "Outlook", "Pipelines – Opportunities and Developments", "Pipelines – Outlook", "Energy – Opportunities and Developments" and "Energy – Outlook". 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 TCPL undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, except as required by law.

ii        TRANSCANADA PIPELINES LIMITED

TRANSCANADA PIPELINES LIMITED

Corporate Structure

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

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

Date   Event
March 21, 1951   Incorporated by Special Act of Parliament as Trans-Canada Pipe Lines Limited.
April 19, 1972   Continued under the Canada Corporations Act by Letters Patent, which included the alteration of its capital and change of name to TransCanada PipeLines Limited.
June 1, 1979   Continued under the Canada Business Corporations Act.
July 2, 1998   Certificate of Arrangement issued in connection with the Plan of Arrangement with NOVA Corporation ("NOVA") under which the companies merged and then split off the commodity chemicals business carried on by NOVA into a separate public company.
January 1, 1999   Certificate of Amalgamation issued reflecting TCPL's vertical short form amalgamation with a wholly-owned subsidiary, Alberta Natural Gas Company Ltd.
January 1, 2000   Certificate of Amalgamation issued reflecting TCPL's vertical short form amalgamation with a wholly-owned subsidiary, NOVA Gas International Ltd.
May 4, 2001   Restated TransCanada PipeLines Limited Articles of Incorporation filed.
June 20, 2002   Restated TransCanada PipeLines Limited By-Laws filed.
May 15, 2003   Certificate of Arrangement issued in connection with the plan of arrangement with TransCanada. TransCanada was incorporated pursuant to the provisions of the Canada Business Corporations Act on February 25, 2003. The arrangement was approved by TCPL common shareholders on April 25, 2003 and following court approval, Articles of Arrangement were filed making the arrangement effective May 15, 2003. 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.

 At Year End, TCPL had approximately 2,350 employees, substantially all of whom were employed in Canada and the United States.

TRANSCANADA PIPELINES LIMITED 1


Significant Subsidiaries

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

GRAPHIC

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

•
the total assets of the subsidiary do not exceed ten per cent of the consolidated assets of TCPL at Year End;

•
the sales and operating revenues of the subsidiary do not exceed ten per cent of the consolidated sales and operating revenues of TCPL for the year ended December 31, 2006;

•
the aggregate assets of all the excluded subsidiaries do not exceed 20 per cent of the consolidated assets of TCPL at Year End; and

•
the aggregate sales and operating revenues of all the excluded subsidiaries do not exceed 20 per cent of the consolidated sales and operating revenues of TCPL for the year ended December 31, 2006.

GENERAL DEVELOPMENT OF THE BUSINESS

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

 Effective June 1, 2006, TCPL revised the composition and names of its reportable business segments to Pipelines and Energy. Pipelines is principally comprised of the company's pipelines in Canada, the United States and Mexico. Energy includes the company's power operations, natural gas storage business and liquefied natural gas ("LNG") projects in Canada and the United States.

Developments in the Pipelines Business

TransCanada's strategy in pipelines is focused on both growing its North American natural gas transmission network and maximizing the long-term value of its existing pipeline assets. Summarized below are significant developments that have occurred in TCPL's pipelines business over the last three years.

2006

2 TRANSCANADA PIPELINES LIMITED


TRANSCANADA PIPELINES LIMITED 3

 Further information about these developments can be found in this AIF under "General Development of the Business – Recent Developments" and in the MD&A under the heading "TCPL's Strategy – Pipelines" and "Pipelines – Opportunities and Developments".

2005


Regulatory Matters

2004


Developments in the Energy Business

In the past three years, TCPL has grown its energy business and, in particular, has increased its power generation capacity from facilities it owns, operates and/or controls, including those under construction or in development, from approximately 5,700 megawatts ("MW") in 2004 to approximately 7,700 MW at Year End. Summarized below are significant developments that have occurred in TCPL's energy business over the last three years.

2006

4 TRANSCANADA PIPELINES LIMITED

 Further information about each of these energy developments can be found in the MD&A under the heading "TCPL's Strategy – Energy" and "Energy – Opportunities and Developments".

2005

TRANSCANADA PIPELINES LIMITED 5

2004

6 TRANSCANADA PIPELINES LIMITED

Recent Developments

On February 22, 2007, TransCanada closed its acquisitions of ANR and an additional 3.55 per cent interest in Great Lakes from El Paso Corporation for approximately US$3.4 billion, and includes approximately US$488 million of assumed long-term debt. The acquisition of ANR was partially financed through a public offering of subscription receipts by TransCanada, resulting in proceeds of approximately $1.5 billion. For further information see "General Development of the Business – Developments in the Pipelines Business" in this AIF.

 In February 2007, TC PipeLines, LP completed a private placement offering of 17,356,086 units at a price of US$34.57 per unit. TransCanada acquired 50 per cent of the units for US$300 million, increasing its total ownership to 32.1 per cent. TransCanada also invested an additional approximately $12 million to maintain its general partnership ownership interest in TC PipeLines, LP. The total private placement resulted in gross proceeds of approximately US$612 million which were used to partially finance TC PipeLines, LP's acquisition of its 46.45 per cent interest in Great Lakes.

 TCPL received NEB approval on February 9, 2007, to transfer a section of the Canadian Mainline natural gas transmission facilities to the Keystone oil pipeline project to transport crude oil from Alberta to refining centres in the U.S. Midwest. TCPL continues to proceed with applications for U.S. regulatory approvals at federal and state levels. Construction of the Keystone pipeline is expected to begin in early 2008, with commercial operations scheduled to commence in the fourth quarter of 2009. In addition, TCPL announced in January 2007 the start of a binding Open Season for an expansion and extension of the propsed Keystone oil pipeline. The purpose of the Open Season is to obtain binding commitments to support the expansion of the proposed Keystone pipeline from approximately 435,000 barrels per day to 590,000 barrels per day and the construction of the 468 km extension of the United States portion of the pipeline. The US$700 million expansion and extension project is targetted to be in-service in the fourth quarter of 2010.

 In February 2007, TCPL received approval from the NEB to integrate the B.C. system into the Foothills system in southern B.C. An agreement between the Company and shippers on the B.C. system includes a sharing mechanism for anticipated cost savings through increased administrative efficiencies arising from the integration of the two systems.

 In January 2007, TCPL received a procedural order from the FERC establishing a timeline for Gas Transmission Northwest System's rate case proceeding. The comprehensive filing requests a number of tariff changes, including increased rates for transportation services. The hearing into this rate case is scheduled to commence on October 31, 2007. For further information see this AIF under "Business of TCPL – Regulation".

BUSINESS OF TCPL

TCPL is a leading North American energy infrastructure company focused on pipelines and energy. At Year End, Pipelines accounted for approximately 53 per cent of revenues and 71 per cent of TCPL's total assets and the Energy business accounted for approximately 47 per cent of revenues and 25 per cent of TCPL's total assets. The following is a description of each of TCPL's two main areas of operation.

TRANSCANADA PIPELINES LIMITED 7


 The following table shows TCPL's revenues from operations by segment, classified geographically, for the years ended December 31, 2006 and 2005.

Revenues From Operations(millions of dollars)   2006   2005(4)
Pipelines        
  Canada – Domestic Deliveries   2,390   2,281
  Canada – Export Deliveries(1)   971   1,159
  United States   629   553
    3,990   3,993
Energy(2)        
  Canada – Domestic Deliveries   2,566   1,218
  Canada – Export Deliveries(1)   1   1
  United States   963   912
    3,530   2,131
Total Revenues(3)   7,520   6,124
(1)
Export deliveries include pipeline revenues attributable to deliveries to U.S. pipelines and power deliveries to U.S. markets.

(2)
Revenues include sales of natural gas.

(3)
Revenues are attributed to countries based on country of origin of product or service.

(4)
Effective June 1, 2006, TCPL revised the composition and names of its reportable business segments to Pipelines and Energy. The financial reporting of these segments was aligned to reflect the internal organizational structure of the Company. Pipelines principally comprises the Company's pipelines in Canada, the U.S. and Mexico. Energy includes the Company's power operations, natural gas storage business and liquefied natural gas projects in Canada and the U.S. The segmented information has been retroactively reclassified to reflect the changes in reportable segments. These changes had no impact on consolidated net income.

Pipelines Business

TCPL has substantial Canadian and U.S. natural gas pipeline and related holdings, including:

Canada

United States

8 TRANSCANADA PIPELINES LIMITED

 As at February 22, 2007 TCPL holds a 32.1 per cent interest in TC PipeLines, LP, a publicly held limited partnership of which a subsidiary of TCPL acts as the general partner. The remaining interest of TC PipeLines, LP is widely held by the public. At Year End, TC PipeLines, LP also held a 50 per cent interest in NBPL and a 99 per cent interest in Tuscarora. Additionally, as at February 22, 2007, TC PipeLines, LP owns the remaining 46.45 per cent in Great Lakes.

International

TCPL also has the following natural gas pipeline and related holdings in Mexico and South America:

 Further information about TCPL's pipeline holdings, developments and opportunities and significant regulatory developments which relate to pipelines can be found in the MD&A under the headings "Pipelines – Opportunities and Developments", and "Pipelines – Financial Analysis".

 In addition, information about the Mackenzie Gas Pipeline Project and the Alaska Highway Pipeline Project can be found in the MD&A under the headings "Pipelines – Opportunities and Developments – Mackenzie Gas Pipeline Project" and "Pipelines – Opportunities and Developments – Alaska Highway Pipeline Project", respectively.

TRANSCANADA PIPELINES LIMITED 9


Regulation

Canada

CANADIAN MAINLINE

Under the terms of the National Energy Board Act (Canada), the Canadian Mainline and B.C. and Foothills Systems are regulated by the NEB. The NEB sets tolls which provide TCPL the opportunity to recover projected costs of transporting natural gas, including the return on the Canadian Mainline's and B.C. and Foothills System's average investment base. In addition, new facilities are approved by the NEB before construction begins and the NEB regulates the operation of the Canadian Mainline and B.C. and Foothills Systems. Net earnings of the Canadian Mainline and B.C. and Foothills Systems may be affected by changes in investment base, the allowed return on equity, the level of deemed common equity and any incentive earnings.

ALBERTA SYSTEM

The Alberta System is regulated by the Alberta Energy and Utilities Board ("EUB") primarily under the provisions of the Gas Utilities Act ("GUA") and the Pipeline Act. Under the GUA, the Alberta System rates, tolls and other charges, and terms and conditions of services are subject to approval by the EUB. Under the provisions of the Pipeline Act, the EUB oversees various matters including the economic, orderly and efficient development of pipeline facilities, the operation and abandonment of the facilities 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 other provincial legislation such as the Environmental Protection and Enhancement Act.

United States

TCPL's wholly-owned and partially owned U.S. pipelines, including ANR System, Gas Transmission Northwest System, Great Lakes System, Iroquois System, Portland System, NBPL System, North Baja System and Tuscarora System, are 'natural gas companies' operating under the provisions of the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, and are subject to the jurisdiction of the FERC. The Natural Gas Act of 1938 grants the FERC authority over the construction and operation of pipelines and related facilities. The FERC also has authority to regulate rates for natural gas transportation and interstate commerce.

GAS TRANSMISSION NORTHWEST SYSTEM AND NORTH BAJA SYSTEM

Rates and tariffs of the Gas Transmission Northwest System and the North Baja System have been approved by the FERC. These two systems operate under fixed rate models, whereby rates for various service types have been approved by the FERC and under which each of the two systems is permitted to discount or negotiate rates on a non-discriminatory basis. Currently effective rates for mainline capacity on the Gas Transmission Northwest System went into effect on January 1, 2007, following Gas Transmission Northwest System's filing of a general rate case in June 2006 under Section 4 of the Natural Gas Act of 1938. Gas Transmission Northwest System's current rates were accepted for filing by the FERC, subject to refund. Refunds, with interest, may be due following approval of final rates by the FERC. Gas Transmission Northwest System's previously effective rates, which remained in effect through December 31, 2006, were established through a 1994 rate proceeding which culminated in a settlement that was approved by the FERC in 1996. Rates for capacity on the North Baja System were established in the FERC's initial order certificating construction and operations of its system.

PORTLAND SYSTEM

In 2003, the Portland System received final approval from the FERC of its general rate case under the Natural Gas Act of 1938. The Portland System is required to file a general rate case under the Natural Gas Act of 1938 with a proposed effective date of April 1, 2008.

10 TRANSCANADA PIPELINES LIMITED

Energy Business

The Energy segment of TCPL's business includes the acquisition, development, construction, ownership and operation of electrical power generation plants, the purchase and marketing of electricity, the provision of electricity account services to energy and industrial customers, and the development, construction, ownership and operation of natural gas storage and LNG facilities in Canada and the United States.

 The electrical power generation plants and power supply that TCPL owns, operates and/or controls, including those under development or in construction, in the aggregate, represent approximately 7,700 MW of power generation capacity. Power plants and power supply in Canada account for approximately 85 per cent of this total, and power plants in the United States account for the balance, being approximately 15 per cent.

 TCPL owns and operates:

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

 TCPL has:

 TCPL owns, but does not operate:

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

TRANSCANADA PIPELINES LIMITED 11

 Further information about TCPL's energy holdings and significant developments and opportunities relating to energy can be found in the MD&A under the headings "Energy – Financial Analysis" and "Energy – Opportunities and Developments".

Other Interests

Cancarb Limited

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

TransCanada Turbines

TCPL 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

TCPL 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.

HEALTH, SAFETY AND ENVIRONMENT

TCPL is committed to providing a safe and healthy environment for its employees, contractors, the public and to the protection of the environment. Health, safety and environment ("HS&E") is a priority in all of TCPL's operations. The HS&E Committee of TCPL's Board of Directors ("Board") monitors conformance with the TCPL HS&E corporate policy through regular reporting provided by TCPL's department of Community, Safety & Environment. TCPL's senior executives are also committed to ensuring TCPL is in conformance with its policies and regulated requirements and is an industry leader. Senior executives are regularly advised of all important operational issues and initiatives relating to HS&E by way of formal reporting processes. TCPL's HS&E management system and performance 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 conducted in November 2006 by Det Norsk Veritas. These assessments involve senior executive and employee interviews, review of policies, procedures, objectives, performance measurement and reporting.

 TCPL's HS&E management system is modeled to the elements of the International Organization for Standardization's (ISO) standard for environmental management systems, ISO 14001. The HS&E management system facilitates the focus of resources on the areas of significant risk to the organization's HS&E business activities. The system highlights opportunities for improvement, enables TCPL to work towards defined HS&E expectations and objectives, and provides a competitive business advantage. Independent third party assessments, internal management system assessments and work place and facility planned inspections are used to evaluate the implementation effectiveness of the HS&E programs, processes and procedures, and confirms TCPL's compliance with regulatory requirements.

12 TRANSCANADA PIPELINES LIMITED


 TCPL 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 TCPL to date. However, there can be no assurance that such requirements will not have a material impact on TCPL's financial or operating results in future years. Such requirements can be dependent on a variety of factors including the regulatory environment in which TCPL operates.

Environment

Climate change remains a serious issue for TCPL. The change of government in Canada in early 2006 resulted in a shift of focus from meeting environmental regulation targets to a broader emphasis on clean air as well as greenhouse gas emissions. The government of Canada released the Clean Air Act on October 19, 2006. At this time, however, the policy framework for the new regulations has not been released by the federal government and detailed sectoral targets and timeframes as well as compliance options have not been set. At a provincial level, the Québec government has passed legislation for a hydrocarbon royalty on industrial greenhouse gas emitters. The details as to how the royalty will be applied have not yet been determined but it is expected these details will be set in the coming year. In Alberta, the government has indicated it will continue with its own plan for implementing regulations to manage greenhouse gas emissions. It is yet to be determined how this effort will tie into a federal program.

 In the United States, state level initiatives are under way to limit greenhouse gas emissions, particularly in the north-eastern United States and California. Details have not been finalized and the impact to TCPL's United States based assets is uncertain.

 Despite this uncertainty, TCPL continues with its programs to manage greenhouse gas emissions from its assets, and to evaluate new processes and technologies that result in improved efficiencies and lower greenhouse gas emissions rates. In addition, TCPL remains involved in policy discussions in those jurisdictions where policy development is under way and where the Company has operations.

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

The Canadian Alliance of Pipeline Landowners' Association (CAPLA) and two individual landowners commenced an action in 2003 under Ontario's Class Proceedings Act, 1992, against TCPL and Enbridge Inc. for damages of $500 million alleged to arise from the creation of a control zone within 30 metres of the pipeline pursuant to Section 112 of the National Energy Board Act. On November 20, 2006, the Ontario Superior Court granted the motion of TCPL and Enbridge Inc. for a dismissal of the case. CAPLA has now appealed the decision. TCPL continues to believe the claim is without merit and will vigorously defend the action. TCPL has made no provision for any potential liability. Any liability, if any, would be dealt with through the regulatory process.

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

TRANSFER AGENT AND REGISTRAR

TCPL'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

Our auditors, KPMG LLP, have confirmed that they are independent within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta.

TRANSCANADA PIPELINES LIMITED 13

RISK FACTORS

A discussion of the Company's risk factors can be found in the MD&A for the year ended December 31, 2006, which is incorporated by reference, under the headings "Pipelines – Opportunities and Developments", "Pipelines – Business Risks", "Energy – Opportunities and Developments", "Energy – Business Risks" and "Risks and Risk Management".

DIVIDENDS

All of TCPL's common shares are held by TransCanada and as a result, any dividends declared by TCPL on its common shares are paid to TransCanada. TCPL's Board of Directors has not adopted a formal dividend policy. The Board reviews the financial performance of TCPL quarterly and makes a determination of the appropriate level of dividends to be declared on its common shares in the following quarter. 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 and preferred shareholders 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 and preferred shares. In the opinion of TCPL management, such provisions do not currently restrict or alter TCPL's ability to declare or pay dividends.

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

    2006   2005   2004
Dividends declared on common shares(1)   $1.28   $1.23   $1.17
Dividends declared on preferred shares, Series U   $2.80   $2.80   $2.80
Dividends declared on preferred shares, Series Y   $2.80   $2.80   $2.80
(1)
Effective May 15, 2003, TCPL dividends have been declared in an amount equal to the aggregate dividend paid by TransCanada. The amounts presented reflect the aggregate amount divided by the total outstanding common shares of TCPL.

DESCRIPTION OF CAPITAL STRUCTURE

Share Capital

TCPL's authorized share capital consists of an unlimited number of common shares, of which 483,344,109 were issued and outstanding at Year End, and an unlimited number of first preferred shares and second preferred shares, issuable in series. There were 4,000,000 Series U and 4,000,000 Series Y first preferred shares issued and outstanding at Year End. The following is a description of the material characteristics of each of these classes of shares.

Common Shares

As the holder of all of TCPL's common shares, TransCanada holds all the voting rights in those common shares.

First Preferred Shares, Series U

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 holders of the first preferred shares, Series U are entitled to receive as and when declared by the Board, fixed cumulative preferential cash dividends at an annual rate of $2.80 per share, payable quarterly.

 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 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 to TCPL in the event of a liquidation, dissolution or winding up of TCPL.

14 TRANSCANADA PIPELINES LIMITED


 TCPL is entitled to purchase for cancellation, some or all of the first preferred shares, Series U outstanding at the lowest price which such shares are obtainable, in the opinion of the Board, but not exceeding $50.00 per share plus costs of purchase. Furthermore, TCPL may redeem, on or after October 15, 2013, some or all of the first preferred shares, Series U upon payment for each share at $50.00 per share.

 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 unless and until TCPL fails to pay, in the aggregate, six quarterly dividends on the first preferred shares, Series U.

 The provisions attaching to the first preferred shares as a class may be modified, amended or varied only with the approval of the holders of the first preferred shares as a class. Any such approval 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.

First Preferred Shares, Series Y

The rights, privileges, restrictions and conditions attaching to the first preferred shares, Series Y are substantially identical to those attaching to the first preferred shares, Series U except that the first preferred shares, Series Y are redeemable by TCPL after March 5, 2014.

DEBT

The following table sets out the issuances by TCPL of senior unsecured notes with terms to maturity in excess of one year, during the 12 months ended December 31, 2006.

Date Issued   Issue Price per
$1,000 Principal
Amount of Notes		   Aggregate
Issue Price
January 13, 2006   $999.55   $299,865,000
March 20, 2006   US$997.21   US$498,605,000
October 3, 2006   $999.76   $399,904,000

 There are no provisions associated with this debt that entitle debt holders to voting rights. From time to time, TCPL issues commercial paper for terms not exceeding nine months.

TRANSCANADA PIPELINES LIMITED 15


CREDIT RATINGS

The following table sets out the credit ratings assigned to those outstanding classes of securities of TCPL:

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(1)   Stable   Negative
(1)
At February 22, 2007, the DBRS rating was confirmed as stable. At December 31, 2006, the rating was under review. Discussed further in the DBRS section below.

 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 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 TCPL'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 TCPL'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 TCPL'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.

 Subsequent to TransCanada's December 22, 2006 announcement of its plans to acquire ANR, DBRS put TCPL's rating under review with developing implications. On February 22, 2007, DBRS confirmed the rating of TCPL with a stable trend and subsequently removed TCPL's rating from under review.

16 TRANSCANADA PIPELINES LIMITED


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 TCPL'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 TCPL'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 TCPL'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 TCPL's senior secured and senior unsecured debt, respectively, 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 TCPL'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.

MARKET FOR SECURITIES

TransCanada holds all the common shares of TCPL and these are not listed on a public market. 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 2006   40.77   38.95   20,122,013
November 2006   39.14   36.50   21,499,249
October 2006   36.34   33.95   19,350,398
September 2006   35.97   34.65   22,209,089
August 2006   36.35   34.86   22,367,872
July 2006   34.75   31.70   17,073,298
June 2006   34.50   31.55   23,121,387
May 2006   33.50   30.94   30,019,492
April 2006   34.73   33.02   20,961,283
March 2006   35.38   33.67   25,708,683
February 2006   35.25   34.57   21,932,670
January 2006   37.01   34.75   24,218,158

TRANSCANADA PIPELINES LIMITED 17

 In addition, the following securities of TCPL are listed:

TCPL's Cumulative Redeemable First Preferred Shares,
Series U (TCA.PR.X) and Series Y (TCA.PR.Y), which are listed on the TSX

    Series U
   Series Y
Month   High
($)		   Low
($)		   Volume
Traded		   High
($)		   Low
($)		   Volume
Traded
December 2006   55.75   53.55   247,895   55.70   53.85   24,486
November 2006   55.75   54.66   45,230   55.65   54.60   37,280
October 2006   55.25   53.80   72,586   55.30   53.75   93,736
September 2006   53.70   52.80   28,346   54.50   52.70   37,876
August 2006   53.00   52.25   27,981   53.40   52.25   76,794
July 2006   52.90   51.65   28,901   52.49   51.72   150,491
June 2006   53.00   51.32   31,406   53.25   51.55   41,185
May 2006   52.50   51.10   36,962   52.15   51.27   46,570
April 2006   53.50   51.45   38,063   53.50   51.28   34,017
March 2006   54.10   53.30   43,092   54.45   53.55   40,666
February 2006   55.19   53.87   46,321   55.00   54.00   37,332
January 2006   54.25   53.41   32,091   54.85   53.75   24,292

TCPL's 8.25% preferred securities due 2047, which are listed on the NYSE (TCAPr)

Month   High
($)		   Low
($)		   Volume
Traded
December 2006   26.35   25.68   106,700
November 2006   26.15   25.66   120,400
October 2006   26.20   25.76   99,500
September 2006   26.16   25.55   104,800
August 2006   26.06   25.59   77,000
July 2006   25.73   25.46   133,800
June 2006   26.25   25.31   153,500
May 2006   25.49   25.31   136,000
April 2006   25.40   25.21   136,700
March 2006   26.03   25.19   225,300
February 2006   25.90   25.70   97,500
January 2006   25.89   25.60   127,000

18 TRANSCANADA PIPELINES LIMITED

 In addition, TCPL's 16.50% First Mortgage Pipe Line Bonds due 2007, are listed on the London Stock Exchange; however, this issue is thinly traded and accounts for approximately $50 million or less than one per cent of TCPL's consolidated capital structure.

DIRECTORS AND OFFICERS

As of February 22, 2007, the directors and officers of TransCanada as a group beneficially owned, directly or indirectly, have exercisable options to own, or exercised control or direction over, 1,676,238 common shares of TransCanada 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.

Directors

Set forth below are the names of the thirteen directors who served on TCPL'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 director has continually served as a director of TransCanada. 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
Kevin E. Benson(1)
Wheaton, Illinois
United States		   President and Chief Executive Officer, Laidlaw International, Inc. (transportation services) since June 2003, and Laidlaw, Inc. from September 2002 to June 2003. President and Chief Executive Officer, The Insurance Corporation of British Columbia from December 2001 until September 2002. Director, Laidlaw International, Inc.   2005
Derek H. Burney, O.C.
Ottawa, Ontario
Canada		   Senior strategic advisor at Ogilvy Renault LLP (law firm). President and Chief Executive Officer, CAE Inc. (technology) from October 1999 to August 2004. Lead director at Québecor World Inc. (communications and media) from April 2003 to November 2005. Chairman, CanWest Global Communications Corp. and Lead Director, Shell Canada Limited.   2005
Wendy K. Dobson
Uxbridge, Ontario
Canada		   Professor, Rotman School of Management and Director, Institute for International Business, University of Toronto (education). Vice Chair, Canadian Public Accountability Board. Director, Toronto-Dominion Bank.   1992
E. Linn Draper
Lampasas, Texas
United States		   Corporate Director. Chairman, President and Chief Executive Officer of Columbus, Ohio-based American Electric Power Co., Inc. from April 1993 to April 2004. Director, Alliance Data Systems Corporation, Lead Director, Alpha Natural Resources, Inc., Chair of NorthWestern Corporation and Director, Temple-Inland Inc.   2005
The Hon. Paule Gauthier,
P.C., O.C., O.Q., Q.C.
Québec, Québec
Canada		   Senior Partner, Desjardins Ducharme LLP (law firm). Director, Cossette Communication Group Inc., Institut Québecois des Hautes Études Internationales, Laval University, Metro Inc., RBC Dexia Investor Services Trust, Rothmans Inc. and Royal Bank of Canada.   2002
         

TRANSCANADA PIPELINES LIMITED 19

Kerry L. Hawkins
Winnipeg, Manitoba
Canada		   Corporate Director. President, Cargill Limited (agricultural) from September 1982 to December 2005. Director, NOVA Chemicals Corporation and Shell Canada Limited.   1996
S. Barry Jackson
Calgary, Alberta
Canada		   Corporate Director. Chair of the Board, TransCanada since April 2005. Chair of Resolute Energy Inc. (oil and gas) from January 2002 to April 2005 and Chair of Deer Creek Energy Limited (oil and gas) from April 2001 to September 2005. Director, Cordero Energy Inc. and 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 PLC and Putnam Mutual Funds.   2004
Harold N. Kvisle
Calgary, Alberta
Canada		   President and Chief Executive Officer, TransCanada since May 2003 and TCPL since May 2001. Director, Bank of Montreal and PrimeWest Energy Inc. Chair of the Mount Royal College Board of Governors.   2001
John A. MacNaughton, C.M.
Toronto, Ontario
Canada		   Corporate Director. Chairman of the Canadian Trading and Quotation System Inc. Founding President and Chief Executive Officer of the Canadian Pension Plan Investment Board from 1999 to 2005. Director, Nortel Networks Corporation.   2006
David P. O'Brien(2)
Calgary, Alberta
Canada		   Corporate Director. Chair, EnCana Corporation (oil and gas) since April 2002 and Chair, Royal Bank of Canada since February 2004. Chair and Chief Executive Officer of PanCanadian Energy Corporation (oil and gas) from October 2001 to April 2002. Director, Focus Energy Trust, Molson Coors Brewing Company, and C.D. Howe Institute. Chancellor, Concordia University.   2001
Harry G. Schaefer, F.C.A.
Calgary, Alberta
Canada		   President, Schaefer & Associates (business advisory services). Vice-Chair of the Board, TransCanada since May 2003 and TCPL since June 1998. Director, Agrium Inc. and Trustee of Fording Canadian Coal Trust.   1987
D. Michael G. Stewart
Calgary, Alberta
Canada		   Principal of the privately held Ballinacurra Group of Investment Companies since March 2002. A number of senior executive positions with Westcoast Energy Inc. (energy infrastructure, services and utilities) including Executive Vice-President, Business Development from September 1993 to March 2002. Director Canadian Energy Services Inc. and Pengrowth Corporation.   2006
(1)
Mr. Benson was President and Chief Executive Officer of Canadian Airlines International Ltd. from July 1996 to February 2000. Canadian Airlines International Ltd. filed for protection under the Companies' Creditors Arrangement Act (Canada) and applicable bankruptcy protection statutes in the United States on March 24, 2000.

(2)
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.

 TransCanada will hold its annual meeting of common shareholders on Friday, April 27, 2007, and subject to the election of the thirteen nominees proposed for election to TransCanada's board, these directors will be elected by the sole

20 TRANSCANADA PIPELINES LIMITED


shareholder of TCPL as directors of TCPL on that date. Each director holds office until TCPL's next annual meeting or until his or her successor is earlier elected or appointed.

 Mr. Stewart was elected to the Board on April 28, 2006 and Mr. MacNaughton was appointed to the Board on June 14, 2006. In addition, Mr. Schaefer will retire effective April 27, 2007 and Mr. W.T. Stephens has been selected as a new nominee for election. Mr. Stephens previously served on the Board from 2000 to 2005.

Officers

All of the executive officers and corporate officers of TransCanada reside in Calgary, Alberta, Canada. 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:

Executive Officers

Name   Present Position Held   Principal Occupation During the Five Preceding Years
Harold N. Kvisle   President and Chief Executive Officer   President and Chief Executive Officer.
Russell K. Girling   President, Pipelines   Executive Vice-President, Corporate Development and Chief Financial Officer, March 2003 to June 2006. Prior to March 2003, Executive Vice-President and Chief Financial Officer.
Gregory A. Lohnes   Executive Vice-President and Chief Financial Officer   Prior to June 2006, President and Chief Executive Officer of Great Lakes Gas Transmission Company.
Dennis J. McConaghy   Executive Vice-President,
Pipeline Strategy and Development		   Prior to June 2006, Executive Vice-President, Gas Development.
Sean McMaster(1)   Executive Vice-President, Corporate and General Counsel and Chief Compliance Officer   Executive Vice-President, General Counsel and Chief Compliance Officer from October 2006 to January 2007. Prior to October 2006, General Counsel and Chief Compliance Officer. Prior thereto, General Counsel since June 2006. Vice-President, Transactions, Power Division, TCPL from April 2003 to June 2006. President, TransCanada Power Services Ltd., general partner of TransCanada Power LP, from June 2003 to August 2005. Prior to June 2003, Vice-President, Power Services Ltd.
Alexander J. Pourbaix   President, Energy   Executive Vice-President, Power March 2003 to June 2006. Prior to March 2003, Executive Vice-President, Power Development.
Sarah E. Raiss   Executive Vice-President, Corporate Services   Executive Vice-President, Corporate Services.
Donald M. Wishart   Executive Vice-President, Operations and Engineering   Prior to March 2003, Senior Vice-President, Field Operations.
(1)
Mr. McMaster was appointed Executive Vice-President, General Counsel and Chief Compliance Officer on October 30, 2006.

TRANSCANADA PIPELINES LIMITED 21

Corporate Officers

Name   Present Position Held   Principal Occupation During the Five Preceding Years
Ronald L. Cook   Vice-President, Taxation   Prior to April 2002, Director, Taxation.
Donald J. DeGrandis   Corporate Secretary   Prior to June 2006, Associate General Counsel, Corporate.
Garry E. Lamb   Vice-President, Risk Management   Vice-President, Risk Management.
Donald R. Marchand   Vice-President, Finance and Treasurer   Vice-President, Finance and Treasurer.
G. Glenn Menuz   Vice President and Controller   Prior to June 2006, Assistant Controller.

CORPORATE GOVERNANCE

The Board and the members of TCPL's management are committed to the highest standards of corporate governance. TCPL's corporate governance practices comply with the governance rules of the Canadian Securities Administrators ("CSA"), those of the NYSE applicable to foreign issuers and of the U.S. Securities and Exchange Commission ("SEC"), and those mandated by the United States Sarbanes-Oxley Act of 2002 ("SOX"). As a non-U.S. company, TCPL is not required to comply with most of the NYSE corporate governance listing standards; however, except as summarized on its website at www.transcanada.com, the governance practices followed are in compliance with the NYSE standards for U.S. companies in all significant respects. TCPL is in compliance with the CSA's Multilateral Instrument 52-110 pertaining to audit committees. TCPL is also in compliance with the CSA's National Policy 58-201, Corporate Governance Guidelines, and National Instrument 58-101, Disclosure of Corporate Governance Practices (collectively, the "Canadian Governance Guidelines"). In 2005, the Canadian Governance Guidelines came into effect and for purposes of the TSX replaced the TSX Corporate Governance Guidelines. Further information about TCPL's corporate governance can be found on TransCanada's website under the heading "Corporate Governance".

Compliance with Canadian Governance Guidelines

The "Disclosure of Corporate Governance Practices" addressing disclosure in accordance with the Canadian Governance Guidelines is attached to this AIF at Schedule "B". It has been approved by the Governance Committee and the Board.

Audit Committee

TCPL has an Audit Committee which is responsible for assisting the Board in overseeing the integrity of TCPL's financial statements and compliance with legal and regulatory requirements and in ensuring the independence and performance of TCPL's internal and external auditors. The members of the Audit Committee at Year End were Harry G. Schaefer (Chair), Kevin E. Benson, Derek H. Burney, Paule Gauthier, Paul L. Joskow and John A. MacNaughton. Mr. Jackson is a non-voting member of the Audit Committee.

 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,

22 TRANSCANADA PIPELINES LIMITED


apart from their respective roles as directors of TCPL, 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 serves on and 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 certain of those boards. Mr. Schaefer has also held several executive positions with public companies. He is currently Chair of the Audit Committee and of the audit committees of two other public companies.

 Mr. Benson earned a Bachelor of Accounting from the University of Witwatersrand (South Africa) and was a member of the South African Society of Chartered Accountants. Mr. Benson is the President and Chief Executive Officer of Laidlaw International, Inc. In prior years, he has held several executive positions including one as President and Chief Executive Officer of Canadian Airlines International Ltd. and has served on other public company boards.

 Mr. Burney earned a Bachelor of Arts (Honours) and Master of Arts from Queen's University. He is currently a senior strategic advisor at Ogilvy Renault LLP. Mr. Burney previously served as President and Chief Executive Officer of CAE Inc. and as Chairman and Chief Executive Officer of Bell Canada International Inc. Mr. Burney is the lead director at Shell Canada Limited and the Chairman of CanWest Global Communications Corp. He has served on one other organization's audit committee.

 Mme. 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 certain of those boards.

 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 is currently a Professor, Department of Economics, Massachusetts Institute of Technology. He has served on the boards of several public companies and other organizations and on the audit committees of certain of those boards.

 Mr. MacNaughton earned a Bachelor of Arts in Economics from the University of Western Ontario. Mr. MacNaughton is currently the Chairman of Canadian Trading and Quotation System Inc. In prior years, he has held several executive positions including founding President and Chief Executive Officer of the Canadian Pension Plan Investment Board and President of Nesbitt Burns Inc. He is currently the Chair of an audit committee of one other public company.

 The Charter of the Audit Committee can be found in Schedule "E" 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".

Pre-Approval Policies and Procedures

TCPL'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. For engagements of $25,000 or less which are not within the annual pre-approved limit, approval by the Audit Committee is not required, 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 to arise on an engagement, the Audit Committee Chair must pre-approve the assignment.

 To date, TCPL 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.

TRANSCANADA PIPELINES LIMITED 23


External Auditor Service Fees

The aggregate fees for external auditor services rendered by the External Auditor for the TransCanada group of companies for the 2006 and 2005 fiscal years, are shown in the table below:

Fee Category   2006   2005   Description of Fee Category
    (millions of dollars)    
Audit Fees   4.94   3.15   Aggregate fees for audit services rendered by TCPL's External Auditor for the audit of TransCanada's 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   0.07   0.11   Aggregate fees for assurance and related services rendered by TCPL'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 TCPL's certain pension plans.
Tax Fees   0.22   0.12   Aggregate fees rendered by TCPL's External Auditor for primarily tax compliance and tax advice. The nature of these services consisted of: tax compliance including the review of Canadian and U.S. income tax returns; and tax items and tax services related to domestic and international taxation including income tax, capital tax and Goods and Services Tax.
All Other Fees   0.07   0.14   Aggregate fees for products and services other than those reported in this table above rendered by TCPL's External Auditor. The nature of these services consisted of advice with respect to TCPL's compliance with SOX.
Total   5.30   3.52    

Other Board Committees

In addition to the Audit Committee, TCPL has three other Board committees: the Governance Committee, the Health, Safety and Environment Committee and the Human Resources Committee. Mr. Jackson, the Chair of the Board, sits on each of Board's committees as a non-voting member. The voting members of each of these committees, as of Year End, are identified below:

Governance Committee   Health, Safety & Environment Committee   Human Resources Committee

Chair:
 
W.K. Dobson
 
Chair:
 
E.L. Draper
 
Chair:
 
K.L. Hawkins
Members:   D.H. Burney   Members:   P. Gauthier   Members:   W.K. Dobson
    P.L. Joskow       K.L. Hawkins       E.L. Draper
    D.P. O'Brien       D.M.G. Stewart       D.P. O'Brien
    H.G. Schaefer       J.A. MacNaughton        

 The charters of the Governance Committee, the Health, Safety & Environment Committee and the Human Resources Committee can be found on TransCanada's website under the Corporate Governance – Board Committees page at the link specified below.

 Further information about TCPL's Board committees and corporate governance can be found in Schedule "D" attached to this AIF or on TransCanada's website located at: http://www.transcanada.com/company/board_committees.html.

24 TRANSCANADA PIPELINES LIMITED

Conflicts of Interest

Directors and officers of TCPL and its subsidiaries are required to disclose the existence of existing or potential conflicts in accordance with TCPL policies governing directors and officers and in accordance with the Canada Business Corporations Act. Although some of the directors sit on boards or may be otherwise associated with companies that ship natural gas on TCPL's pipeline systems, TCPL as a common carrier in Canada cannot, under its tariff, deny transportation service to a credit-worthy shipper. Further, due to the specialized nature of the industry, TCPL believes that it is important for its Board to be composed of qualified and knowledgeable directors, so some of them must come from oil and gas producers and shippers; the Governance Committee closely monitors relationships among directors to ensure that business associations do not affect the Board's performance. In a circumstance where a director declares an interest in any material contract or material transaction being considered at a meeting, the director generally absents himself or herself from the meeting during the consideration of the matter, and does not vote on the matter.

INDEBTEDNESS OF DIRECTORS AND EXECUTIVE OFFICERS

As at the date hereof and since the beginning of the most recently completed financial year, no executive officer, director, or former executive officer or director of TCPL or its subsidiaries, no proposed nominee as a director of TCPL, or any associate of any such director, executive officer or proposed nominee has been indebted to TCPL or any of its subsidiaries. There is no indebtedness of any such person to another entity that is the subject of a guarantee, support agreement, letter of credit or other similar arrangement or understanding provided by TCPL or any of its subsidiaries.

SECURITIES OWNED BY DIRECTORS

The following table sets out the number of each class of securities of TransCanada or any of its affiliates beneficially owned, directly or indirectly, or over which control or direction is exercised and the number of deferred share units credited to each director, as of February 22, 2007.

Director   Securities
Owned,
Controlled or
Directed(1)		   Deferred Share
Units(2)
K. Benson   3,000   7,857
D. Burney   1,000   7,310
W. Dobson   3,000   29,584
E.L. Draper   0   7,647
P. Gauthier   1,000   21,314
K. Hawkins   3,898 (3) 32,875
S.B. Jackson   39,000   13,931
P.L. Joskow   5,000   10,423
H. Kvisle   607,516 (4) 0
J. MacNaughton   30,000   3,464
D. O'Brien   18,771   21,314
H. Schaefer   23,214 (5) 20,208
D.M.G. Stewart   7,500 (6) 3,026

TRANSCANADA PIPELINES LIMITED 25

(1)
The information as to shares beneficially owned or over which control or direction is exercised, not being within the knowledge of TransCanada, has been furnished by each of the nominees. Except as indicated in these notes, the nominees have sole voting and dispositive power with respect to the securities listed above. As to each class of shares of TransCanada, its subsidiaries and affiliates, the percentage of outstanding shares beneficially owned by any one director or nominee or by all directors and officers of TransCanada as a group does not exceed 1% of the class outstanding.

(2)
The value of a deferred share unit is tied to the value of TransCanada's common shares. A deferred share unit is a bookkeeping entry, equivalent to the value of a TransCanada common share, and does not entitle the holder to voting or other shareholder rights, other than the accrual of additional deferred share units for the value of dividends. A director cannot redeem deferred share units until the director ceases to be a member of the Board. Canadian directors can then redeem their units for cash or shares while U.S. directors can only redeem their units for cash. Mr. Kvisle is an employee of TransCanada and participates is the ESU program; he does not participate in the DSU program.

(3)
The shares listed include 2,500 shares held by Mr. Hawkins' wife.

(4)
Securities owned, controlled or directed include common shares that Mr. Kvisle has a right to acquire through the exercise of stock options that are vested under the Stock Option Plan, which is described elsewhere in this AIF. Directors as such do not participate in the Stock Option Plan. Mr. Kvisle, as an employee of TransCanada, has the right to acquire 474,500 common shares under vested stock options, which amount is included in this column.

(5)
The shares listed do not include 700 common shares held by Mr. Schaefer's wife and 5,500 common shares held by a company controlled by Mr. Schaefer's wife. Mr. Schaefer disclaims beneficial ownership of, or control or direction over, such shares.

(6)
The shares listed include 500 shares held by Mr. Stewart's wife.

COMPENSATION OF DIRECTORS

Unless as otherwise defined in the following sections, all capitalized terms used from herein shall have the same meaning ascribed to them in TransCanada's Management Proxy Circular (the "Proxy Circular"), dated February 22, 2007.

 TransCanada's directors also serve as directors of TCPL. An aggregate fee is paid for serving on the Boards of TransCanada and TCPL. Since TransCanada does not hold any assets directly, other than the common shares of TCPL and receivables from certain of TransCanada's subsidiaries, all directors' costs are assumed by TCPL according to a management services agreement between the two companies. The meetings of the boards and committees of TransCanada and TCPL run concurrently.

Minimum Share Ownership Guidelines

The Board believes that directors can more effectively represent the interests of shareholders if they have a significant investment in the common shares of TransCanada, or their economic equivalent. As a result, TransCanada requires each director (other than Mr. Kvisle who is subject to executive share ownership guidelines) to acquire and hold a minimum number of common shares, or their economic equivalent, equal in value to five times the director's annual cash retainer fee. Directors have a maximum of five years to reach this level of ownership. The level of ownership can be achieved by direct purchase of common shares, by participation in the TransCanada Dividend Reinvestment Plan or by means of directing cash retainer fees (or any other fees subsequent to January 1, 2007) into, or otherwise acquiring deferred share units ("DSUs") under, the Share Unit Plan for Non-Employee Directors (1998) (the "DSU Plan"), described under the heading "Share Unit Plan for Non-Employee Directors" below.

 All of the current directors have achieved the minimum share ownership.

26 TRANSCANADA PIPELINES LIMITED


Board and Committee Remuneration

TCPL's director compensation practices are designed to reflect the size and complexity of TCPL and to reinforce the emphasis TCPL places on shareholder value by linking a portion of directors' compensation to the value of TransCanada's common shares. The market competitiveness of director compensation is assessed against the Comparator Group (as defined under the heading "Executive Compensation and Other Information – Report on Executive Compensation") and a general industry sample of Canadian companies of similar size and scope to TCPL.

 For the financial year ended December 31, 2006, each director who was not an employee of TCPL, other than the Chair, was paid in quarterly installments in arrears as follows:

Retainer fee   $30,000 per annum
Committee retainer fee   $3,000 per annum
Committee Chair retainer fee   $4,000 per annum
Board and Committee attendance fee   $1,500 per meeting
Committee Chair attendance fee   $1,500 per meeting

 The Chair, who was paid none of the directors' fees outlined above, was paid a retainer fee of $300,000 per annum in respect of his duties as Chair, $3,000 per chaired Board meeting, and was reimbursed for certain office and other expenses. Half of Mr. Jackson's retainer fee for acting as Chair was paid in DSUs. The Vice-Chair was paid a retainer fee of $12,000 per annum in respect of his duties as Vice-Chair, in addition to his other director's fees as outlined above. Each committee chair is entitled to claim a per diem for time spent on committee activities outside of the committee meetings. Additionally, directors other than the Chair and the CEO receive, in respect of their service as directors, an annual grant of units under the DSU Plan, see "Share Unit Plan for Non-Employee Directors" below for details on this plan. Fees are paid quarterly and are pro-rated from the date of the director's appointment to the Board and the relevant committees.

 TCPL pays a travel fee of $1,500 per meeting for which round trip travel time exceeds three hours, and reimburses the directors for out-of-pocket expenses incurred in attending such meetings.

 Directors who are U.S. residents are paid the same amounts as outlined above in U.S. dollars.

Fees Paid to Directors in 2006

The following table sets out the total fees paid in cash and the value of the DSUs awarded or credited for each non-employee director in 2006 as at the date of the grant, unless otherwise stated. Mr. Kvisle, as an employee of TCPL, receives no cash fees or DSUs as a director.

 Directors generally direct their retainer fee to be paid in DSUs until the minimum share ownership guideline is reached, and are always entitled to direct their retainer fee (and, subsequent to January 1, 2007, any other fees) to be paid in DSUs. In 2006, K.E. Benson, D.H. Burney, E.L. Draper, P. Gauthier, K.L. Hawkins, J.A. MacNaughton and D.P. O'Brien received their retainer fees in DSUs and half of Mr. Jackson's retainer fee for acting as Chair was paid in DSUs. For

TRANSCANADA PIPELINES LIMITED 27


further information on the DSU Plan, see the description under the heading "Share Unit Plan for Non-Employee Directors" below.

Name   Board Retainer Fee   Committee Retainer Fee   Committee Chair Retainer Fee   Board Attendance Fee   Committee Attendance Fee   Travel
Fee		   Strategic Issues and Strategic Planning Sessions   Total Fees Paid in Cash   Total Value of DSUs Credited(2)   Total Cash and Value of DSUs Credited
D.D. Baldwin(3)(4)   $15,000   $3,000   $2,000   $4,500   $6,000   $0   $1,500   $32,000   $0   $32,000
K.E. Benson(5)   30,000   3,000   N/A   15,000   9,000   13,500   4,500   45,000   136,290   181,290
D.H. Burney   30,000   5,250   N/A   12,000   6,000   10,500   4,500   38,250   136,290   174,540
W.K. Dobson(3)   30,000   6,000   4,000   16,500   12,000   9,000   6,000   83,500   106,290   189,790
E.L. Draper(3)(5)(6)   30,000   6,000   3,000   16,500   15,000   12,000   6,000   58,500   136,290   194,790
P. Gauthier(3)(6)   30,000   6,000   N/A   16,500   16,500   10,500   6,000   55,500   136,290   191,790
K.L. Hawkins(3)   30,000   6,000   4,000   15,000   16,500   10,500   6,000   58,000   136,290   194,290
S.B. Jackson(6)(7)   300,000   N/A   N/A   33,000   1,500   4,500   4,500   193,500   150,000   343,500
P.L. Joskow(5)   30,000   6,000   N/A   16,500   12,000   10,500   6,000   81,000   106,290   187,290
J.A. MacNaughton   22,500   4,500   N/A   10,500   6,000   4,500   1,500   33,264   122,526   155,790
D.P. O'Brien   30,000   6,000   N/A   13,500   4,500   1,500   1,500   27,000   136,290   163,290
H.G. Schaefer(3)(8)   42,000   6,000   4,000   16,500   21,000   3,000   6,000   98,500   106,290   204,790
D.M.G. Stewart(6)   22,500   2,250   N/A   12,000   3,000   6,000   3,000   48,750   106,290   155,040
(1)
Fees are aggregate amounts respecting duties performed on both TransCanada and TCPL Boards.

(2)
Total DSUs credited includes the amount of the retainer fee elected to be received in DSUs and the grant of 3,000 DSUs made in September 2006 which had an initial cash value of approximately $35.43 per DSU.

(3)
The committee chair retainer fee amount includes per diem fees paid in addition to the committee retainer fee in respect of duties performed and meetings held in preparation for committee meetings. Mme. Gauthier chaired one meeting of the Health, Safety and Environment Committee in Mr. Baldwin's absence.

(4)
Mr. Baldwin retired from the Board on April 28, 2006.

(5)
U.S. directors are paid or credited these amounts, including DSU equivalents, based on U.S. dollars.

(6)
The committee attendance fee includes the amount of $1,500 for a Health, Safety and Environment Committee off-site facility visit.

(7)
Mr. Jackson's Board attendance fee includes the fee of $3,000 in respect of each Board meeting chaired. Half of Mr. Jackson's retainer fee for acting as Chair was paid in DSUs.

(8)
Mr. Schaefer's retainer fee amount includes the fee of $12,000 in respect of duties performed as Vice-Chair.

Share Unit Plan for Non-Employee Directors

The Share Unit Plan for Non-Employee Directors (1998) was established in 1998 and was last amended and restated effective January 1, 2007. Prior to the January 1, 2007 amendment, the DSU Plan allowed eligible Board members, on a quarterly basis, to direct their annual directors' retainer fee or, at the discretion of the Governance Committee, other Board-related fees, to acquire units representing the right to acquire common shares or their cash equivalent. Subsequent to January 1, 2007, Board members are permitted to elect to receive any portion of their fees in DSUs. The DSU Plan also allows the Governance Committee to grant units as additional directors' compensation. In September 2006, a grant of 3,000 DSUs was made to each director other than the Chair and the CEO.

28 TRANSCANADA PIPELINES LIMITED

 Initially the value of a DSU is equal to the market value of a common share at the time the directors are credited with the units. Thus each grant of 3,000 DSUs in September 2006 had an initial cash value of approximately $106,290. The value of a DSU, when redeemed, is equivalent to the market value of a common share at the time the redemption takes place. In addition, at the time dividends are declared and paid on the common shares, each DSU accrues an amount equal to such dividends, which amount is then reinvested in additional DSUs at a price equal to the then market value of a common share. DSUs cannot be redeemed until the director ceases to be a member of the Board. Canadian directors may redeem for cash or common shares at their option. U.S. directors may only redeem for cash.

EXECUTIVE COMPENSATION AND OTHER INFORMATION

Report on Executive Compensation

The following is the Human Resources Committee (the "Committee") Report on Executive Compensation which outlines the policies of the Committee for determining compensation of TCPL's Presidents, Executive Vice-Presidents and the CEO (collectively, the "Executives").

Committee Information

COMPOSITION OF THE COMMITTEE

The Committee is composed of four directors, K.L. Hawkins (chair), W.K. Dobson, E.L. Draper, and D.P. O'Brien, all of whom are independent, as required by securities regulations. There are no interlocking relationships between the members of the Committee or between any member of the Committee and any of TCPL's current Executives. The Committee reports to the Board on all material matters considered, recommended or approved by the Committee.

 For further information on the composition and mandate of the Committee please refer to Schedule "D" "Description of Board Committees and their Charters – Human Resources Committee". For further information on the independence of the Committee members please refer to "Schedule "B" – Disclosure of Corporate Governance Practices – Board of Directors".

COMMITTEE PROCESSES

The Committee recognizes the importance of maintaining sound governance practices for the development and administration of executive compensation and benefit programs, and has instituted processes that enhance the Committee's ability to effectively carry out its responsibilities. Examples of process steps that the Committee uses include:

 The Committee directs management to gather information on its behalf, and provide initial analysis and commentary. The Committee reviews this material along with other information received from external advisors in its deliberations

TRANSCANADA PIPELINES LIMITED 29


before considering and/or rendering decisions. The Committee has full discretion to adopt management recommendations or to alter them and to consult its own external advisors.

INDEPENDENT ADVICE

The Committee engages its own consultants, and from time-to-time legal advisors, independent of those used by management, to gather information and deliver opinions and advice on various subjects including executive compensation, securities law and compensation disclosure practices.

Executive Compensation Advisory Services

The Committee engaged the services of an individual consultant (the "Consultant") from Towers Perrin to provide executive compensation consulting services to the Committee during 2006. The mandate of the Consultant was to provide an assessment of management's proposals relating to the compensation of the Executives. In 2006, the Consultant provided services to the Committee in accordance with this mandate and attended portions of some Committee meetings, as requested by the chair of the Committee. The fees paid to Towers Perrin in 2006 for the Consultant's services to the Committee were approximately $78,000. The performance of the Consultant is reviewed and their engagement is approved by the Committee on an annual basis.

 Under the mandate, the Consultant could also provide advice to management on significant changes to compensation philosophy or programs, or other compensation matters of the Company if the work was directed or approved by the chair of the Committee. These additional services were not provided by the Consultant to TCPL in 2006. In 2006, other separate consultants from Towers Perrin did provide the Company with non-executive compensation, Board compensation, benefit and pension actuarial consulting services and the fees paid for these services were approximately $1.9 million. All service fees and related expenses paid to Towers Perrin, including those for the services of the Consultant, are reviewed by the Committee.

Executive Compensation Program

COMPENSATION PHILOSOPHY

The design of TCPL's Executive Compensation Program is based on a compensation philosophy that:


 The Executive Compensation Program specifically provides for Total Direct Compensation ("TDC") which is a combination of base salary and performance-based incentives that reflect competitive pay in light of business achievement, fulfillment of individual objectives and overall job performance. The Committee approves, or recommends for approval, all remuneration to be awarded through the Executive Compensation Program.

DETERMINING INDIVIDUAL EXECUTIVE COMPENSATION

Context for Decisions

All compensation awarded annually to the Executives under the following plans is considered for each individual and approved by the Committee or, in the case of the CEO, recommended by the Committee to the Board for approval. The Committee approves or recommends the compensation awards, which are not contingent on the number, term or current value of other outstanding compensation previously awarded to the individual. However, the Committee is provided with summaries of the three-year history of awarded compensation, which is intended to provide further context for its annual decision-making.

30 TRANSCANADA PIPELINES LIMITED

 During 2006, organizational restructuring resulted in significant changes in TCPL's Executive Leadership Team. These changes were effective June 1, 2006 and included, among others, the following changes:

 As a result of these changes, the Committee was asked to make mid-year adjustments to compensation for the executives which were based on material differences in role accountabilities and responsibilities.

Program Funding

The Committee is cognizant of the impact of Executive compensation on TCPL's cash flow and stock dilution levels, and endeavors to manage these overall costs in a just and prudent manner. In 2006, the Committee looked at potential methods for hedging the cost of some cash-settled incentive plans where share price exposure is present. After reviewing the benefits and costs of such activities, the Committee decided to continue to maintain the budgeted accrual process for funding of these plans.

Market Competitiveness

As one factor in the decision-making process, the Committee considers market compensation data provided by various external compensation sources. This data consists of summary compensation information from selected Canadian-based companies that are generally of similar size and scope to TCPL, and represent the market in which TCPL may compete for talent (the "Comparator Group").

TRANSCANADA PIPELINES LIMITED 31

 The composition of the Comparator Group is reviewed annually by the Committee for its on-going business relevance to TCPL. An overview of the 2005 characteristics of the Comparator Group, as compared to TCPL, is provided in the following table:


 
 
 
 
TCPL
 
Comparator Group

Industry
 
 
 
North American Pipelines, Power
 
Canadian Oil and Gas, Pipelines,
Power, Utilities

Location
 
 
 
Calgary
 
Principally Alberta

 
 
 
 
 
 
Median
 
75th Percentile

Revenue(1)
 
 
 
$  6.1 billion
 
$  4.8 billion
 
$10.2 billion

Market Capitalization(2)
 
 
 
$15.7 billion
 
$23.9 billion
 
$34.9 billion

Assets(1)
 
 
 
$24.1 billion
 
$9.5 billion
 
$15.7 billion

Employees(1)
 
 
 
Approximately 2,400
 
2,319
 
4,166
(1)
Revenue, assets and number of employees reflect 2005 information.

(2)
Market Capitalization is calculated as at October, 2006.

Pay for Performance

Awarding Compensation

When awarding annual compensation to the Executives, the Committee considers actual performance and results achieved against annual corporate and individual performance objectives. The annual TDC an Executive is awarded will vary in accordance with the following guidelines:

If Actual Performance...
       TDC will be...
Meets objectives / satisfactory   =   Comparable to the median of the Comparator Group

Exceeds objectives / above satisfactory
 
=
 
Comparable to above-median compensation(1)

Falls short of objectives / below satisfactory
 
=
 
Adjusted downward from the previous year(2)
(1)
The degree to which an Executive is compensated above the median is relative to his or her performance level.

(2)
The degree to which the pay is adjusted downward is relative to individual performance. However, the adjustment is typically made through variable and not fixed compensation.

2006 Corporate Performance

TCPL sets annual corporate objectives directed at achieving the results required to deliver on TCPL's key longer-term strategies for growth and value creation. Below is a summary of the performance categories and highlights of results achieved in 2006.

Performance Category
  Examples of Performance Measures
  Highlights of Results Achieved in 2006
Financial performance   •  Earnings per share
•  Funds generated from operations
•  Total Shareholder Return		   •  Strong financial performance in 2006 including:
    •  Excluding gains on asset sales, earnings per share from operations of $2.12 ($2.15 less gains of $0.03). This was a significant increase to the comparable earnings per share in 2005 of $1.75 ($2.49 less gains of $0.74).
    •  Funds generated from operations increased significantly from 2005.

32 TRANSCANADA PIPELINES LIMITED

Performance Category
  Examples of Performance Measures
  Highlights of Results Achieved in 2006
Operational excellence   •  Costs
•  Environment
•  Safety		   •  Managed capital projects to budget despite labour market pressures.
•  Delivered significant value from improved asset management.
•  Achieved productivity gains.
•  Improved safety performance; results continue to compare favourably to industry benchmarks.
•  Continued outstanding performance on pipeline customer satisfaction and service, as reflected in both internal and external customer satisfaction surveys.
Maximize TransCanada's competitive strength and enduring value   •  Stakeholder relationships
•  Corporate reputation
•  Organizational and people strengths
•  Financial capacity and flexibility
•  Excellence in value-creating strategy, analysis and investment execution		   •  Continued to build strong relationships with regulators, governments, customers and other stakeholders critical to TCPL's success.
•  Named again to the Dow Jones Sustainability Index in 2006.
•  Recognized for corporate governance practices in external rankings.
•  Maintained strong financial capacity and credit ratings in Canada and the U.S. which has allowed the Company to complete large transactions.
•  Named to the Global 100 – a list of the world's top 100 most sustainable corporations initiated by Corporate Knights Inc. in partnership with Innovest Strategic Value Advisors Inc.
Grow and maximize long-term value of Pipeline and Energy businesses   •  Progress on longer-term value adding initiatives
•  Greenfield projects
•  Completed acquisitions		   •  Long-term negotiated settlements on Northern Border Pipeline and Tuscarora Gas Transmission.
•  Continuing progress on longer-term initiatives including liquefied natural gas opportunities, northern gas pipeline development, Bruce Power "A" restart.
•  Greenfield initiatives – the Portlands Energy Centre and Halton Hills Generating Station progressed to the construction phase. Significant progress on Keystone oil pipeline project. Tamazanchale Mexican pipeline in service.
•  TransCanada and/or TC PipeLines, LP entered into agreements for acquisitions – ANR Pipeline; ANR Storage; 50% interest in Great Lakes Gas Transmission; 50% interest in Tuscarora Gas Transmission; and 20% interest in Northern Border Pipeline. TransCanada will become operator of all four pipelines.

 To assess results achieved against corporate objectives, where appropriate, the Committee looks at both absolute and relative performance against specific peer companies. The Committee is of the view that both relative and absolute measures are required to give a balanced perspective of achievement of objectives.

 The Committee and the Board were of the opinion that TCPL's 2006 performance delivered results that exceeded objectives in the areas of financial performance and growth and above satisfactory results on other notable objectives. Based on this corporate performance achievement and the assessment of individual performance, the Committee decided to award above-median TDC for Executives.

VALUE OF AWARDED COMPENSATION

While annual compensation awards made to the Executives are based on current year corporate and individual performance, the ultimate value from longer-term components of the TDC awards is linked to, and dependent upon, TCPL's ability to replicate and sustain annual performance over the longer term.

TRANSCANADA PIPELINES LIMITED 33

 To ensure that the Company's longer-term compensation programs are effective in delivering on this intent, in 2006 the Committee reviewed modeled compensation scenarios for the Executives that illustrated the impact of various future corporate performance outcomes on previously awarded and outstanding compensation. The Committee found that the intended relationship between pay and performance was appropriate for all of the Executives, and that, in aggregate, the resulting compensation modeled under various performance scenarios was reasonable, not excessive, and delivered the intended differentiation of compensation value based on performance.

Components of Total Direct Compensation

TCPL's TDC is structured with an emphasis on variable compensation. This places most of the Executive's compensation at risk where the value ultimately received by the Executive is contingent on meeting or exceeding performance requirements. Disclosure of the actual components of TDC for the CEO, the Chief Financial Officer and the three other most highly compensated executive officers based on salary and bonus value earned and received during the 2006 financial year (collectively, the "Named Executive Officers") is noted under the heading, "Executive Compensation Program – Elements of the Executive Compensation Program" below.

Executive Compensation Program

ELEMENTS OF THE EXECUTIVE COMPENSATION PROGRAM

In 2006, the Executive Compensation Program consisted of four direct compensation elements: base salary, short-term annual cash incentives, performance share units issued under the mid-term incentive plan and stock options issued under the long-term incentive plan. The following table provides an overview of these elements.

Component of TDC
   Type of Compensation
   Average 2006 Pay Mix(1)
   Element
   Form
   Plan
   Performance Period
FIXED   Annual   26%
of TDC		   Base Salary   Cash   "Base Pay Program"   1 year
    Annual   31%
of TDC		   Short-term Incentive   Cash   "Incentive Compensation Program"   1 year
   
VARIABLE   Longer-term   25%
of TDC		   Medium-term Incentive   Share Units   "Executive Share Unit Plan"   Up to 3 years with vesting at end of term
       
        19%
of TDC		   Long-term Incentive   Stock Options   "Stock Option Plan"   Vesting 331/3% each year for 3 years with a 7 year term
(1)
Pay Mix is the resulting relative value of each pay element following the determination of TDC. It is expressed as an aggregate average percentage of TDC for the Named Executive Officers. The relative value of TDC allocated to specific forms of variable compensation for individual Executives is aligned with the Executive's ability to contribute to short, medium and long-term business results based on the Committee's assessment.

34 TRANSCANADA PIPELINES LIMITED

OVERVIEW OF EXECUTIVE COMPENSATION ELEMENTS

Fixed Compensation

Base Pay Program

The Base Pay Program provides a fixed level of income based on the market value of a role. In accordance with TCPL's market-based compensation practices, all Executive roles are individually matched to similar roles in the Comparator Group. Base salaries are typically targeted at the median of the market and are reviewed annually. Variance from the median could occur on the basis of individual performance or material differences in an Executive's responsibilities versus the market comparator role. Changes in base pay are typically effective April 1st.

Variable Compensation – Annual

For Executives, the Committee has intentionally moved away from a formulaically driven variable compensation program to a program based on sound judgment and discretion at the Board and Committee levels. The Committee is of the view that formulas and weightings applied to forward-looking objectives may lead to unintended consequences for compensation purposes. For this reason, there are no pre-established weightings applied to measures or formulaic calculations used to determine payments for Executives from TCPL's performance-based annual variable compensation program. The Committee's comprehensive assessment of overall business performance of TCPL, including corporate performance against stated objectives, business circumstances and, where appropriate, relative performance against peers, provides the context for individual Executive evaluations for annual variable compensation payments.

Incentive Compensation Program

Short-term incentives are awarded through the Incentive Compensation Program (the "IC Program"). The IC Program provides for the opportunity to receive annual cash payments based on individual performance measured against pre-established annual business and individual objectives, within the context of overall corporate performance.

 Corporate performance provides the baseline from which individual assessments are made. The actual incentive awards for the Executives are based on the Committee's subjective and discretionary assessment of the Executive's contribution to the corporate results based on his or her achievement against individual objectives. The awards are provided under the pay-for-performance guidelines noted above. Payments from the IC Program are made in the first quarter following the completion of the financial year.

Variable Compensation – Longer-Term

The total value of longer-term incentive compensation ("Total LTI Value") granted each year is established as part of an Executive's overall performance-based TDC. Total LTI Value is derived from the established TDC value minus Total Cash (from Base Pay and actual awards from the IC program).

 Once the Total LTI Value has been established by the Committee, the value is then divided between the Executive Share Unit Plan (the "ESU Plan") and the Stock Option Plan. The Committee determines the actual division of Total LTI Value in a given year at its discretion and takes into account a number of factors including:


 The actual value of granted stock options cannot be determined until the date of grant. At the time of granting, the Committee grants a set number of stock options that it believes reflect the intended dollar value to be awarded based on an economic valuation done prior to granting. Once the final economic value of stock options is known, the actual value ultimately granted via the ESU Plan may be adjusted. This adjustment is necessary to reconcile the cumulative longer-term value actually granted via the two plans to the Total LTI Value that is determined by the Committee (as part of the TDC deliberation).

TRANSCANADA PIPELINES LIMITED 35

 Under this approach the Total LTI Value could potentially be different year over year based on performance or operational considerations. As a result, the number of ESU units and stock options granted each year may also vary. In recent years, approximately 70% to 80% of the Total LTI Value has been awarded through the ESU Plan and 20% to 30% through the Stock Option Plan.

Executive Share Unit Plan

Medium-term incentives are granted through the ESU Plan. The purpose of this plan is to align a considerable portion of each participant's compensation with medium-term performance objectives that support the interests of shareholders and other stakeholders. These performance objectives play a key role in the company's strategy for growth and sustainability. Participants in this plan include all executive and senior management employees of TCPL.

 Under the ESU Plan, participants receive a provisional grant of units that is based on the allocated award value from Total LTI divided by the price of TransCanada's common shares at the time of grant. Vesting of the grants is subject to the attainment of specific business performance objectives set by the Committee at the time of grant. Throughout the three-year term of the grant, participants are credited with additional value from dividends declared and paid to TransCanada's shareholders.

 At the end of the grant term, actual results are compared against the performance objectives and participant unit totals are adjusted based on this assessment. The resulting total vested units are then valued based on the price of TransCanada's common shares at the time of vesting. Participants receive a cash payment, less statutory withholdings, for their total settlement value.

 In 2006, participants received a grant of units that was valued based on the weighted average closing price for TransCanada's common shares on the TSX for the five trading days prior to and including the grant date. The Committee established specific objectives for threshold, target and maximum performance levels, the achievement of which will adjust payment amounts as follows:

Performance Level
       Unit Total Adjustment
Below threshold   =   zero units vest; no payment is made
At threshold   =   50% of units vest for payment
At target   =   100% of units vest for payment
At or above maximum   =   150% of units vest for payment

 The performance criteria which need to be met for the vesting of the 2006 grant consist of:

1.
TransCanada's absolute total shareholder return ("TSR");

2.
TransCanada's relative TSR as compared to specified companies with which TransCanada may compete for capital (the "ESU Peer Group"); and

3.
Corporate financial measures of earnings per share and funds generated from operations.

 The Committee establishes performance criteria that cover a full range of performance outcomes including the potential for a zero payout. There are no pre-established weightings applied to these measures nor are there formulaic calculations used to create the performance achievement for the plan. The Committee uses its judgment and discretion to assess overall performance in light of the stated criteria and business circumstances surrounding the performance achieved.

 If the actual performance achievement is determined by the Committee to align at a point between threshold and target, or target and maximum levels, the Committee will determine the number of units that vest on a pro-rata basis. The formula to determine the value of the vested units is based on the weighted average closing price of TransCanada's common shares on the TSX during the five trading days immediately prior to and including the vesting date.

 For the purposes of executive compensation disclosure, grants under the ESU Plan are reported as long term incentives in this AIF.

36 TRANSCANADA PIPELINES LIMITED


Stock Option Plan

Long-term incentives are granted to the Executives through the Stock Option Plan. This plan aligns the Executives' interests with the longer term growth and profitability of TransCanada, ultimately enhancing shareholder value. Participants benefit only if the market value of TransCanada's common shares at the time of stock option exercise is greater than the market value of such shares at the time of grant. Only executive-level employees received grants from the Stock Option Plan in 2006.

 The exercise price of a stock option is set as the volume weighted average trading price on the TSX during the five trading days immediately prior to the grant date. Stock options granted in 2006 vest 331/3% on each anniversary of the grant date for a period of three years. Vested stock options from this grant may be exercised until their expiry, which is seven years from the grant date.

Share Ownership Guidelines

The Committee believes that executives can more effectively represent the interests of shareholders if they have a significant investment in the common shares of TransCanada, or their economic equivalent. The Committee is of the opinion that executives should hold an interest in TransCanada in order to align their financial interests with those of shareholders. In January 2003, all of the Executives and certain additional executive and senior-level employees of the Company were given guidelines to achieve an interest level that the Committee viewed as significant in relation to each employee's base salary.

 The level of ownership could be achieved by direct purchase of common shares, by participation in the TransCanada Dividend Reinvestment Plan or through unvested units granted under the ESU Plan. In June 2006, the Committee approved an amendment to the current Share Ownership Guidelines (the "Guidelines") to require that at least 50% of the ownership level be TransCanada common shares or units of any TransCanada sponsored limited partnership. Unvested Executive Share Units ("ESUs") would only count to a maximum of 50% of the ownership level. Executives and other employees included under the guidelines have until the end of 2010 to meet this new standard.

 The Committee receives regular updates on Executive ownership levels and compliance with the guidelines. The following table sets out the Guideline ownership levels for the Named Executive Officers based on their base salary rate as of December 31, 2006 and the 20-day weighted average closing price of TransCanada's common shares at year end which was $39.92.

Named Executive Officer   Minimum Ownership Requirement(1)   Minimum Guideline Ownership Value ($)   Actual Guideline Ownership Value as at December 31, 2006 ($)(2)   Multiple of Base Salary Rate
H.N. Kvisle   3 times base salary   3,300,000   3,695,421   3.36
G.A. Lohnes(3)   2 times base salary   680,000   357,645   1.05
R.K. Girling   2 times base salary   1,040,000   1,014,529   1.95
A.J. Pourbaix   2 times base salary   1,040,000   677,245   1.30
D.M. Wishart   2 times base salary   800,000   1,613,688   4.03
(1)
Other senior employees of TransCanada have a minimum ownership requirement of one times base salary.

(2)
Under the Guidelines, the value from unvested Executive Share Units (ESUs) is counted only to a maximum of 50% of the ownership requirement.

(3)
Mr. Lohnes became an Executive Vice-President in June 2006 at which time his ownership requirement under the Guidelines was increased from one times base salary to two times base salary.

TRANSCANADA PIPELINES LIMITED 37

Changes Made to the Executive Compensation Program

The following section provides information regarding recent design or practice changes that have been made to plans in TCPL's Executive Compensation program. These changes impact compensation values disclosed as compensation for the Named Executive Officers in the noted tables contained under the heading "Executive Compensation" below.

ESU PLAN

A review of the ESU Plan design was undertaken in 2004 to further enhance its alignment to TCPL's compensation philosophy. As a result of this review, changes were approved by the Committee and implemented commencing with the 2005 grant. ESU grants awarded in 2004 were made under the previous design and payments from those vested grants are reported in the "Summary Compensation Table" below.

 The key differences between the previous and current designs include the expansion of the performance levels and the recalibration of performance objectives as set out below.

 
   Below Threshold
  Threshold
  Target
  Maximum

Previous Plan
Design
(for 2004
grants)
 
Zero payout
 
Requires stretch but
achievable performance;
50% of granted units
payout
 
Very difficult stretch
performance
requirements;
100% granted units
payout
 
N/A

Current Plan
Design
(for 2005
grants
onward)
 
Zero payout
 
Requires acceptable
performance;
50% of granted units
payout
 
Requires stretch but
achievable performance;
100% granted units
payout
 
Very difficult stretch
performance
requirements;
150% granted units
payout

 With the previous plan design, there was a significant risk of grant forfeiture due to the difficulty of the performance requirements at both the threshold and target levels. Grants were made with lower nominal values (i.e., more units) in recognition of this significant risk. The current plan design provides for recognition of both satisfactory and excellent performance without the requirement for higher nominal grant values to deliver the same intended level of competitive compensation over the longer term.

 Previously, the share price used to value units was the closing price on the TSX on the grant date. Starting with the 2005 grant, the share price used to value the units at the time of grant reflects the weighted average closing price for TransCanada's common shares on the TSX for the five trading days prior to and including the grant date. The change was made to align the grant valuation process with the payout valuation process.

Inactive Executive Compensation Plan

The following section provides information pertaining to the executive compensation plan under which grants or awards are no longer made. However, outstanding grants or awards from this noted plan continue to be disclosed as compensation for the Named Executive Officers in the various tables contained under the heading "Executive Compensation" below.

PERFORMANCE UNIT PLAN

The Performance Unit Plan (the "PUP") was established in 1995 and included participants in the executive and senior management employee groups. In July 2002, the Committee amended the plan so that, starting in 2003, no further grants would be made under the PUP but accruals on existing grants will continue until the last grants expire in 2012, if not redeemed prior to this date.

 Until 2003, one unit from the PUP ("PUP Unit") was granted in tandem with each stock option granted under the Stock Option Plan. Each PUP Unit is eligible for an annual cash accrual up to the total value of dividends paid on one common share in the preceding financial year. The accrual is made if TransCanada's TSR is equal to or greater than the

38 TRANSCANADA PIPELINES LIMITED


average TSR of other specified Canadian companies with which TransCanada competes for capital (the "PUP Peer Group"). The Committee has full discretion to award the full or a lesser accrual value if TransCanada's absolute TSR is below that of the PUP Peer Group average.

 PUP Units vest three years after the grant date and are considered to be automatically redeemed on the tenth anniversary of the grant date. Once vested, a PUP Unit may be exercised for the dollar value accrued on the unit at any time and prior to the tenth anniversary of the grant. However, the vested PUP Unit may only be exercised if the stock option granted in tandem with the PUP Unit is concurrently exercised, or has been previously exercised. If the underlying stock option is exercised before the PUP unit is vested, the PUP Unit is forfeited.

Compensation of the President and Chief Executive Officer

The components of TDC for the CEO are the same as those for the other Executives. Annually, the Committee makes recommendations to the Board regarding the CEO's compensation based on the same market-based, performance-related basis as for the other Executives.

OVERVIEW OF PERFORMANCE

The Committee assesses the performance of the CEO on the basis of achievement against personal and corporate performance objectives approved by the Committee at the beginning of the year, as well as his overall contribution to the success of the Company. In 2006, Mr. Kvisle's personal objective focused on the following areas:

Achievement of Corporate Objectives

The Board has reviewed TCPL's financial and non-financial results for 2006, and assessed that the Company has met or exceeded all of the stated performance objectives, and that Mr. Kvisle played a key role in achieving these outcomes. The following highlights some of Mr. Kvisle's key accomplishments.

Value Creation

Mr. Kvisle provided strong support to the organization as it worked to maximize the long-term value and grow its existing businesses. The acquisition of the ANR pipeline is expected to generate accretive earnings in the Pipelines business. The purchase of additional interests in Northern Border Pipeline, Tuscarora Gas Transmission and Great Lakes Gas Transmission in expected to enhance the profitability and cash generation for TC PipeLines, LP. The Company commissioned the Tamazunchale Pipeline in 2006, and moved both the Portlands Energy Centre and Halton Hills Generating Station through to the construction phase. Significant progress was made on gaining the necessary approvals for the Keystone oil pipeline project.

 Mr. Kvisle also played a pivotal role in the continuing progress on longer-term initiatives including liquefied natural gas opportunities, northern gas pipeline development, and the Bruce Power restart.

Creating a Strong Management Team

Under Mr. Kvisle's guidance, the Company undertook a major organizational restructuring in 2006. Formation of the Pipelines and Energy business units created clear accountability for the profitability of those businesses. In addition, key succession plans were implemented, positioning the Company for continued strong leadership in the future.

Building Relationships

Mr. Kvisle continued to personally contribute to building long term winning relationships with key stakeholders, including shareholders, customers, governments, regulators and First Nations, all of whom are critical to the success of TCPL's strategies.

Operational Excellence

Mr. Kvisle continued to lead the Company in its efforts to manage costs, provide outstanding customer service, and achieve superior health, safety and the environmental standards. The Company's actual operating and administrative costs were under budget, and both internal and external customer surveys produced very positive results.

TRANSCANADA PIPELINES LIMITED 39

Investor Confidence

The Company's disciplined, consistent strategy continued to deliver strong financial results under Mr. Kvisle's leadership. As a result the Board increased the dividend in 2006 from $1.22 to $1.28. This contributed to an increase in TransCanada's share price from $36.65 at the end of 2005 to $40.61 at December 31, 2006.

Corporate Governance and Reputation

Mr. Kvisle plays a key role in ensuring TCPL adheres to best practices in corporate governance and maintaining the Company's excellent reputation. The Company was again recognized externally in 2006 for its governance practices, social responsibility and community investment.

SUMMARY OF PERFORMANCE

The Committee assessed Mr. Kvisle's results and concluded that his performance exceeded his individual objectives in 2006 and made this recommendation to the Board.

 The Board is of the view that Mr. Kvisle's overall achievements and performance exceeded his individual objectives in 2006, resulting in his TDC being positioned at above median TDC for similar roles in the Comparator Group. In making this determination, the Board considered the achievement of the Company and Mr. Kvisle's individual objectives (both financial and non financial) as well as significant economic, industrial and market circumstances that influenced the performance of TCPL.

Committee Summary

The Committee is satisfied that TCPL's current Executive Compensation Program reflects competitive market practice and the levels of compensation delivered under this program are aligned with the company's performance. The Committee fully understands and supports the implications of awarded compensation. The Committee will continue to monitor market conditions and modify TCPL's Executive Compensation Program, if required, to ensure it remains competitive and aligned with TCPL's compensation philosophy.

 This Report on Executive Compensation is submitted on behalf of the voting members of the Human Resources Committee of the Board:

    K.L. Hawkins (Chair)   D.P O'Brien
    W.K. Dobson   E.L. Draper

40 TRANSCANADA PIPELINES LIMITED

Performance Graph

The following chart compares the five-year cumulative total shareholder return on the TransCanada (formerly TCPL) common shares to the S&P/TSX composite index (assuming reinvestment of dividends and considering a $100 investment in common shares on December 31, 2001).

GRAPHIC

 
   Dec. 31, 2001
   Dec. 31, 2002
   Dec. 31, 2003
   Dec. 31, 2004
   Dec. 31, 2005
   Dec. 31, 2006
   Compound Annual Growth
TransCanada   100.0   120.5   153.1   170.6   217.9   250.3   20.1%
TSX   100.0   87.6   111.0   127.0   157.7   184.9   13.1%

Remuneration of Executive Officers of TCPL

The Executives also serve as executive officers of TCPL. An aggregate remuneration is paid for serving as an executive of TransCanada and for service as an executive officer of TCPL. Since TransCanada does not hold any assets directly other than the common shares of TCPL and receivables from certain of TCC's subsidiaries, all executive employee costs are assumed by TCPL according to a management services agreement between the two companies.

Executive Compensation

All compensation values disclosed in this section, unless otherwise noted, are expressed in Canadian dollars and are derived from compensation plans and programs that are described in detail under the section "Report on Executive Compensation" or from retirement arrangements reported under the section "Pension and Retirement Benefits".

TRANSCANADA PIPELINES LIMITED 41


Summary Compensation Table

The following table outlines the summary of compensation earned in the 2006, 2005 and 2004 financial years by the Named Executive Officers.

 
   ANNUAL COMPENSATION
  LONG-TERM COMPENSATION
   
 
    
    
    
    
   Awards
  Payouts
   

Name and Principal Position of the Named Executive Officers
(a)
  Year
(b)
   Salary(5)
($)
(c)
   Bonus(6)
($)
(d)
   Other Annual Compensation(7)
($)
(e)
   Securities Under Options Granted(8)
(#)
(f)
   Shares or Units Subject to Resale Restriction
($)
(g)
   LTIP Payouts(9)
($)
(h)
   All Other Compensation(10)
($)
(i)
H.N. Kvisle
President and
Chief Executive Officer		   2006
2005
2004		   1,100,004
1,050,003
871,251		   1,500,000
1,300,000
1,100,000		   –
–		   250,000
160,000
165,000		   –
–
–		   2,980,971
1,852,433
–		   11,000
10,417
8,665
G.A. Lohnes
Executive Vice-President
and Chief Financial Officer		   2006
2005
2004		 (1)
(2)
(2)		 331,973
318,914
345,605		   320,000
208,240
161,173		   266,013
62,077
84,844		   64,000
20,000
12,000		   –
–
–		   345,000
254,562
–		   11,786
9,167
9,296
R.K. Girling
President, Pipelines		   2006
2005
2004		 (3)

 498,346
460,032
457,524		   700,000
500,000
460,000		   –
–		   190,000
60,000
60,000		   –
–
–		   1,192,429
740,973
–		   28,192
25,600
25,571
A.J. Pourbaix
President, Energy		   2006
2005
2004		 (4)

 494,172
440,001
407,505		   700,000
500,000
450,000		   –
–		   190,000
60,000
60,000		   –
–
–		   1,064,734
740,973
–		   71,065
49,691
46,148
D.M. Wishart
Executive Vice-President,
Operations and Engineering		   2006
2005
2004		   395,007
372,504
335,004		   500,000
400,000
330,000		   –
–		   55,000
40,000
40,000		   –
–
–		   877,367
370,487
–		   24,942
3,713
3,325
(1)
Mr. Lohnes was appointed Executive Vice-President and Chief Financial Officer for TCPL in June 2006 and continued in his role as President of Great Lakes Gas Transmission Company ("Great Lakes") until September 1, 2006. As such, the values denoted for the 2006 financial year represent compensation earned in this position for a four month period, combined with compensation earned for eight months in his previous position as President and Chief Executive Officer of Great Lakes.

(2)
These values reflect the compensation Mr. Lohnes received during his tenure as President and Chief Executive Officer of Great Lakes. Mr. Lohnes became President and CEO in August 2000 and during his term, Great Lakes was a pipeline joint venture owned 50/50 by TransCanada and El Paso Corporation. The values denoted were provided to Mr. Lohnes in U.S. dollars (or equivalent value) but have been expressed here in Canadian dollars based on the Bank of Canada's average annual exchange rate for the financial year noted, namely 1.2116 for 2006, 1.3015 for 2005, and 1.4015 for 2004.

(3)
Mr. Girling was appointed President, Pipelines in June 2006. As such, values denoted for the 2006 financial year represent compensation earned in this position for a seven month period, combined with compensation earned for five months in his previous position as Executive Vice-President, Corporate Development and Chief Financial Officer.

(4)
Mr. Pourbaix was appointed President, Energy in June 2006. As such, values denoted for the 2006 financial year represent compensation earned in this position for a seven month period, combined with compensation earned for five months in his previous position as Executive Vice-President, Power.

(5)
This column reflects actual base salary earnings during the noted financial year. Salary adjustments are typically effective April 1.

(6)
Amounts referred to in this table as "Bonus" are paid pursuant to the IC Program and attributable to the noted financial year. Payments from the IC Program are made in the first quarter following the completion of the financial year.

(7)
This column includes payments made to Mr. Lohnes for tax equalization on exercised stock options of US$124,842 for 2006, US$47,697 for 2005 and US$60,538 for 2004. The aforementioned payments are disclosed here in Canadian dollars based on the Bank of Canada's average annual exchange rate for the financial year noted, namely 1.2116 for 2006, 1.3015 for 2005, and 1.4015 for 2004. As part of his repatriation to Canada, Mr. Lohnes also received a one-time special tax-protected bonus payment of $200,000. This value will be paid to Mr. Lohnes in annual installments of $70,000 in 2006, $65,000 in 2007 and $65,000 in 2008. The first installment disclosed for 2006 includes $44,754 of tax reimbursement.

The value of perquisites for each Named Executive Officer is less than $50,000 and 10% of total annual salary and bonus for the financial year and, as such, is not included. For information, the average annual value for perquisites provided to the Named Executive Officers in 2006 was $32,378 and included such things as car allowance or lease and the associated maintenance fees, Company paid parking, luncheon and/or recreation club memberships and financial counseling/tax preparation.

(8)
This column shows the total number of stock options granted under the Stock Option Plan to each of the Named Executive Officers during each of the financial years noted. Due to the corporate restructuring in June 2006 there was a special grant made to certain Named Executive Officers that was in addition to those granted during the annual determination of TDC in February. Specifically, Mr. Lohnes received an additional 50,000 options, Mr. Girling and Mr. Pourbaix each received an additional 100,000 options. Further disclosure on these grants is found under the heading "Equity Compensation Plan Tables" below.

42 TRANSCANADA PIPELINES LIMITED

(9)
LTIP Payouts represent the value of the payments made or to be made for the proportion of ESU units granted in 2004 that vested and became eligible for payout in 2006. There were no payouts made under the PUP to the Named Executive Officers in 2006.

(10)
The amounts in this column include payments made to the Named Executive Officers by subsidiaries and affiliates of TransCanada (including directors' fees paid by affiliates and amounts paid for serving on management committees of entities in which TransCanada holds an interest), specifically: Mr. Girling – $23,250 for 2006 and $21,000 for both 2005 and 2004; Mr. Pourbaix – $59,250 for 2006 and $39,000 for both 2005 and 2004; Mr. Wishart – $21,000 for 2006.

This column also includes the value of salary paid in lieu of vacation based on the election of the Named Executive Officer and the value of TCPL's contributions under the Employee Stock Savings Plan made on behalf of the Named Executive Officer for the noted financial year.

Long-Term Incentive Plan Tables

2006 ESU PLAN GRANTS

The following table outlines the grants made under the ESU Plan that were approved in February 2006. These grants are still unvested and outstanding as at December 31, 2006 and have therefore not yet been recorded as LTIP Payouts in the Summary Compensation Table, column (h), above.

 
    
    
   Estimated Future Payouts Under
Non-Securities-Price-Based Plans (units)(2)
 
    
   Performance or Other Period Until Maturation or Payout
Name
  Securities, Units or Other Rights(1)
(#)
   Below Threshold
(#)
   Threshold
(#)
   Target
(#)
   Maximum
(#)
H.N. Kvisle   52,391   Dec. 31, 2008   0   26,195   52,391   78,586
G.A. Lohnes   3,401   Dec. 31, 2008   0   1,701   3,401   5,102
R.K. Girling   16,893   Dec. 31, 2008   0   8,447   16,893   25,340
A.J. Pourbaix   16,893   Dec. 31, 2008   0   8,447   16,893   25,340
D.M. Wishart   8,958   Dec. 31, 2008   0   4,479   8,958   13,436
(1)
This is the grant of units under the ESU Plan.

(2)
Does not include the units related to reinvested dividend value.

2005 ESU PLAN GRANTS

The following table outlines the grants made under the ESU Plan that were approved in February 2005. These grants are still unvested and outstanding as at December 31, 2006 and therefore have not yet been recorded as LTIP Payouts in the Summary Compensation Table, column (h), above.

 
    
    
   Estimated Future Payouts Under
Non-Securities-Price-Based Plans (units)(2)
 
    
   Performance or Other Period Until Maturation or Payout
Name
  Securities, Units or Other Rights(1)
(#)
   Below Threshold
(#)
   Threshold
(#)
   Target
(#)
   Maximum
(#)
H.N. Kvisle   65,320   Dec. 31, 2007   0   32,660   65,320   97,980
G.A. Lohnes   4,441   Dec. 31, 2007   0   2,221   4,441   6,662
R.K. Girling   18,349   Dec. 31, 2007   0   9,175   18,349   27,524
A.J. Pourbaix   15,657   Dec. 31, 2007   0   7,828   15,657   23,485
D.M. Wishart   12,458   Dec. 31, 2007   0   6,229   12,458   18,687
(1)
This is the grant of units under the ESU Plan.

(2)
Does not include the units related to reinvested dividend value.

TRANSCANADA PIPELINES LIMITED 43

2004 ESU PLAN GRANTS

The following table outlines the ESU Plan grants that were made in 2004 and vested in 2006. The table reconciles the value that was paid to the Named Executive Officers which is disclosed under LTIP Payouts in the Summary Compensation Table, column (h) above.

Name
  Securities, Units or Other Rights(1)
(#)
   Performance or Other Period Until Maturation or Payout
   Vested Units From Grants(2)
(#)
   Vested Value From Grants(3)
($)
   Vested Value From Dividends(4)
($)
   Total Settlement(5)
($)
H.N. Kvisle   73,185   Dec. 31, 2006   65,867   2,664,300   316,671   2,980,971
G.A. Lohnes   8,470   Dec. 31, 2006   7,623   308,350   36,650   345,000
R.K. Girling   29,275   Dec. 31, 2006   26,348   1,065,756   126,673   1,192,429
A.J. Pourbaix   26,140   Dec. 31, 2006   23,526   951,627   113,107   1,064,734
D.M. Wishart   21,540   Dec. 31, 2006   19,386   784,164   93,203   877,367
(1)
This is the grant of units under the ESU Plan that is used to determine vesting. The range of units that are eligible to vest under this grant are between 50% and 100%, based on performance between Threshold and Target, or 0% if Threshold performance is not met.

(2)
Based on the Committee's assessment of the performance achieved against objectives, 90% of the granted units vested for settlement. This number does not include units related to reinvested dividends.

(3)
Vested units were valued at $40.45 per unit based on the five day weighted closing price of common share on the TSX at December 31, 2006.

(4)
The additional value related to the accrued value from declared dividends and paid relative to the vested unit total.

(5)
Includes both the Vested Value from Grant and Vested Value from Dividends. This settlement value is reported as an LTIP Payout in the Summary Compensation Table, column (h) above.

SUPPLEMENTAL DISCLOSURE – 2007 ESU PLAN GRANTS

Decisions regarding ESU Plan grants are made annually by the Committee in February prior to the publication of the Proxy Circular. Although not a requirement, TCPL discloses these compensation grants for the Named Executive Officers. The following table outlines the grants under the ESU Plan made in 2007.

 
    
    
   Estimated Future Payouts Under
Non-Securities-Price-Based Plans (units)(2)
 
    
   Performance or Other Period Until Maturation or Payout
Name
  Securities, Units or Other Rights(1)
(#)
   Below Threshold
(#)
   Threshold
(#)
   Target
(#)
   Maximum
(#)
H.N. Kvisle   58,405   Dec. 31, 2009   0   29,203   58,405   87,608
G.A. Lohnes   10,383   Dec. 31, 2009   0   5,192   10,383   15,575
R.K. Girling   30,964   Dec. 31, 2009   0   15,482   30,964   46,446
A.J. Pourbaix   30,964   Dec. 31, 2009   0   15,482   30,964   46,446
D.M. Wishart   18,541   Dec. 31, 2009   0   9,271   18,541   27,812
(1)
This is the grant of units under the ESU Plan.

(2)
Does not include units related to reinvested dividend value.

44 TRANSCANADA PIPELINES LIMITED

PUP GRANTS OUTSTANDING

The following table outlines PUP grants made to the Named Executive Officers. The estimated future payouts set out in the table include all accruals up to and including the accrual approved for the most recently completely financial year.

 
    
    
   Estimated Future Payouts Under Non-Securities-Price-Based Plans(3)
    
 
    
   Performance or Other Period Until Maturation or Payout(2)
    
Name
  Securities, Units or Other Rights(1)
(#)
   Below Threshold(4)
($)
   Maximum(4)
($)
   Settlement Value for 2006(5)
($)
H.N. Kvisle   150,000   25-Feb-12   0   811,350   –
    100,000   20-Mar-11   0   630,900   –
    42,500   27-Feb-11   0   268,133   –
    55,000   28-Feb-10   0   395,395   –
    50,000   01-Feb-10   0   359,450   –
    90,000   01-Sep-09   0   647,010   –
G.A. Lohnes   20,000   25-Feb-12   0   108,180   –
    17,500   27-Feb-11   0   110,408   –
    17,500   28-Feb-10   0   125,808   –
    22,016   9-Dec-07   0   184,912   –
R.K. Girling   65,000   25-Feb-12   0   351,585   –
    45,000   27-Feb-11   0   283,905   –
    45,000   28-Feb-10   0   323,505   –
    50,000   01-Feb-10   0   359,450   –
    20,000   29-Jul-09   0   143,780   –
    25,000   01-Mar-09   0   179,725   –
    25,000   03-Dec-08   0   179,725   –
    25,162   09-Dec-07   0   211,336   –
A.J. Pourbaix   65,000   25-Feb-12   0   351,585   –
    35,000   27-Feb-11   0   220,815   –
    20,000   28-Feb-10   0   143,780   –
    20,000   01-Feb-10   0   143,780   –
    20,000   01-Mar-09   0   143,780   –
    17,500   03-Dec-08   0   125,808   –
D.M. Wishart   30,000   25-Feb-12   0   162,270   –
    35,000   27-Feb-11   0   220,815   –
    20,000   28-Feb-10   0   143,780   –
    20,000   01-Feb-10   0   143,780   –
    20,000   01-Mar-09   0   143,780   –
    25,162   09-Dec-07   0   211,336   –
(1)
As no further awards will be made under the PUP, it will be phased out over the remaining life of the outstanding units.

(2)
The exercise period for all PUP Units commences upon vesting, which is the third anniversary of the grant date, and expires on the tenth anniversary of the grant date, with the exception of the PUP Units maturing on February 1, 2010. These Units were granted under a one time special performance incentive program which vested on February 22, 2002.

(3)
The Committee determined in January 2007 that $1.27 per outstanding PUP Unit will accrue for 2006 in respect of the grants made from December 5, 1996 to February 25, 2002.

TRANSCANADA PIPELINES LIMITED 45

(4)
The Company is no longer including the "Threshold" and "Target" columns since the values reported were equal to the ones noted here in the "Maximum" column. Once the accrued value is approved by the Committee and assigned to each outstanding PUP Unit, no further variance of future value may be applied. However, the plan does provide for a risk of zero value payments from the plan should the exercise provision in the plan not be met.

(5)
Values contained in this column are amounts received during the current financial year following the exercise of vested PUP Units. A blank ("–") denotes that there were no Units exercised from the grant. A zero value denotes that all PUP Units from the grant were forfeited. When applicable, settlement values are also reported as LTIP Payouts in column (h) of the Summary Compensation Table, above.

Equity Compensation Plan Tables

2006 STOCK OPTION PLAN GRANT

The following table outlines the grants made under the Stock Option Plan to each of the Named Executive Officers during the 2006 financial year.


Name

 
Date of
Grant
 
Number of
Common Shares
Under Options
Granted(1)
 
% of
Total Options
Granted to
Employees
in 2006
 
Exercise Price
($/common share)(2)
 
Market Value of Common Shares Underlying Options on the Date of Grant
($/common share)
 
Expiration
Date
H.N. Kvisle   27-Feb-06   250,000   13.58%   35.23   35.23   27-Feb-13
G.A. Lohnes   12-Jun-06   50,000   2.72%   33.08   32.70   12-Jun-13
    27-Feb-06   14,000   0.76%   35.23   35.23   27-Feb-13
R.K. Girling   12-Jun-06   100,000   5.43%   33.08   32.70   12-Jun-13
    27-Feb-06   90,000   4.89%   35.23   35.23   27-Feb-13
A.J. Pourbaix   12-Jun-06   100,000   5.43%   33.08   32.70   12-Jun-13
    27-Feb-06   90,000   4.89%   35.23   35.23   27-Feb-13
D.M. Wishart   27-Feb-06   55,000   2.99%   35.23   35.23   27-Feb-13
(1)
On each anniversary date of the grant for a period of three years, one-third of these options vest and are exercisable.

(2)
The exercise price is equal to the greater of the closing price of common shares on the grant date and the weighted average closing price of common shares on the TSX during the five trading days immediately prior to the grant date of the stock options.

AGGREGATE STOCK OPTION EXERCISES DURING 2006 AND 2006 YEAR-END STOCK OPTION VALUES

The following table provides information relating to options exercised and the number or value of options outstanding as at December 31, 2006 for each of the Named Executive Officers.

 
    
    
   Unexercised Options at December 31, 2006
(#)
  Value of Unexercised in-the-Money Options at December 31, 2006(1)
($)
 
   Common Shares Acquired on Exercise
(#)
   Aggregate Value Realized
($)
Name
  Exercisable
   Unexercisable
   Exercisable
   Unexercisable
H.N. Kvisle   100,000   1,551,454   555,833   411,667   9,568,163   3,223,937
G.A. Lohnes   30,500   365,062   4,167   81,333   43,837   647,123
R.K. Girling   0   0   205,000   250,000   3,469,900   1,933,200
A.J. Pourbaix   80,000   1,017,273   97,500   250,000   1,472,200   1,933,200
D.M. Wishart   0   0   190,162   95,000   3,408,018   759,899
(1)
The value of unexercised "in-the-money" stock options at December 31, 2006 is the difference between the exercise price and the closing price of $40.61 per share of a common share on the TSX on December 31, 2006. The underlying stock options have not been and will not necessarily be exercised and the actual gains, if any, on exercise will depend on the value of common shares on the date of exercise.

46 TRANSCANADA PIPELINES LIMITED

SUPPLEMENTAL DISCLOSURE – 2007 STOCK OPTION PLAN GRANTS

Decisions regarding stock option grants are made annually by the Committee in February prior to the publication of the Proxy Circular. Although not a requirement, TCPL discloses these compensation grants for the Named Executive Officers. The following table outlines the stock option grants under the Stock Option Plan made in 2007.


Name

 
Date of
Grant
 
Number of
Common Shares
Under Options
Granted(1)
 
% of
Total Options
Granted to
Employees
in 2007(2)
 
Exercise Price
($/common share)(3)
 
Market Value of Common Shares Underlying Options on the Date of Grant(3)
($/common share)
 
Expiration Date
H.N. Kvisle   22-Feb-07   202,442   18.69%   38.10   38.10   22-Feb-14
G.A. Lohnes   22-Feb-07   35,990   3.32%   38.10   38.10   22-Feb-14
R.K. Girling   22-Feb-07   107,326   9.91%   38.10   38.10   22-Feb-14
A.J. Pourbaix   22-Feb-07   107,326   9.91%   38.10   38.10   22-Feb-14
D.M. Wishart   22-Feb-07   64,267   5.93%   38.10   38.10   22-Feb-14
(1)
On each anniversary date of the grant for a period of three years, one-third of these stock options vest and are exercisable.

(2)
Based on total stock options granted as at February 22, 2007.

(3)
Equal to the volume weighted average trading price of common shares on the TSX during the five trading days immediately prior to the grant date of the stock options.

Equity Compensation Plan Information

Stock Option Plan

The Stock Option Plan is the only compensation plan under which equity securities of TransCanada have been authorized for issuance. Stock options may be granted to such employees of TCPL as the Human Resources Committee may from time to time determine. Starting in 2005, the Committee determined that only executive-level employees will participate in the plan.

 On recommendation of the Human Resources Committee, the Board has approved various amendments to the Stock Option Plan, some of which are subject to shareholder approval at TransCanada's Annual and Special Meeting. The following provides key information regarding the Stock Option Plan provisions:

TRANSCANADA PIPELINES LIMITED 47

 Under the terms of the Stock Option Plan, the maximum number of common shares reserved for issuance as stock options to any one participant in any fiscal year cannot exceed 20% of the total number of options granted in that fiscal year and the number of common shares that may be reserved for issuance to insiders, or issued within any one year period, under all of TransCanada's security based compensation arrangements cannot exceed 10% of TransCanada's issued and outstanding common shares. There are no restrictions on the number of stock options that may be granted to insiders, subject to the foregoing limitations. Stock options cannot be transferred or assigned by participants other than a personal representative being permitted to exercise stock options in the case of death of a participant or if a participant is unable to mange his or her affairs.

 Stock options granted as of 2003 onward vest as to one-third on each anniversary of the grant date for a period of three years and have a seven year term. The exercise price of a stock option is equal to the volume weighted average trading price of a common share on the TSX during the five trading days immediately prior to the grant date of the stock options.

 The following table outlines the action prescribed for grants under the Stock Option Plan. Unless a stock option expires earlier, as outlined below, stock options expire on the seventh anniversary of the date of the grant.

Event   Action
Death   All outstanding stock options vest and become exercisable as at the date of death and may be exercised no later than the first anniversary of the date of death.
Resignation   The participant may exercise outstanding vested and exercisable stock options no later than six months after the last day of active employment, after which date all outstanding stock options are forfeited.
Retirement   All outstanding stock options vest and become exercisable as at the date of retirement and the participant may exercise these, and all other vested and exercisable stock options no later than three years past the date of retirement.
Termination without cause   The participant may exercise outstanding vested and exercisable stock options no later than the later of the last day of the notice period and six months after the last day of active employment, after which date all outstanding stock options are forfeited. No options vest during the notice period.
Termination for cause   The participant may exercise outstanding vested and exercisable stock options no later than six months after the last day of active employment, after which date all outstanding stock options are forfeited.

Securities Authorized for Issuance under Equity Compensation Plans

The following table outlines the number of common shares to be issued upon the exercise of outstanding stock options under the Stock Option Plan, the weighted-average exercise price of the outstanding stock options, and the number of common shares available for future issuance under the Stock Option Plan, all as at December 31, 2006.

Plan Category
  Number of securities to be issued upon exercise of outstanding options
(a)
   Weighted-average exercise price of outstanding options
(b)
   Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
(c)
Equity compensation plans approved by security holders   8,798,920   $25.37   1,567,560
Equity compensation plans not approved by security holders   Nil   Nil   Nil

TOTAL
 
8,798,920
 
$25.37
 
1,567,560

48 TRANSCANADA PIPELINES LIMITED

Pension and Retirement Benefits for Executives

Pension and Retirement Benefits

TCPL's Canadian pension plans are designed to attract and retain employees for the long term and to provide employees with a lifetime annual retirement income.

Base Pension Plan

All TCPL Canadian employees participate in the TCPL Registered Pension Plan, which is now solely a non-contributory defined benefit pension plan.

 The normal retirement age under the Registered Pension Plan is age 60 or any age between 55 and 60 where the sum of an employee's age and continuous service equals 85. Employees are eligible to retire prior to their normal retirement date, but the benefit payable is subject to early retirement reduction factors. The defined benefit plan is integrated with Canada Pension Plan benefits. The benefit calculation is:

 1.25% of an employee's Highest Average Earnings(1) up to the Final Average(2) YMPE(3)

 plus

 1.75% of an employee's Highest Average Earnings above the Final Average YMPE

 multiplied by

 the employee's years of credited service in the Registered Pension Plan ("Credited Pensionable Service")

(1)
"Highest Average Earnings" means the average of an employee's best consecutive 36 months of Pensionable Earnings in the last 15 years before retirement. "Pensionable Earnings" means an employee's base salary plus actual Incentive Compensation paid up to a targeted percentage or for executive employees (as defined in the plan) a fixed percentage of their base salary, as provided in the plan. Pensionable Earnings do not include overtime, shift and premium differentials or any other forms of compensation.

(2)
"Final Average YMPE" means the average of the YMPE in effect for the latest calendar year from which earnings are included in an employee's highest earnings calculation plus the two previous years.

(3)
"YMPE" means Year's Maximum Pensionable Earnings under the Canada/Québec Pension Plan.

 Registered defined benefit pension plans are subject to a maximum annual benefit accrual under the Income Tax Act (Canada), which is currently $2,222 for each year of Credited Pensionable Service, with the result that benefits cannot be earned in the Registered Pension Plan on compensation above approximately $139,000 per annum.

Supplemental Pension Plan

All TCPL employees with pensionable earnings over the Income Tax Act (Canada) ceiling of $139,000, including the Named Executive Officers, participate in the Company's non-contributory defined benefit Supplemental Pension Plan. Approximately 477 TCPL employees currently participate in the Supplemental Pension Plan.

 The Registered Pension Plan and Supplemental Pension Plan were amended at January 1, 2007 to change from an earnings maximum approach, where the earnings are capped each year based on the maximum annual benefit accrual under the Income Tax Act (Canada), to a hold harmless approach, where the maximum amount allowable under the Income Tax Act (Canada) will be paid from the Registered Pension Plan and the remainder is paid from the Supplemental Pension Plan. The overall benefit remains the same.

 The Supplemental Pension Plan is funded through a retirement compensation arrangement under the Income Tax Act (Canada). Subject to the Board's approval, contributions to the fund are based on an annual actuarial valuation of the Supplemental Pension Plan obligations calculated on the basis of the plan terminating at the beginning of each calendar year.

 The annual pension benefit under the Supplemental Pension Plan is equal to 1.75% multiplied by the employee's Credited Pensionable Service multiplied by the amount by which such employee's Highest Average Earnings exceed the ceiling imposed under the Income Tax Act (Canada) and is recognized under the Registered Pension Plan.

TRANSCANADA PIPELINES LIMITED 49


 Generally, neither the Registered Pension Plan nor the Supplemental Pension Plan provide for the recognition of past service. However, the Committee may, under the provisions of the Supplemental Pension Plan, at its sole discretion, grant additional years of credited service to executive employees.

 Under the Registered Pension Plan and the Supplemental Pension Plan, TCPL employees, including the Named Executive Officers, will receive the following normal form of pension:

 In lieu of the normal form of pension, optional forms of pension payment may be chosen provided that any legally required waivers are completed.

 The following table sets out the estimated annual defined benefit plan benefits (based on the "joint and 60% survivor" method) payable for credited service under the Registered Pension Plan and the Supplemental Pension Plan (excluding amounts payable under the Canada Pension Plan) for employees with the following Highest Average Earnings and Credited Pensionable Service. The benefits listed in the table are not subject to any deduction for social security or other offset amounts such as Canada Pension Plan or the Québec Pension Plan.

 
   Years of Credited Pensionable Service
Highest Average Earnings
  10 Years
   15 Years
   20 Years
   25 Years
   30 Years
   35 Years
$   400,000   $68,000   $102,000   $136,000   $170,000   $204,000   $238,000
      600,000   103,000   154,000   206,000   257,000   309,000   360,000
      800,000   138,000   207,000   276,000   345,000   414,000   483,000
  1,000,000   173,000   259,000   346,000   432,000   519,000   605,000
  1,200,000   208,000   312,000   416,000   520,000   624,000   728,000
  1,400,000   243,000   364,000   486,000   607,000   729,000   850,000
  1,600,000   278,000   417,000   556,000   695,000   834,000   973,000
  1,800,000   313,000   469,000   626,000   782,000   939,000   1,095,000
  2,000,000   348,000   522,000   696,000   870,000   1,044,000   1,218,000
  2,200,000   383,000   574,000   766,000   957,000   1,149,000   1,340,000
  2,400,000   418,000   627,000   836,000   1,045,000   1,254,000   1,463,000
  2,600,000   453,000   679,000   906,000   1,132,000   1,359,000   1,585,000
  2,800,000   488,000   732,000   976,000   1,220,000   1,464,000   1,708,000

 Based on their current Highest Average Earnings and assuming the Named Executive Officers remain employed by TCPL until age 60 and that the Registered Pension Plan and Supplemental Pension Plan remain in force substantially in their

50 TRANSCANADA PIPELINES LIMITED


present form, the Named Executive Officers will have the number of years of credited pensionable service and benefit payable set out below under their names.


 
 
H.N. Kvisle(1)
 
G.A. Lohnes(2)
 
R.K. Girling(3)
 
A.J. Pourbaix(3)
 
D.M. Wishart
Years of Credited Service to December 31, 2006   14.33   13.33   8.00   8.00   9.59
Accrued Pension at December 31, 2006 and Payable at age 60   $461,000   $76,000   $103,000   $95,000   $93,000
Years of Credited Service to age 60   23.16   22.92   26.50   29.58   17.50
Annual Benefit Payable at age 60   $748,000   $131,000   $334,000   $347,000   $169,000
(1)
In 2002, the Human Resources Committee approved an arrangement with Mr. Kvisle to grant him additional credited pensionable service. The arrangement resulted in him receiving five years of additional credited pensionable service in 2004 on his fifth anniversary date with TransCanada. In addition, for each year after 2004, until and including 2009, Mr. Kvisle will be granted one additional year of credited pensionable service on the date of the anniversary of his employment. All such additional service will not exceed ten additional years of credited pensionable service and is to be recognized solely in the Supplemental Pension Plan with respect to earnings in excess of the maximum set under the Income Tax Act (Canada).

(2)
Mr. Lohnes continued to accrue credited service in the Canadian Registered Pension Plan and Supplemental Pension Plan while employed in the USA from August 16, 2000 to August 31, 2006. Pensionable earnings were established on the basis that one U.S. dollar is equal to one Canadian dollar, and included both the U.S. Base Salary and Incentive Compensation Payment at Target.

(3)
In 2004, the Human Resources Committee also approved arrangements for Mr. Girling and Mr. Pourbaix to obtain additional credited pensionable service. Subject to Mr. Girling and Mr. Pourbaix maintaining continuous employment with TransCanada until September 8, 2007, each will receive an additional three years of credited pensionable service on that date which are to be recognized solely in the Supplemental Pension Plan with respect to earnings in excess of the maximum set under the Income Tax Act  (Canada).

Fiscal 2006 Pension Expense Related to Service and Compensation

Amounts reported in the table below represent the pension expense related to services provided in the 2006 year for each of the Named Executive Officers under both the Registered Pension Plan and the Supplemental Pension Plan including the impact of differences between actual compensation paid in 2006 and the actuarial assumptions used for the year.


Name

 
Fiscal 2006 pension expense related to service and compensation
H.N. Kvisle   $713,000
G.A. Lohnes   $626,000
R.K. Girling   $384,000
A.J. Pourbaix   $393,000
D.M. Wishart   $154,000

Accrued Pension Obligations

As at December 31, 2006, TCPL's accrued obligation for the Supplemental Pension Plan was approximately $197.9 million. The 2006 current service costs and interest costs of the Supplemental Pension Plan were approximately $5.1 and $8.9 million, respectively, for a total of $14.0 million. The accrued pension obligation is calculated following the method prescribed by the Canadian Institute of Chartered Accountants and is based on management's best estimate of future events that affect the cost of pensions, including assumptions about future salary adjustments and bonuses. More information on the accrued obligations and the assumptions utilized may be found in Note 19

TRANSCANADA PIPELINES LIMITED 51

(Employee Future Benefits) of the Notes to TCPL's 2006 Consolidated Financial Statements which are available on the Company's website at www.transcanada.com and filed on SEDAR at www.sedar.com.

 The accrued pension obligations for the Named Executive Officers under both the Registered Pension Plan and the Supplemental Pension Plan are outlined in the following table. Changes include the fiscal 2006 expense attributed to service and compensation, as well as the normal increases to pension obligations arising from the annual valuation of the Company's pension plans. The normal increases include interest on the beginning of year obligations and changes in interest rate assumptions as a result of changes in long-term bond yields.


Name

 
Accrued obligation at December 31, 2005(1)
(A)
 
Change in accrued obligation for 2006(1)(2)
(B)
 
Accrued obligation at December 31, 2006(1)
(C) = (A) + (B)
H.N. Kvisle   $6,129,000   $1,408,000   $7,537,000
G.A. Lohnes   $845,000   $795,000   $1,640,000
R.K. Girling   $1,111,000   $640,000   $1,751,000
A.J. Pourbaix   $1,039,000   $640,000   $1,679,000
D.M. Wishart   $1,167,000   $320,000   $1,487,000
(1)
The calculation of reported amounts use actuarial assumptions and methods that are consistent with those used for calculating pension obligations and annual expense as disclosed in the Company's 2005 and 2006 consolidated financial statements. As the assumptions reflect the Company's best estimate of future events, the values shown in the above table may not be directly comparable to similar estimates of pension obligations that may be disclosed by other corporations.

(2)
Excluded from the change in accrued obligation for 2006 is the impact of investment returns on the Company's pension plan assets.

Executive Separation Agreements

Executive separation agreements with the Executives (including each of the Named Executive Officers) outline the terms and conditions applicable in the event of the Executive's separation from TCPL due to retirement, termination (with or without cause), resignation (with or without good reason), disability or death. Good reason is an event which constitutes a constructive dismissal of the Executive. A change of control by itself without an event that constitutes constructive dismissal would not be good reason.

52 TRANSCANADA PIPELINES LIMITED


 The following table summarizes the material terms and provisions that apply in the event of termination without cause or resignation with good reason.

Severance Payment   Annualized salary rate as of the termination date, plus the average of the previous three years' annual short-term compensation plan payments (the "Annual Compensation"), multiplied by a notice period(1).
Benefits   Continuation of benefits during the notice period or a cash payment in lieu of continued benefits.
Perquisites   A cash payment for perquisites the Executive would have received during the notice period.
Pension   Continued accrual of pensionable service until the earlier of retirement, death and expiry of the notice period(2). However, if the termination date is within two years of a change of control, then the Executive would immediately receive the credit of pensionable service as though the full notice period has occurred and any vesting requirements under the pension plans would be deemed to have been met upon a change of control.
Short-term Compensation   A cash amount equal to the average amount of the annual bonus paid to the Executive in respect of the three years prior to the year in which the termination occurs, pro rated based on the number of days of service in the year in which the termination occurs up to the termination date.
Mid-term Compensation   If the termination date is within two years of a change of control, all unvested grants under the ESU Plan shall be deemed vested and shall be paid out in cash to the Executive. Otherwise, the Executive is provided with a prorated payment. This payment is based on the granted dollar value and the number of months the Executive participated in the grant term prior to termination (as per other plan participants).
Long-term Compensation   The participant may exercise outstanding vested and exercisable stock options no later than the later of the last day of the notice period and six months after the last day of active employment, after which date all outstanding stock options are forfeited. No options vest during the notice period.
(1)
In the case of Mr. Kvisle, the notice period is three years. In the case of the other Executives, the notice period is two years.

(2)
For Mr. Kvisle, Mr. Girling and Mr. Pourbaix, their respective notice periods would also be considered in the calculation of additional credited pensionable service as agreed to in their specific arrangements as described below.

 A change of control includes (but is not limited to) another entity becoming the beneficial owner of more than 20% of the voting shares of TransCanada or more than 50% of the voting shares of TCPL (not including the voting shares of TCPL held by TransCanada). A change of control in itself does not trigger any cash payments under the agreements. However, in the month following the one year anniversary after a change of control, Mr. Kvisle may provide notice of his intention to leave TCPL and receive all of the entitlements of a resignation for good reason.

TRANSCANADA PIPELINES LIMITED 53


 The following table summarizes the material terms and provisions provided for all executives in the executive separation agreements in the event of a change of control.

Mid-term Compensation   If the Executive's termination date is within two years of a change of control, all unvested grants under the ESU Plan shall be deemed vested and shall be paid out in cash to the Executive.
Long-term Compensation   Following a change of control, there is an acceleration of stock option vesting under the Stock Option Plan. If for any reason the Company is unable to affect the acceleration of such vesting, the Company will pay the Executive a cash payment. This payment would be equal to the net amount of compensation the Executive would have received if the Executive had, on the date of a change of control, exercised all vested options and unvested options for which vesting would have been accelerated.

 
 
During 2007, TCPL intends to implement a "double trigger" in the Executive Separation Agreements where the acceleration of stock options vesting is contingent on both a change of control and the termination of the executive's employment.

 The agreements provide that TCPL may elect to take advantage of a non-competition provision effective for a period of 12 months from the date of termination upon payment to the Executive of an amount valued at one additional year of Annual Compensation.

Supplemental Disclosure – Total Compensation Awards

Annually, the Committee approves compensation awards that deliver market competitive and performance-relevant TDC, which is a combination of base salary and variable incentives, to the Executives. Although not awarded annually, TCPL also considers the annual value of the Base and Supplemental Pension Plans to be an integral part of the Company's Executive Compensation Program. For the purposes of this supplemental disclosure, Total Compensation is defined as TDC plus the pension expense related to service and compensation for the fiscal year noted.

 For all tables in this section, the following definitions are applicable for the noted compensation elements:

Annual Base Salary:   Unless otherwise noted, the annual base salary rate as at April 1st of the noted financial year.
Cash Bonus:   The total lump-sum cash award under the IC Program for performance attributable to the noted financial year, and paid in the first quarter following the completion of that financial year.
ESUs:   The value granted under the ESU Plan on the date of grant. The number of units granted for each financial year is based on this grant value and is reported in the various ESU Plan Grant tables in the section "Long-Term Incentive Tables".

 
 
The number of units that vest from these grants is subject to specified performance conditions over a three-year period. Payments received from vested units are variable based on the valuation price as of the date of vesting.
Stock Options:   The stock option values are based on the number of stock options granted for each financial year as reported in the Summary Compensation Table multiplied by an economic value per stock option as calculated by an external consulting firm. This valuation methodology considers, among other things, the exercise price on the date of grant and the seven year term of the options. This method may not be identical to the methods or assumptions used by other companies, and as such, may not be directly comparable to other companies.
Annual Pension Expense:   Pension expense related to the year of service under both the Registered Pension Plan and the Supplemental Pension Plan. The amount includes the impact of differences between actual compensation paid in the financial year and the actuarial assumptions used for that year. The value noted is rounded to the nearest one thousand dollars.

54 TRANSCANADA PIPELINES LIMITED

 The following tables outline the value of Total Compensation awarded to the Named Executive Officers as determined by the Committee for the last three financial years.

H.N. Kvisle   2006
($)		   2005
($)		   2004
($)
FIXED            
  Annual Base Salary   1,100,000   1,100,000   900,000
VARIABLE            
  Cash Bonus   1,500,000   1,300,000   1,100,000
  ESUs   1,917,500   1,940,004   1,206,089
  Stock Options   782,500   360,000   361,350
Total Direct Compensation   5,300,000   4,700,004   3,567,439
  Annual Pension Expense   713,000   1,604,000   894,000
 
G.A. Lohnes   2006(1)
($)		   2005(2)
($)		   2004(2)
($)
FIXED            
  Annual Base Salary   340,000   272,664   281,702
VARIABLE            
  Cash Bonus   320,000   208,240   161,173
  ESUs   124,477   131,898   139,586
  Stock Options   186,320   45,000   26,280
Total Direct Compensation   970,797   657,802   608,740
  Annual Pension Expense   626,000   71,583   53,257
(1)
The value noted for Annual Base Salary reflects Mr. Lohnes' rate of pay as of June 1, 2006 following his appointment to the position of Executive Vice-President and Chief Financial Officer for TCPL. The value noted for Stock Options reflects the total from two grants, namely $43,820 from the annual grant in February and $142,500 from a special one-time grant in June.

(2)
These values reflect the compensation Mr. Lohnes was awarded during his tenure as President and Chief Executive Officer of Great Lakes. Mr. Lohnes became President and CEO in August 2000 and during his term, Great Lakes was a pipeline joint venture owned 50/50 by TCPL and El Paso Corporation. The values denoted were provided to Mr. Lohnes in U.S. dollars (or equivalent value) but are expressed here in Canadian dollars based on the Bank of Canada's average annual exchange rate for the financial year noted, namely 1.2116 for 2006, 1.3015 for 2005, and 1.4015 for 2004.

R.K. Girling   2006(1)
($)		   2005
($)		   2004
($)
FIXED            
  Annual Base Salary   520,000   460,000   460,000
VARIABLE            
  Cash Bonus   700,000   500,000   460,000
  ESUs   618,300   544,965   482,452
  Stock Options   566,700   135,000   131,400
Total Direct Compensation   2,405,000   1,639,965   1,533,852
  Annual Pension Expense   384,000   158,000   86,000
(1)
The value noted for Annual Base Salary reflects Mr. Girling's rate of pay as of June 1, 2006 following his appointment to the position of President, Pipelines. The value noted for Stock Options reflects the total from two grants, namely $281,700 from the annual grant in February and $285,000 from a special one-time grant in June.

TRANSCANADA PIPELINES LIMITED 55

A.J. Pourbaix   2006(1)
($)		   2005
($)		   2004
($)
FIXED            
  Annual Base Salary   520,000   450,000   410,000
VARIABLE            
  Cash Bonus   700,000   500,000   450,000
  ESUs   618,300   465,013   430,787
  Stock Options   566,700   135,000   131,400
Total Direct Compensation   2,405,000   1,550,013   1,422,187
  Annual Pension Expense   393,000   218,000   70,000
(1)
The value noted for Annual Base Salary reflects Mr. Pourbaix's rate of pay as of June 1, 2006 following his appointment to the position of President, Energy. The value noted for Stock Options reflects the total from two grants, namely $281,700 from the annual grant in February and $285,000 from a special one-time grant in June.

D.M. Wishart   2006
($)		   2005
($)		   2004
($)
FIXED            
  Annual Base Salary   400,000   380,000   350,000
VARIABLE            
  Cash Bonus   500,000   400,000   330,000
  ESUs   327,850   370,003   354,979
  Stock Options   172,150   90,000   87,600
Total Direct Compensation   1,400,000   1,240,003   1,122,579
  Annual Pension Expense   154,000   155,000   190,000

ADDITIONAL INFORMATION

1.
Additional information in relation to TCPL may be found under TCPL's profile 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 TCPL.

3.
Additional financial information is provided in TCPL's audited consolidated financial statements and MD&A for its most recently completed financial year.

56 TRANSCANADA PIPELINES LIMITED

GLOSSARY

ACES   Accelerated Clean Energy Supply
AIF   Annual Information Form of TransCanada PipeLines Limited dated February 22, 2007
Alberta System   A natural gas transmission system throughout the province of Alberta
Annual Report   TCPL's Annual Report to Shareholders for the year ended, December 31, 2006
ANR   American Natural Resources Company and ANR Storage Company
ANR Purchase and Sale Agreement   An agreement between TransCanada and El Paso Corporation, dated December 22, 2006, whereby TransCanada agreed to acquire ANR from El Paso Corporation.
ANR System   A natural gas transmission system which extends approximately 17,000 km from producing fields in Louisiana, Oklahoma, Texas and the Gulf of Mexico to markets in Wisconsin, Michigan, Illinois, Ohio and Indiana.
B.C. and Foothills Systems   A natural gas pipeline system in southeastern B.C., southern Alberta and southwestern Saskatchewan
Bcf   Billion cubic feet
Bécancour Plant   A power plant near Trois-Rivières, Québec
Board   TransCanada's Board of Directors
Bruce A   Bruce Power A L.P.
Bruce B   Bruce Power L.P.
Cacouna Energy Project   The Cacouna Energy LNG facility in Cacouna, Québec
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
Cartier Wind Energy Project   Six wind energy projects by Hydro-Québec Distribution representing a total of 740 MW in the Gaspé region of Québec
CSA   Canadian Securities Administrators
EUB   Alberta Energy and Utilities Board
External Auditor   KPMG LLP
FERC   Federal Energy Regulatory Commission (USA)
Gas Transmission Northwest System   A natural gas transmission system running from northwestern Idaho, through Washington and Oregon to the California border
Grandview Plant   A power plant in Saint John, New Brunswick
Great Lakes   Great Lakes Gas Transmission Limited Partnership
Great Lakes System   A natural gas pipeline system in the north central U.S., roughly parallel to the Canada-U.S. Border
GUA   Gas Utilities Act
HS&E   Health, Safety and Environment
Iroquois System   A natural gas pipeline system in New York and Connecticut
LNG   Liquefied Natural Gas
MD&A   TCPL's Management's Discussion and Analysis dated February 22, 2007
MW   Megawatts
NBPL   Northern Border Pipeline
NBPL System   A natural gas transmission system located in the upper midwestern portion of the United States
NEB   National Energy Board
North Baja System   A natural gas pipeline in southern California
Northern Border Pipeline   Northern Border Pipeline Company
NOVA   NOVA Corporation
NYSE   New York Stock Exchange
PEC   Portlands Energy Centre
Portland System   A natural gas pipeline that runs through Maine and New Hampshire into Massachusetts
Power LP   TransCanada Power, L.P.
PPA   Power Purchase Agreement
Proxy Circular   TransCanada Corporation's Management Proxy Circular dated February 22, 2007
SEC   U.S. Securities and Exchange Commission
Shell   Shell US Gas & Power LLC
SOX   U.S. Sarbanes-Oxley Act of 2002
TCC   TransCanada Corporation
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
Tuscarora System   A natural gas pipeline that runs from Oregon through northeast California to Reno, Nevada
Year End   December 31, 2006

TRANSCANADA PIPELINES LIMITED 57


SCHEDULE "A"

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 PIPELINES LIMITED A-1

SCHEDULE "B"
DISCLOSURE OF CORPORATE GOVERNANCE PRACTICES

The Board and the members of TCPL's management are committed to the highest standards of corporate governance. TCPL's corporate governance practices comply with the governance rules of the Canadian Securities Administrators ("CSA"), those of the New York Stock Exchange ("NYSE") applicable to foreign issuers and of the U.S. Securities and Exchange Commission ("SEC"), and those mandated by the United States Sarbanes-Oxley Act of 2002 ("SOX"). As a non-U.S. company, TCPL is not required to comply with most of the NYSE corporate governance listing standards; however, except as summarized on its website at www.transcanada.com, the governance practices followed are in compliance with the NYSE standards for U.S. companies in all significant respects. TCPL is in compliance with the CSA's Multilateral Instrument 52-110 pertaining to audit committees ("Canadian Audit Committee Rules"); National Policy 58-201, Corporate Governance Guidelines; and National Instrument 58-101, Disclosure of Corporate Governance Practices (collectively, the "Canadian Governance Guidelines"). TCPL's principal objective in directing and managing its business and affairs is to enhance shareholder value. TCPL believes that effective corporate governance improves corporate performance and benefits all shareholders. TCPL also believes that director, management and employee honesty and integrity are vital factors in ensuring good corporate governance. The discussion that follows relates primarily to the Canadian Governance Guidelines and highlights various elements of the Company's corporate governance program. It has been approved by the Governance Committee and by the Board.

Board of Directors

The Board believes that, as a matter of policy, there should be a majority of independent directors on TCPL's Board. The Board is charged with making this determination. The Board is currently comprised of 13 directors, of whom 11 (85%) were determined by the Board in 2006 to be independent directors. Thirteen nominees are being put forward for election at the Meeting, 11 (85%) of whom have been determined by the Board to be independent. The Board annually determines the independent status of each of its members and each nominee for election, based on a written set of criteria developed in accordance with the definition of "independent" in the Canadian Audit Committee Rules and the Canadian Governance Guidelines. The independence criteria also conform with the applicable rules of the SEC, the NYSE and those set out under SOX. The Board has determined that none of the nominees for director, with the exception of Mr. Kvisle and Mr. Stewart, have a direct or indirect material relationship with TCPL that could interfere with their ability to act in the best interests of TCPL.

 Mr. Kvisle, as the CEO of TCPL, is not independent. Mr. Stewart is not independent as he provided consulting services to TCPL and received more than $75,000 in compensation during the 2005 financial year. Mr. Stewart's consulting contract terminated on December 31, 2005 and, assuming no other factors affect his status as an independent director, he will be considered independent on November 1, 2008.

 The Governance Committee reviews, at least annually, the existence of any relationship between each director and TCPL to ensure that the majority of directors are independent of TCPL.

 Further, the Board considered whether directors serving on boards of non-profit organizations which receive donations from TCPL pose any potential conflict. The Board determined that such relationships, where they exist, do not interfere with any such director's ability to act in the best interests of TCPL, as all decisions on making donations to non-profit organizations are made by a management committee on which no directors serve. The Board also considered family relationships and possible associations with companies which have relationships with TCPL, in its determination of independence.

 Although some of the proposed nominees sit on boards or may be otherwise associated with companies that ship natural gas on TCPL's pipeline systems, TCPL as a common carrier in Canada cannot, under its tariff, deny transportation service to a credit-worthy shipper. Further, due to the specialized nature of the industry, TCPL believes that it is important for its Board to be composed of qualified and knowledgeable directors, so some of them must come from oil and gas producers and shippers; the Governance Committee closely monitors relationships among

TRANSCANADA PIPELINES LIMITED B-1


directors to ensure that business associations do not affect the Board's performance. In a circumstance where a director declares an interest in any material contract or material transaction being considered at a meeting, the director generally absents himself or herself from the meeting during the consideration of the matter, and does not vote on the matter.

 All reporting issuers of which the nominees are presently directors of are set out in the table in TransCanada's Management Proxy Circular under the heading "Business to be Transacted at the Meeting – Election of Directors".

 In 2006, independent directors of the Board met separately after every regularly scheduled meeting. There were seven such meetings during 2006.

 Mr. Jackson has served as the Chair of TCPL since April 30, 2005. He has also acted as chair-person for Deer Creek Energy Limited (from 2001 to 2005) and Resolute Energy Inc. (from 2002 to 2005).

 The attendance record of each director for all Board and committee meetings held for the 12-month period ending December 31, 2006 is set out with each director's biography in TransCanada's Management Proxy Circular under the heading "Business to be Transacted at the Meeting – Election of Directors ".

Board Mandate

The Board discharges its responsibilities directly and through committees. At regularly scheduled meetings, members of the Board and management discuss a broad range of issues relevant to TCPL's strategy and business interests and the Board is responsible for the approval of TCPL's strategic plan. In addition, the Board receives reports from management on TCPL's operational and financial performance. The Board had seven scheduled meetings in 2006. Unscheduled meetings are held from time to time as required; there were four unscheduled meetings of the Board in 2006. There were also three strategic issue sessions and one full-day strategic planning session of the Board held in 2006.

 The Board operates under a written charter while retaining plenary power. Any responsibility not delegated to management or a committee of the Board remains with the Board. The Charter of the Board of Directors addresses Board composition and organization, and the Board's duties and responsibilities for managing the affairs of TCPL and its oversight responsibilities with respect to: management and human resources; strategy and planning; financial and corporate issues; business and risk management; policies and procedures; compliance reporting and corporate communications; and general legal obligations of TCPL. The charter is available on TransCanada's website at www.transcanada.com and is attached to TCPL's AIF as Schedule "C".

 The Board also closely oversees any potential conflicts of interest between the Company and its affiliates including TC PipeLines, LP, a public limited partnership.

 Charters have been adopted for each of the committees outlining their principal responsibilities. The Board and each committee reviews its charter annually to ensure it is in line with the current developments in corporate governance. The Board and each committee is responsible to update its respective charter. All charters are available on TransCanada's website at www.transcanada.com.

Position Descriptions

The Board has developed written position descriptions for its chair, the chair of each of the Board committees and for the CEO. The responsibilities of each committee chair are set out in each respective committee's Charter. The written position descriptions and the committee charters are available on TransCanada's website at www.transcanada.com.

 The Human Resources Committee and the Board annually review and approve the CEO's personal performance objectives and review with him or her their performance against the previous year's objectives. The Human Resources Committee's report on executive compensation can be found in TCPL's AIF under the heading "Executive Compensation and Other Information – Report on Executive Compensation".

Orientation and Continuing Education

New directors are provided with an orientation and education program that includes a directors' manual containing information about the duties and obligations of directors, the business and operations of TCPL, copies of governance

B-2 TRANSCANADA PIPELINES LIMITED

charters, copies of past public filings and documents from recent Board meetings. New directors are given additional historical and financial information, a session on corporate strategy, are provided opportunities to visit TCPL's facilities and project sites, and are provided with opportunities for meetings and discussions with the executive leadership team and other directors. Briefing sessions are also held for new committee members, as appropriate. The directors' manual and the director induction and continuing education process are reviewed annually by the Governance Committee. The details of the orientation of each new director are tailored to each director's individual needs and expressed areas of interest.

 Senior management as well as external experts make presentations to the Board and to its committees periodically on various business-related topics and on changes in legal, regulatory and industry requirements. Directors tour certain TCPL operating facilities and project sites on an annual basis. TCPL encourages continuing education for its directors, periodically suggests programs which may be relevant to the directors and provides funding for director education. All directors are members of the Canadian Institute of Corporate Directors which provides another source of director education.

Ethical Business Conduct

The Board has formally adopted and published a set of Corporate Governance Guidelines, which affirms TCPL's commitment to maintaining a high standard of corporate governance. The guidelines address the structure and composition of the Board and its committees and also provide guidance to both the Board and management in clarifying their respective responsibilities. The Board's strengths include: an independent, non-executive Chair; well informed and experienced directors who ensure that standards exist to promote ethical behaviour throughout TCPL; an effective board size; alignment with shareholders through director share ownership requirements; and annual assessments of Board, committee and individual director effectiveness. TCPL's Corporate Governance Guidelines are available on TransCanada's website at www.transcanada.com.

 The Board has also adopted a code of business ethics for directors which incorporates as its basis, principles of good conduct and highly ethical behaviour. TCPL has adopted codes of business ethics for its employees and one applicable to its CEO, Chief Financial Officer and Controller, all of which must be certified on an annual basis. Compliance with the Company's various codes is monitored by the Audit Committee and reported to the Board. There have been no departures from these codes in 2006. TCPL's codes of business ethics may be viewed on TransCanada's website at www.transcanada.com.

 In a circumstance where a director declares an interest in any material contract or material transaction being considered at a meeting, the director generally absents himself or herself from the meeting during the consideration of the matter, and does not vote on the matter.

Nomination of Directors

The Governance Committee, which is composed entirely of independent directors, is responsible for proposing new nominees to the Board, which in turn is responsible for identifying suitable candidates for election by the shareholders. The Governance Committee annually reviews the qualifications of persons proposed for election to the Board and submits its recommendations to the Board for consideration. The objective of this review is to maintain the composition of the Board in a way that provides the best mix of skills and experience to guide the long-term strategy and ongoing business operations of TransCanada. New nominees must have experience in the industries in which TCPL participates or experience in general business management of corporations that are a similar size and scope to TransCanada, the ability to devote the time required, and a willingness to serve. The Governance Committee also advises the Board on the criteria for, and determination of, the independence of each director.

 The Governance Committee maintains a matrix of skills and requirements and periodically assesses the skill set of the current Board members to identify necessary skills and backgrounds for Board candidates. The Governance Committee also maintains an "evergreen" list of potential candidates for its future consideration and periodically retains independent search firms to identify new candidates for election to the Board.

TRANSCANADA PIPELINES LIMITED B-3


 The Board has determined that no person shall stand for election or re-election to the Board if he or she attains the age of 70 years on or before the date of the annual meeting held in relation to the election of directors; provided however, that if a director attains the age of 70 before serving a full seven consecutive years on the Board, that director may stand for re-election, upon the recommendation of the Board each year until that director has served a full seven years on the Board.

 Further information relating to the Governance Committee can be found in TCPL's AIF under Schedule "D", "Description of Board Committees and Their Charters – Governance Committee".

Compensation

The Governance Committee reviews the compensation of the directors on an annual basis, taking into account such matters as time commitment, responsibility, and compensation provided by comparable companies, and makes an annual recommendation to the Board for consideration. Towers Perrin provides an annual report on directors' compensation paid by comparable companies to facilitate the Governance Committee's review of director compensation. Directors may receive their compensation in the form of cash and deferred share units. With the exception of Mr. Kvisle, who follows the Share Ownership Guidelines for executives, Directors must hold a minimum of five times their annual cash retainer fee in common shares or related deferred share units of TransCanada. Directors have a maximum of five years to reach this level of share ownership.

 The Human Resources Committee, which is composed entirely of independent directors, conducts an annual review of the performance of TCPL and the CEO as measured against objectives established in the prior year by the Board, the Human Resources Committee and the CEO. The results of this annual review are reported to the Board, which then makes an evaluation of the overall performance of TCPL and the CEO. The chair of the Board and the chair of the Human Resources Committee communicate this performance evaluation to the CEO. The evaluation is used by the Human Resources Committee in its deliberations concerning the CEO's annual compensation. The evaluation of TCPL's performance against corporate objectives also forms part of the determination of the compensation of all employees. The Human Resources Committee's report on executive compensation can be found in TCPL's AIF under the heading "Executive Compensation and Other Information – Report on Executive Compensation".

 Further information relating to the Human Resources Committee can be found in TCPL's AIF under Schedule "D", "Description of Board Committees and Their Charters – Human Resources Committee".

 Information relating to compensation consulting services provided by Towers Perrin during the 2006 financial year can be found in TCPL's AIF under the heading "Executive Compensation and Other Information – Report on Executive Compensation – Executive Compensation Advisory Services".

Other Board Committees

The Board has the following Committees: Audit; Health, Safety and Environment; Governance; and Human Resources. Details relating to these committees can be found in TCPL's AIF under Schedule "D", "Description of Board Committees and Their Charters".

Assessments

The Governance Committee is responsible for making an annual assessment of the overall performance of the Board, its committees and its individual members, and reporting its findings to the Board. An annual questionnaire is utilized as part of this process. This questionnaire is circulated to each of the directors and is administered by the Corporate Secretary.

 The questionnaire examines the effectiveness of the Board as a whole, and of each committee, and specifically reviews areas that the Board and/or management believe could be improved or enhanced to ensure the continued effectiveness of the Board and its committees in the execution of their responsibilities. Each committee also conducts an annual self-assessment, based on specific questions in the annual questionnaire. Responses are provided to the Chair and collated results are distributed to directors and discussed at the Board.

B-4 TRANSCANADA PIPELINES LIMITED


 The annual questionnaire and the individual director's terms of reference are then used in the evaluation of the contribution of individual directors. Formal interviews with each director and each member of TCPL's executive leadership team are carried out annually by the Chair with respect to this matter. The Chair of the Governance Committee also interviews each director annually on his or her assessment of the Chair's performance. All of these assessments are reported annually to the full Board.

 TCPL believes that due to the specialized nature of the industry, it is important for its Board to be composed of qualified and knowledgeable directors. During the last year, all directors demonstrated a strong commitment to their roles and responsibilities through an average 94% overall attendance rate at Board meetings and an average 95% attendance rate at committee meetings. In addition, all of the directors are available to meet with management as required.

Financial Literacy of Directors

The Board has determined that all of the members of its Audit Committee are financially literate. An individual is financially literate if he or she has the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of the issues that can reasonably be expected to be raised by TCPL's financial statements.

Majority Voting for Directors

TCPL has adopted a policy whereby, at any meeting where the number of nominees for election is the same as the number of director positions on the Board, if proxy votes withheld for the election of any particular director are greater than 5% of the votes cast by proxy, a ballot pertaining to the election of each of the directors will be held at that meeting. A director is required to tender his resignation if the director receives more votes "withheld" than "for" that director's election when such ballot is held. In the absence of extenuating circumstances, the Board is expected to accept that resignation within 90 days. The Board may fill a vacancy in accordance with TCPL's by-laws and the Canada Business Corporations Act. The policy does not apply in the event of a proxy contest with respect to the election of directors. This policy is part of TCPL's Corporate Governance Guidelines which are published on its website at www.transcanada.com.

TRANSCANADA PIPELINES LIMITED B-5

SCHEDULE "C"
CHARTER OF THE BOARD OF DIRECTORS

I.      INTRODUCTION

II.     COMPOSITION AND BOARD ORGANIZATION

III.    DUTIES AND RESPONSIBILITIES

TRANSCANADA PIPELINES LIMITED C-1

(1)
For purposes of this Charter, the term "material" includes a transaction or a series of related transactions that would, using reasonable business judgment and assumptions, have a meaningful impact on the Corporation. The impact could be relative to the Corporation's financial performance and liabilities as well as its reputation.

    v)
    taking all reasonable steps to ensure succession planning programs are in place, including programs to train and develop management;

    vi)
    approving certain matters relating to all employees, including:

    a)
    the annual salary policy/program for employees;

    b)
    new benefit programs or changes to existing programs that would create a change in cost to the Company in excess of $10,000,000 annually;

    c)
    pension fund investment guidelines and the appointment of pension fund managers; and

    d)
    material benefits granted to retiring employees outside of benefits received under approved pension and other benefit programs.

C.
Strategy and Plans

C-2 TRANSCANADA PIPELINES LIMITED

TRANSCANADA PIPELINES LIMITED C-3

IV.    GENERAL LEGAL OBLIGATIONS OF THE BOARD OF DIRECTORS

C-4 TRANSCANADA PIPELINES LIMITED

SCHEDULE "D"

DESCRIPTION OF BOARD COMMITTEES AND THEIR CHARTERS

The Board has four standing committees: the Audit Committee; the Governance Committee; the Health, Safety and Environment Committee; and the Human Resources Committee. The Board does not have an Executive Committee. The Audit, Human Resources and Governance committees are required to be composed entirely of independent directors. The Health, Safety and Environment Committee is required to have a majority of independent directors.

 Each of the committees has the authority to retain advisors to assist it in the discharge of their respective responsibilities. Each of the committees review their respective charters at least annually and, as required, recommend changes to the Governance Committee and to the Board. Each of the committees also review their respective performance annually.

 Each of the committees has a charter; the committee charters are published on TransCanada's website at www.transcanada.com.

Audit Committee

 
    
Chair:   H.G. Schaefer, F.C.A.
Members:   D.H. Burney, K.E. Benson, P. Gauthier, P.L. Joskow, J.A. MacNaughton

 This committee is comprised of six independent directors and is mandated to assist the Board in monitoring, among other things, the integrity of the financial statements of TCPL, the compliance by TCPL with legal and regulatory requirements, and the independence and performance of TCPL's internal and external auditors. The committee is also mandated to review and recommend to the Board approval of TCPL's audited annual and unaudited interim consolidated financial statements and related management discussion and analysis, and other corporate disclosure documents including information circulars, the annual information form, all prospectuses, other offering memoranda, and any financial statements required by regulatory authorities, before they are released to the public or filed with the appropriate regulatory authorities. In addition, the committee reviews and recommends to the Board the appointment and compensation of the external auditor, oversees the accounting, financial reporting, control and audit functions, and recommends funding of TCPL's pension plans.

 Audit Committee information as required under the Canadian Audit Committee Rules is contained in TCPL's Annual Information Form for the year ending December 31, 2006 in the section "Corporate Governance – Audit Committee". Audit committee information includes the charter, committee composition, relevant education and experience of each member, reliance on exemptions, financial literacy of each member, committee oversight, pre-approval policies and procedures, and external auditor service fees by category. The Annual Information Form is available on SEDAR at www.sedar.com under TCPL's profile and is published on TransCanada's website at www.transcanada.com.

 The committee oversees the operation of an anonymous and confidential toll free telephone number for employees, contractors and the public to call with respect to perceived accounting irregularities and ethical violations, and has set up a procedure for the receipt, retention, treatment and regular review of any such reported activities. This telephone number is published on TransCanada's website at www.transcanada.com, on its intranet for employees and in the Company's Annual Report to shareholders.

 The committee reviews the audit plans of the internal and external auditors and meets with them at the time of each committee meeting, in each case both with and without the presence of management. The committee annually receives and reviews the external auditor's formal written statement of independence delineating all relationships between itself and TCPL and its report on recommendations to management regarding internal controls and procedures, and ensures the rotation of the lead audit partner having primary responsibility for the audit as required by law. The committee pre-approves all audit services and all permitted non-audit services. In addition, the committee discusses with

TRANSCANADA PIPELINES LIMITED D-1


management TCPL's material financial risk exposures and the actions management has taken to monitor and control such exposures, reviews the internal control procedures to oversee their effectiveness, monitors compliance with TCPL's policies and codes of business ethics, and reports on these matters to the Board. The committee reviews and approves the investment objectives and choice of investment managers for the Canadian pension plans and considers and approves any significant changes to those plans relating to financial matters.

 There were six meetings of the Audit Committee in 2006.

Governance Committee

 
    
Chair:   W.K. Dobson
Members:   D.H. Burney, P.L. Joskow, D.P. O'Brien, H.G. Schaefer

 This committee is comprised of five independent directors and is mandated to enhance TCPL's governance through a continuing assessment of TCPL's approach to corporate governance. The committee is also mandated to identify qualified individuals to become Board members, to recommend to the Board nominees for election as directors at each annual meeting of shareholders and to annually recommend to the Board placement of directors on committees. The committee annually reviews the independence status of each director in accordance with written criteria in order to provide the Board with guidance for its annual determination of director independence and for the placement of members on committees.

 The committee reviews and reports to the Board on the performance of individual directors, the Board as a whole and each of the committees, in conjunction with the Chair of the Board. The committee also monitors the relationship between management and the Board, and reviews TCPL's structures to ensure that the Board is able to function independently of management. The committee chair annually reviews the performance of the Chair of the Board. The committee is also responsible for an annual review of director compensation and for the administration of the Share Unit Plan for Non-Employee Directors (1998), including the granting of units under the plan.

 The committee monitors best governance practice and ensures any corporate governance concerns are raised with management. The committee also ensures the Company has a best practice orientation package and monitors continuing education for all directors.

 There were two meetings of the Governance Committee in 2006.

Human Resources Committee

 
    
Chair:   K.L. Hawkins
Members:   W.K. Dobson, E.L. Draper, D.P. O'Brien

 This committee is comprised of four independent directors and is mandated to review the Company's human resources policies and plans, monitor succession planning and to assess the performance of the CEO and other senior officers of TCPL against pre-established objectives. The committee approves the salary and other remuneration to be awarded to senior executive officers of TCPL. A report on senior management development and succession is prepared annually for presentation to the Board. The committee reports to the Board with recommendations on the remuneration package for the CEO. The committee approves executive compensation plans, including actual compensation awards for the most senior officers and approves any major changes to TCPL's compensation and benefit plans. The committee considers and approves any changes to TCPL's pension plans relating to benefits provided under these plans. The committee approves grants under the Stock Option Plan and accruals pursuant to the Performance Unit Plan and has oversight responsibilities for the Executive Share Unit Plan, the Performance Share Unit Plan, the Stock Option Plan and the Performance Unit Plan.

D-2 TRANSCANADA PIPELINES LIMITED


 There were four meetings of the Human Resources Committee in 2006.

Health, Safety and Environment Committee

 
    
Chair:   E.L. Draper
Members:   P. Gauthier, K.L. Hawkins, J.A. MacNaughton, D.M.G. Stewart

 This committee is comprised of five directors, four of whom are considered independent (all members other than Mr. Stewart), and is mandated to monitor the health, safety and environmental practices and procedures of TCPL and its subsidiaries for compliance with applicable legislation, conformity with industry standards and prevention or mitigation of losses. The committee also considers whether the implementation of TCPL's policies related to health, safety and environmental matters are effective. The committee reviews reports and, when appropriate, makes recommendations to the Board on TCPL's policies and procedures related to health, safety and the environment. This committee meets separately with officers of TCPL and its business units who have responsibility for these matters and reports to the Board on such meetings.

 There were three meetings of the Health, Safety and Environment Committee in 2006.

Chair's Participation in Committees

Mr. S.B. Jackson, the Chair of the Board, is an independent director. The Chair is appointed by the Board and serves in a non-executive capacity. The Chair is a non-voting member of all committees of the Board.

TRANSCANADA PIPELINES LIMITED D-3

SCHEDULE "E"
CHARTER OF THE AUDIT COMMITTEE

1.     Purpose

2.     Roles and Responsibilities

TRANSCANADA PIPELINES LIMITED E-1

E-2 TRANSCANADA PIPELINES LIMITED

TRANSCANADA PIPELINES LIMITED E-3

E-4 TRANSCANADA PIPELINES LIMITED

3.     Composition of Audit Committee

The Audit Committee shall consist of three or more Directors, a majority of whom are resident Canadians (as defined in the Canada Business Corporations Act), and all of whom are unrelated and/or independent for the purposes of applicable Canadian and United States securities law and applicable rules of any stock exchange on which the Company's shares are listed. Each member of the Audit Committee shall be financially literate and at least one member shall have accounting or related financial management expertise (as those terms are defined from time to time under the requirements or guidelines for audit committee service under securities laws and the applicable rules of any stock exchange on which the Company's securities are listed for trading or, if it is not so defined as that term is interpreted by the Board in its business judgment).

TRANSCANADA PIPELINES LIMITED E-5


4.     Appointment of Audit Committee Members

5.     Vacancies

6.     Audit Committee Chair

7.     Absence of Audit Committee Chair

8.     Secretary of Audit Committee

9.     Meetings

10.  Quorum

E-6 TRANSCANADA PIPELINES LIMITED

11.  Notice of Meetings

12.  Attendance of Company Officers and Employees at Meeting

13.  Procedure, Records and Reporting

14.  Review of Charter and Evaluation of Audit Committee

15.  Outside Experts and Advisors

16.  Reliance

TRANSCANADA PIPELINES LIMITED E-7

GRAPHIC

GRAPHIC

Financial Highlights


 
Year ended December 31
(millions of dollars)
 
2006
 
2005
 
2004
 
2003
 
2002
 
  Income                    
      Net income applicable to common shares                    
          Continuing operations   1,049   1,208   978   801   747
          Discontinued operations   28   –   52   50   –
 
      Net income applicable to common shares   1,077   1,208   1,030   851   747
 
  Cash Flow                    
      Funds generated from operations   2,374   1,950   1,701   1,822   1,843
      (Increase)/decrease in operating working capital   (300 ) (48 ) 28   93   92
 
      Net cash provided by operations   2,074   1,902   1,729   1,915   1,935
 
      Capital expenditures and acquisitions   2,042   2,071   2,046   965   851

 
Balance Sheet
 
 
 
 
 
 
 
 
 
 
      Total assets   25,908   24,113   22,421   20,884   20,555
      Long-term debt   10,887   9,640   9,749   9,516   8,899
      Common shareholders' equity   7,618   7,164   6,484   6,044   5,747

GRAPHIC

TRANSCANADA PIPELINES LIMITED 1


TABLE OF CONTENTS

CONSOLIDATED FINANCIAL REVIEW    
  Selected Three Year Consolidated Financial Data   3
  Highlights   4
  Segment Results-at-a-Glance   5
  Results of Operations   6
SUBSEQUENT EVENTS   7
FORWARD-LOOKING INFORMATION   8

NON-GAAP MEASURES
 
8

TCPL OVERVIEW
 
8
TCPL'S STRATEGY    
  Pipelines   9
  Energy   11
  Operational Excellence   12
  Competitive Strength and Enduring Value   13
OUTLOOK   14
PIPELINES    
  Highlights   18
  Results-at-a-Glance   19
  Financial Analysis   20
  Opportunities and Developments   22
  Business Risks   27
  Other   29
  Outlook   29
  Natural Gas Throughput Volumes   31
ENERGY    
  Highlights   34
  Results-at-a-Glance   35
  Power Plants – Nominal Generating Capacity and Fuel Type   36
  Financial Analysis   36
  Opportunities and Developments   46
  Business Risks   46
  Outlook   47
CORPORATE    
  Results-at-a-Glance   48
DISCONTINUED OPERATIONS   49
LIQUIDITY AND CAPITAL RESOURCES    
  Summarized Cash Flow   49
  Highlights   50
CONTRACTUAL OBLIGATIONS    
  Contractual Obligations   52
  Principal Repayments   52
  Interest Payments   53
  Purchase Obligations   53

FINANCIAL AND OTHER INSTRUMENTS
 
55

RISKS AND RISK MANAGEMENT
 
60

CONTROLS AND PROCEDURES
 
62

SIGNIFICANT ACCOUNTING POLICIES AND CRITICAL ACCOUNTING ESTIMATES
 
62

ACCOUNTING CHANGES
 
64

SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA
 
65

FOURTH QUARTER 2006 HIGHLIGHTS
 
67

SHARE INFORMATION
 
68

OTHER INFORMATION
 
68

GLOSSARY OF TERMS
 
69

2 MANAGEMENT'S DISCUSSION AND ANALYSIS

The Management's Discussion and Analysis (MD&A) dated February 22, 2007 should be read in conjunction with the audited Consolidated Financial Statements of TransCanada PipeLines Limited (TCPL or the Company) and the notes thereto for the year ended December 31, 2006. This MD&A covers TCPL's financial position and operations as at and for the year ended December 31, 2006. TCPL's February 22, 2007 acquisition of American Natural Resources Company, and ANR Storage Company (collectively ANR), additional interests in Great Lakes Gas Transmission Partnership (Great Lakes) and related events, are summarized in the "Subsequent Events" section of this MD&A. Amounts are stated in Canadian dollars unless otherwise indicated. Abbreviations and acronyms used in this MD&A are identified in the Glossary of Terms of the Company's 2006 Annual Report.

CONSOLIDATED FINANCIAL REVIEW

SELECTED THREE YEAR CONSOLIDATED FINANCIAL DATA(1)
(millions of dollars except per share amounts)

    2006   2005   2004
Balance Sheet            
Total assets   25,908   24,113   22,421
Total long-term liabilities   14,464   13,012   12,403

Income Statement
 
 
 
 
 
 
Revenues   7,520   6,124   5,497

Net income applicable to common shares
 
 
 
 
 
 
  Continuing operations   1,049   1,208   978
  Discontinued operations   28   –   52
  Total net income   1,077   1,208   1,030

Per Common Share Data
 
 
 
 
 
 
Net income – Basic and Diluted            
  Continuing operations   $2.17   $2.50   $2.03
  Discontinued operations   0.06   –   0.11
    $2.23   $2.50   $2.14
(1)
The selected three-year consolidated financial data is based on the Company's financial statements which are prepared in accordance with Canadian generally accepted accounting principles (GAAP). Certain comparative figures have been reclassified to conform with the current year's presentation.

MANAGEMENT'S DISCUSSION AND ANALYSIS 3

HIGHLIGHTS

Balance Sheet

Net Income

Net Earnings

Investing Activities


Financing Activities

Dividends

4 MANAGEMENT'S DISCUSSION AND ANALYSIS

SEGMENT RESULTS-AT-A-GLANCE
Year ended December 31 (millions of dollars)

    2006   2005   2004  
 

Pipelines Net Earnings
 
 
 
 
 
 
 
  Excluding gains   547   630   577  
  Gain on sale of Northern Border Partners, L.P. interest   13   –   –  
  Gain on sale of PipeLines LP units   –   49   –  
  Gain on sale of Millennium   –   –   7  
 
    560   679   584  
 

Energy Net Earnings
 
 
 
 
 
 
 
  Excluding gains   452   258   211  
  Gain on sale of Paiton Energy   –   115   –  
  Gains related to Power LP   –   193   187  
 
    452   566   398  
 
Corporate   37   (37 ) (4 )
 

Net Income Applicable to Common Shares
 
 
 
 
 
 
 
  Continuing Operations1   1,049   1,208   978  
  Discontinued Operations   28   –   52  
 
    1,077   1,208   1,030  
 

Net Income Per Common Share Data
 
 
 
 
 
 
 
  Continuing Operations2   $2.17   $2.50   $2.03  
  Discontinued Operations   0.06   –   0.11  
 
  Basic   $2.23   $2.50   $2.14  
 
  (1)Net Income Applicable to Common Shares from Continuing Operations:            
    Excluding gains   1,036   851   784
    Gains as noted above   13   357   194
    1,049   1,208   978
  (2)Net Income Applicable to Common Share Data from Continuing Operations:            
    Excluding gains   $2.17   $1.76   $1.63
    Gains as noted above   0.03   0.74   0.40
    $2.17   $2.50   $2.03

MANAGEMENT'S DISCUSSION AND ANALYSIS 5

RESULTS OF OPERATIONS

Effective June 1, 2006, TCPL revised the composition and names of its reportable business segments to Pipelines and Energy. The financial reporting of these segments was aligned to reflect the internal organizational structure of the Company. Pipelines principally comprises the Company's pipelines in Canada, the U.S. and Mexico. Energy includes the Company's power operations, natural gas storage business and liquefied natural gas (LNG) projects in Canada and the U.S. The segmented information has been retroactively reclassified to reflect the changes in reportable segments. These changes had no impact on consolidated net income.

Net income applicable to common shares for the year ended December 31, 2006 was $1,077 million compared to $1,208 million for 2005 and $1,030 million for 2004. This includes net income from discontinued operations of $28 million in 2006, reflecting bankruptcy settlements with Mirant Corporation and certain of its subsidiaries (Mirant) related to TCPL's Gas Marketing business divested in 2001. Income from discontinued operations of $52 million in 2004 reflects income recognized on initially deferred gains relating to Mirant.

Net earnings for the year ended December 31, 2006 were $1,049 million compared to $1,208 million in 2005 and $978 million in 2004. Net earnings for 2006 included after-tax gains of $13 million from the sale of TCPL's general partner interest in Northern Border Partners, L.P. Net earnings for 2005 included after-tax gains of $193 million on the sale of the Company's interest in TransCanada Power, L.P. (Power LP), $115 million on the sale of the Company's interest in P.T. Paiton Energy Company (Paiton Energy) and $49 million on the sale of PipeLines LP units.

Excluding gains of $13 million in 2006 and $357 million in 2005, net earnings in 2006 were $1,036 million, an increase of $185 million compared to 2005. This increase was mainly due to higher net earnings in Energy and Corporate, partially offset by decreased net earnings in Pipelines.

Excluding the gains on sale of the Northern Border Partners, L.P. interest in 2006 and the PipeLines LP units in 2005, net earnings in the Pipelines business decreased $83 million in 2006 compared to 2005. The decrease was primarily due to lower net earnings from the Canadian Mainline and the Alberta System as a result of lower approved rates of return on common equity (ROE) and lower average investment bases in 2006 compared to 2005. In addition, the Company's Other Pipelines businesses and the Gas Transmission Northwest System and the North Baja system (collectively GTN) experienced lower earnings in 2006.

Excluding the gain on the sale of Paiton Energy and gains related to the Company's investment in Power LP in 2005, Energy's net earnings for 2006 increased $194 million compared to 2005 as a result of higher operating income from each of its existing businesses as well as a $23-million favourable impact on future income taxes arising from reductions in Canadian federal and provincial income tax rates in 2006. These increases were partially offset by a loss of operating income associated with the sale of Power LP in 2005.

The increase in Corporate's net earnings in 2006 of $74 million compared to 2005 was primarily due to $72 million of positive income tax adjustments in 2006.

Net earnings increased $230 million in 2005 compared to 2004. The increase was primarily due to the inclusion of gains of $357 million in 2005 compared to gains of $194 million in 2004. Excluding gains, Pipeline's net earnings increased due to the inclusion of a full year of earnings from GTN in 2005 and the positive impact on earnings of a National Energy Board (NEB) decision to increase the Canadian Mainline's common equity component in its deemed capital structure. This was partially offset by the Canadian Mainline's lower average investment base, lower earnings related to operating cost savings, a decrease in the approved ROE and lower net earnings from the Company's Other Pipelines' businesses in 2005. Energy's net earnings, excluding gains, increased in 2005, compared to 2004, primarily due to higher operating income from Bruce Power A L.P. (Bruce A) and Bruce Power L.P. (Bruce B) (collectively Bruce Power), and Eastern Power Operations. A lower contribution from Western Power Operations and higher general administrative, support costs and other also reduced Energy's net earnings in 2005 compared to 2004. Corporate's net expenses increased in 2005 compared to 2004, primarily due to increased net interest expense on higher average long-term debt and commercial paper balances in 2005.

6 MANAGEMENT'S DISCUSSION AND ANALYSIS

SUBSEQUENT EVENTS

ANR Acquisition

On February 22, 2007, TCPL closed the acquisition of ANR and an additional 3.55 per cent interest in Great Lakes from El Paso Corporation for approximately US$3.4 billion, subject to certain post-closing adjustments, including approximately US$488 million of assumed long-term debt. The acquisition of ANR added approximately 17,000 kilometres (km) of natural gas transmission pipeline with a peak-day capacity of 6.8 Bcf/d. ANR also owns and operates natural gas storage facilities with a total capacity of approximately 230 Bcf. The acquisition was financed with a combination of proceeds from the Company's recent issuance of $1.3 billion of common shares, cash on hand and funds drawn on existing and newly established loan facilities, discussed below.

In February 2007, the Company, through a wholly owned subsidiary, executed an agreement with a syndicate of banks to establish a new US$1.0 billion credit facility, consisting of a US$700 million five-year term loan and a US$300 million five-year extendible revolving facility. This facility is committed and unsecured. The Company utilized US$1.0 billion from this facility and an additional US$100 million from an existing demand line to partially finance the ANR acquisition as well as additional investments in PipeLines LP, described below.

Great Lakes Acquisition

On February 22, 2007, PipeLines LP closed its acquisition of a 46.45 per cent interest in Great Lakes from El Paso Corporation for approximately US$962 million, which included approximately US$212 million of assumed long-term debt, subject to certain post-closing adjustments. At December 31, 2006, TransCanada had a 13.4 per cent interest in PipeLines LP.

In February 2007, PipeLines LP increased the size of its syndicated revolving credit and term loan agreement from US$410 million to US$950 million. Incremental draws of US$126 million received under this agreement were used to partially finance PipeLines LP's Great Lakes acquisition.

On February 22, 2007, PipeLines LP completed a private placement offering of 17,356,086 common units at a price of US$34.57 per unit, of which 50 per cent of the units were acquired by TCPL, for US$300 million. TCPL also invested an additional approximately US$12 million to maintain its general partnership ownership interest in PipeLines LP. As a result of TCPL's additional investments in Pipelines LP, its ownership in PipeLines LP increased to 32.1 per cent. The total private placement resulted in gross proceeds to PipeLines LP of US$612 million, which were used to partially finance its Great Lakes acquisition. As a result of TCPL's increased ownership in PipeLines LP, TCPL's effective ownership in Tuscarora Gas Transmission Company (Tuscarora), Northern Border Pipeline Company (Northern Border) and Great Lakes increased to 32.5 per cent (including one per cent held directly), 16.1 per cent and 68.5 per cent (including 53.55 per cent held directly), respectively.

MANAGEMENT'S DISCUSSION AND ANALYSIS 7

FORWARD-LOOKING INFORMATION

Certain information in this MD&A includes forward-looking statements. All forward-looking statements are based on TCPL's beliefs and assumptions based on information available at the time such statements were made. Factors which could cause actual results or events to differ materially from current expectations include, among other things, the ability of TCPL to successfully implement its strategic initiatives and whether such strategic initiatives will yield the expected benefits, the availability and price of energy commodities, regulatory decisions, changes in environmental and other laws and regulations, competitive factors in the pipeline and energy industry sectors, construction and completion of capital projects, access to capital markets, interest and currency exchange rates, technological developments and the current economic condition in North America. By its nature, such forward-looking information is subject to various risks and uncertainties, which could cause TCPL'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 of this MD&A or as otherwise stated. TCPL undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, except as required by law.

NON-GAAP MEASURES

The Company uses the measures "funds generated from operations" and "operating income" in this MD&A. These measures do not have any standardized meaning in GAAP and are therefore considered to be non-GAAP measures. These measures may not be comparable to similar measures presented by other entities. These measures have been used to provide readers with additional information on the Company's liquidity and its ability to generate funds to finance its operations.

Funds generated from operations is comprised of net cash provided by operations before changes in operating working capital. A reconciliation of funds generated from operations to net cash provided by operations is presented in the Summarized Cash Flow table in this MD&A. Operating income is used in the Energy segment and is comprised of revenues plus income from equity investments less operating expenses as shown on the consolidated income statement. Refer to the Energy section in this MD&A for a reconciliation of operating income to net earnings.

TCPL OVERVIEW

TCPL is a leading North American energy infrastructure company with a strong focus on natural gas transmission and power generation opportunities located in regions in which it has significant competitive advantages. Natural gas transmission and power are complementary businesses for TCPL. They are driven by similar supply and demand fundamentals, they are both capital-intensive businesses, and they use similar technology and operating practices. They are also businesses with significant long-term growth prospects.

North American natural gas demand is expected to increase primarily due to a growing 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 by higher utilization of existing natural gas-fired generating plants.

Nuclear facilities have played, and will continue to play, a significant role in supplying North American power. Coal-fired plants remain the largest source of electric power in North America and coal reserves are significant. However, the long lead times required to complete new coal and nuclear projects 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. Natural gas demand in North America, including Mexico, is expected to

8 MANAGEMENT'S DISCUSSION AND ANALYSIS


grow to approximately 89 billion cubic feet per day (Bcf/d) by 2016, an increase of 14 Bcf/d when compared to 2006. New natural gas-fired power generation is expected to account for approximately 9 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. Natural gas supply is limited 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 essentially remain flat over the next decade. An increase in production in the U.S. Rockies is expected to offset declines in other basins, including the Gulf of Mexico. This outlook for traditional basins means that northern gas and offshore LNG will be required to fill the shortfall between supply and demand. TCPL is well positioned in North America to serve growing power generation demand in the near term and to bring these new natural gas supplies to market in the medium to long term.

TCPL'S STRATEGY

TCPL's strong position in North America is the direct result of successfully executing its corporate strategy which was first adopted in 2000. While the plan has evolved over time in response to actual and anticipated changes in the business environment, it fundamentally remains the same. Today, TCPL's corporate strategy consists of the following six components:

Pipelines

Strategy

The Company's strategy in Pipelines is focused on both growing its North American natural gas transmission network and maximizing the profitability and long-term value of its existing pipeline assets. In order to grow the Pipelines segment, TCPL is focusing on expanding and extending its existing systems to connect new supply to growing markets, increasing its ownership in partially owned entities, acquiring or constructing pipelines that provide TCPL with a significant regional presence, expanding into the oil transmission business and, in the long term, connecting new sources of supply in the form of northern gas and LNG.

Over the past 50 years, TCPL 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, TCPL operates one of the largest, most sophisticated, remote-controlled pipeline networks in the world with a solid reputation for safety and reliability.

In addition to growing the North American Pipelines business, the Company continues to place a priority on maximizing the profitability and long-term value of its 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 TCPL's regulated pipelines. Further, the Company works collaboratively with its customers to develop and implement new services. TCPL also provides services to many of its partially owned pipeline systems.

MANAGEMENT'S DISCUSSION AND ANALYSIS 9


Existing Pipelines

TCPL's natural gas transmission assets link the Western Canada Sedimentary Basin (WCSB) with premium North American markets. With approximately 42,000 km of pipeline (at December 31, 2006), the Company's network of wholly owned pipeline assets is one of the largest in North America.

In 2006, the wholly owned Alberta System gathered 67 per cent of the natural gas produced in western Canada or 17 per cent of total North American production. TCPL exports natural gas from the WCSB to Eastern Canada and the U.S. West, Midwest and Northeast through four wholly owned pipeline systems:

In addition, the Company transports natural gas in Alberta through the TCPL Pipeline Ventures Limited Partnership (Ventures LP) System.

In December 2006, TCPL began transporting natural gas in Mexico through its Tamazunchale pipeline.

TCPL also exports gas from the WCSB to eastern Canada as well as the U.S. West, Midwest and Northeast through six partially owned pipeline systems:

Northern Development

In 2006, TCPL continued to pursue the Mackenzie Delta and Alaska North Slope projects. When the Mackenzie Gas Pipeline (MGP) project and the Alaska Highway Pipeline project are constructed and connected to TCPL's existing infrastructure, they would represent additional growth opportunities for TCPL and enhance the long-term viability and value of the Company's existing Pipelines business, especially the wholly owned pipelines currently transporting WCSB natural gas.

Mexico

In addition to the Tamazunchale pipeline, TCPL continues to explore other pipeline and energy infrastructure opportunities in Mexico.

ANR and Great Lakes

On February 22, 2007, TCPL closed its acquisition of ANR and an additional 3.55 per cent interest in Great Lakes. In addition, PipeLines LP closed its acquisition of a 46.45 per cent interest in Great Lakes.

10 MANAGEMENT'S DISCUSSION AND ANALYSIS

Regulatory

In 2006, TCPL's principal regulatory activities included a negotiated settlement with respect to 2006 Canadian Mainline tolls; filing a rate case with the Federal Energy Regulatory Commission (FERC) for new Gas Transmission Northwest System rates; filing an application with the NEB to integrate the BC System into the Foothills Zone 8 facilities and (received NEB approval in February 2007); filing an application with the NEB seeking approval to transfer approximately 860 km of the Canadian Mainline's existing natural gas pipeline to oil service; filing an application with the NEB to construct and operate approximately 370 km of new oil pipeline, terminal facilities and pump stations; and filing applications that sought approval to transfer a portion of the Canadian Mainline's assets to Keystone and to reduce the Canadian Mainline's rate base by the net book value (NBV) of the transferred assets (received NEB approval in February 2007).

Energy

Strategy

TCPL's strategy for growth and value creation in the Energy business has five key elements:

TCPL's ability to successfully execute its strategy is related to 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. In addition, the Company actively participates in deregulated and deregulating markets and has the ability to structure transactions and manage risk, which is critical to mitigating volatility in natural gas and power markets.

Existing Assets

TCPL has built a substantial energy business over the past decade and has achieved a significant presence in power generation across Canada and the U.S. More recently, TCPL has developed its natural gas storage business through investments in Alberta.



GRAPHIC

 

The power plants and power supply that TCPL owns, operates and/or controls, including projects under construction, represent approximately 7,700 megawatts (MW) of power generation capacity in Canada and the U.S. TCPL's portfolio of power supply is diversified: 33 per cent natural gas; 32 per cent nuclear; 22 per cent coal; seven per cent hydro and six per cent wind. TCPL's power assets are primarily low-cost, base load generation and/or backed by secure, long-term power sales agreements. The Company's power assets are concentrated in two main regions: Western Power Operations in Alberta and Eastern Power Operations in the eastern Canada and New England markets.
Energy's natural gas storage assets are all located in Alberta. TCPL owns or controls more than 130 billion cubic feet (Bcf) or approximately one third of the natural gas storage
capacity in the province. TCPL believes the market fundamentals for natural gas storage will remain strong into the future.

MANAGEMENT'S DISCUSSION AND ANALYSIS 11

In 2006, TCPL continued to add to its diverse portfolio of existing quality energy assets as follows:

Bécancour

Construction of the Bécancour cogeneration plant was completed and placed commercially in service in September 2006. The project was completed on time and under budget and is the largest greenfield power plant built by TCPL to date.

Portlands Energy

In September 2006, Portlands Energy Centre L.P. (Portlands Energy) announced that it had signed a 20-year Accelerated Clean Energy Supply (ACES) contract with the Ontario Power Authority (OPA) to construct a natural gas generation plant to be located in downtown Toronto, Ontario.

Cartier Wind

In November 2006, the Baie-des-Sables wind farm went into commercial operation and is currently one of the largest wind farms in Canada, providing 110 MW of power to the Hydro-Québec grid.

Halton Hills

In November 2006, TCPL announced that it had been awarded a contract to build, own and operate a natural gas-fired power plant near the town of Halton Hills, Ontario.

Bruce Power

Throughout 2006, work continued on the Bruce A capital project, consisting of the restart and refurbishment of the currently idle Units 1 and 2, extension of the operating life of Unit 3 by replacing its steam generators and fuel channels when required, and replacement of the steam generators on Unit 4.

Edson Gas Storage

Construction of the Edson natural gas storage facility was substantially completed and placed into service on December 31, 2006.

Broadwater and Cacouna LNG Facilities

TCPL continues to pursue these two LNG proposals.

Operational Excellence

TCPL maintains a high level of pipeline operating performance, as measured by the minimal disruptions for the Canadian Mainline, the Alberta System and GTN.

In 2006, TCPL developed a technology program involving techniques to reduce the cost and environmental impact of constructing new pipeline. The program, which negates the need for large volumes of water, was applied to a segment of TCPL's pipeline construction. The technology was accepted by the NEB which is expected to encourage further development by TCPL and to promote wide-scale use.

Through its annual Customer Satisfaction Survey, TCPL received feedback from customers served by its Canadian pipelines. The survey, conducted by Ipsos Reid in the fall of 2006, found that TCPL maintained high levels of overall customer satisfaction. TCPL's call centre, transactional systems and staff obtained the highest satisfaction levels. This reflects TCPL's commitment to operational excellence in the provision of reliable and high-quality service to customers.

The Company was very productive in 2006 with respect to collaborative efforts with customers. The Mainline Tolls Task Force, the Alberta System Tolls, Tariff, Facilities and Procedures Committee, and the BC System and Foothills Shippers group produced a number of resolutions in 2006. These resolutions included new services, service enhancements,

12 MANAGEMENT'S DISCUSSION AND ANALYSIS


process improvements, a Canadian Mainline tolls settlement and the proposed integration of the BC System into the Foothills system, which was approved by the NEB in February 2007. Productive collaborative processes can result in significant costs savings for both TCPL and the industry by avoiding costs associated with regulatory proceedings.

In Energy, TCPL continued its commitment in 2006 to provide safe, low-cost operations and maintenance of all assets to ensure the highest possible reliability and availability. For power plants directly operated by TCPL, the weighted average plant availability in 2006 was 93 per cent compared to 87 per cent in 2005.

In 2007, TCPL will continue to focus efforts on efficiencies, operational reliability, the environment and safety. Greenhouse gas emissions management programs will continue to receive attention and further efforts will be undertaken to improve contractor safety.

Competitive Strength and Enduring Value

TCPL's strategy includes:

At December 31, 2006, TCPL had approximately 2,350 employees who have expertise in gas transmission and power operations, project management, depth of market and industry knowledge, and financial acumen.

MANAGEMENT'S DISCUSSION AND ANALYSIS 13

OUTLOOK

Since 2000, TCPL has followed a long-term approach of growing its Pipelines and Energy businesses in a diligent and disciplined manner. In 2007 and beyond, the Company's net earnings and cash flow, combined with a strong balance sheet, are expected to continue to provide the financial flexibility for TCPL to pursue opportunities and create additional long-term value for its shareholders.

In 2007, the Company will continue to implement its Pipelines strategy, including:

TCPL will continue to grow its Energy business in 2007. As in prior years, this growth is expected to come from a mix of greenfield developments, new acquisitions and organic growth within its existing assets and markets. In particular, in 2007, TCPL expects to:

Although the following discussion reflects management's expectations for 2007, as discussed throughout this MD&A, a number of risk factors and developments may positively or negatively affect the actual results for 2007, as discussed throughout this MD&A, including the section entitled "Forward-Looking Information".

14 MANAGEMENT'S DISCUSSION AND ANALYSIS

With the closing of the acquisition of ANR and Great Lakes, and the Company's increased ownership in PipeLines LP, TCPL expects higher net earnings from Pipelines in 2007 compared to 2006. The combined effect of an expected decline in the average investment base of each of the Canadian Mainline and the Alberta System, and a decline in each of their formula-based regulated ROEs is expected to decrease net earnings on these systems compared to 2006. Excluding any potential positive impact from a decision or settlement on the current rate case filing for the Gas Transmission Northwest System, reduced firm contract volumes on this system are expected to have a slightly negative impact on the results compared to 2006. In addition, Pipelines' 2006 net earnings included a $13 million gain on the sale of Northern Border Partners, L.P. interest, which will not occur in 2007. In 2007, TCPL is expecting a positive impact from a full year of earnings from the Tamazunchale pipeline.

In Energy, net earnings in 2007 are expected to approximate or be slightly lower than 2006 net earnings due to the non-recurring $23-million future tax benefit in 2006 arising from reductions in federal and provincial income tax rates. Operating income is expected to be relatively consistent with 2006, although this is very dependent on commodity prices in each region as well as other factors such as hydrology and storage spreads. TCPL's operating income from its investment in Bruce B can be significantly impacted by the effect, on uncontracted output, of changes in spot market prices for power. Excluding any changes in spot market prices for 2007 compared to 2006, Bruce Power's operating income is expected to decline in 2007 compared to 2006, reflecting lower projected generation volumes and higher operating costs resulting from an increase in planned outages in 2007. Western Power Operations' operating income in 2007 is expected to approximate 2006. Although TCPL has sold forward significant output from its Alberta power purchase agreements (PPA) and power plants, Western Power Operations' operating income in 2007 can be significantly impacted by changes in the spot market price of power and market heat rates in Alberta. Eastern Power Operations' operating income is expected to increase in 2007 primarily due to a full year of operations for both the Bécancour natural gas-fired cogeneration facility and the first of six wind farms of the Cartier Wind project as well as the positive impact of the New England Power Pool (NEPOOL) forward capacity payments received by Ocean State Power (OSP) and TC Hydro commencing December 1, 2006. Gas Storage's operating income is expected to increase in 2007 over 2006 primarily due to the placing into service of the Edson facility at the end of 2006, partially offset by expected lower storage spreads.

Corporate's net expenses are expected to be higher in 2007 compared to 2006 primarily due to the income tax refunds and positive income tax adjustments realized in 2006 that are not expected to recur in 2007. Financing costs associated with the purchase of ANR are expected to increase net expenses in Corporate in 2007.

MANAGEMENT'S DISCUSSION AND ANALYSIS 15

GRAPHIC

CANADIAN MAINLINE   TCPL's 100 per cent owned 14,957 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   TCPL'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, Foothills and other pipelines. The 23,498 km system is one of the largest carriers of natural gas in North America.

GAS TRANSMISSION NORTHWEST SYSTEM   TCPL's 100 per cent owned natural gas transmission system extends 2,174 km and links the BC System and Foothills with Pacific Gas and Electric Company's California Gas Transmission System, with Williams' Northwest Pipeline in Washington and Oregon, and with Tuscarora.

FOOTHILLS   TCPL'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.

16 MANAGEMENT'S DISCUSSION AND ANALYSIS


BC SYSTEM   TCPL's 100 per cent owned natural gas transmission system extends 201 km from Alberta's western border through British Columbia (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   TCPL's 100 per cent owned natural gas transmission system extends 129 km from southwestern Arizona at Ehrenberg to a point near Ogilby, California on the California/Mexico border and connects with the Gasoducto Bajanorte pipeline system in Mexico.

VENTURES LP   Ventures LP, which is 100 per cent owned by TCPL, 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.

TAMAZUNCHALE   TCPL's 100 per cent owned 130 km natural gas pipeline in east central Mexico extends from the facilities of Pemex Gas near Naranjos, Veracruz to an electricity generation station near Tamazunchale, San Luis Potosi. This pipeline went into service on December 1, 2006.

ANR   On February 22, 2007, TCPL acquired 100 per cent of the ANR natural gas transmission system which extends approximately 17,000 km from producing fields in Louisiana, Oklahoma, Texas and the Gulf of Mexico to markets in Wisconsin, Michigan, Illinois, Ohio and Indiana. This pipeline also connects with other pipelines to give access to supply from western Canada, the Rocky Mountain region and a variety of markets in the midwestern and northeastern U.S. ANR also owns and operates underground natural gas storage facilities in Michigan with a total capacity of approximately 230 Bcf.

TUSCARORA   Tuscarora is owned or controlled 99 per cent by PipeLines LP and is a 491 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. TCPL operates Tuscarora and, at February 22, 2007, effectively owns or controls an aggregate 32.8 per cent interest in Tuscarora, of which 31.8 per cent is held indirectly through TCPL's 32.1 per cent ownership interest in PipeLines LP and the remaining one percent is owned directly.

NORTHERN BORDER   Northern Border is 50 per cent owned by PipeLines LP and is a 2,250 km natural gas pipeline system which serves the U.S. Midwest from a connection with Foothills near Monchy, Saskatchewan. In April 2007, TCPL expects to become the operator of Northern Border. At February 22, 2007, the Company effectively owns approximately 16.1 per cent of Northern Border through its 32.1 per cent ownership interest in PipeLines LP.

GREAT LAKES   Great Lakes is a 3,404 km pipeline system that connects with the Canadian Mainline at Emerson, Manitoba and serves markets in central Canada and the midwestern U.S. Effective February 22, 2007, TCPL owns 53.55 per cent of Great Lakes and PipeLines LP owns the remaining 46.45 per cent. TCPL's effective ownership of Great Lakes is 68.5 per cent of which 14.9 per cent is held indirectly through its 32.1 per cent ownership in PipeLines LP. TCPL is the operator of Great Lakes.

IROQUOIS   Iroquois connects with the Canadian Mainline near Waddington, New York and delivers natural gas to customers in the northeastern U.S. TCPL has a 44.5 per cent ownership interest in this 666 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. TCPL holds a 50 per cent ownership interest in TQM and is the operator.

PORTLAND   Portland is a 474 km pipeline that connects with TQM near East Hereford, Québec and delivers natural gas to customers in the northeastern U.S. TCPL has a 61.7 per cent ownership interest in Portland and operates this pipeline.

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. TCPL 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. TCPL 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. TCPL holds a 30 per cent ownership interest in INNERGY.

MANAGEMENT'S DISCUSSION AND ANALYSIS 17

HIGHLIGHTS

Net Earnings


ANR and Great Lakes Acquisition

Canadian Mainline

Alberta System

Gas Transmission Northwest System

Keystone

Foothills and BC System

North Baja

PipeLines LP

Other Pipelines

18 MANAGEMENT'S DISCUSSION AND ANALYSIS

PIPELINES RESULTS-AT-A-GLANCE
Year ended December 31 (millions of dollars)

    2006   2005   2004  
 
Wholly Owned Pipelines              
  Canadian Mainline   239   283   272  
  Alberta System   136   150   150  
  GTN(1)   64   71   14  
  Foothills   21   21   22  
  BC System   6   6   7  
 
    466   531   465  
 

Other Pipelines
 
 
 
 
 
 
 
  Great Lakes   44   46   55  
  Iroquois   15   17   17  
  PipeLines LP(2)   4   9   16  
  Portland   13   11   10  
  Ventures LP   12   12   15  
  TQM   7   7   8  
  Tamazunchale(3)   2   –   –  
  TransGas   11   11   11  
  Gas Pacifico/INNERGY(4)   8   6   4  
  Northern Development   (5 ) (4 ) (6 )
  General, administrative, support costs and other   (30 ) (16 ) (18 )
 
    81   99   112  
Gain on sale of Northern Border Partners, L.P. interest   13   –   –  
Gain on sale of PipeLines LP units   –   49   –  
Gain on sale of Millennium   –   –   7  
 
    94   148   119  
 
Net earnings   560   679   584  
 
(1)
TCPL acquired GTN in November 2004. Amounts in this table reflect TCPL's 100 per cent ownership interest in GTN's net earnings from the acquisition date.

(2)
During 2005, TCPL decreased its ownership interest in PipeLines LP to 13.4 per cent from 33.4 per cent.

(3)
The Tamazunchale pipeline went into service December 1, 2006.

(4)
Gasoducto del Pacifico S.A./INNERGY Holdings S.A.

In 2006, net earnings from the Pipelines business were $560 million compared to $679 million and $584 million in 2005 and 2004, respectively. Excluding the $49-million after-tax gain on the sale of PipeLines LP units in 2005 and the $13-million after-tax gain on the sale of TCPL's general partner interest in Northern Border Partners, L.P. in 2006, Pipelines' net earnings for the year ended December 31, 2006 decreased $83 million compared to the same period in 2005. This decrease was primarily due to lower net earnings from the Canadian Mainline, the Alberta System, GTN and Other Pipelines.

The overall increase of $95 million in 2005 Pipelines net earnings compared to 2004 was mainly due to a full year of GTN net earnings, the $49-million gain related to PipeLines LP and higher Canadian Mainline net earnings in 2005 as a result of an April 2005 NEB decision that resulted in a positive $13-million adjustment related to 2004, partially offset

MANAGEMENT'S DISCUSSION AND ANALYSIS 19


by lower net earnings from Other Pipelines. Lower 2005 net earnings from Other Pipelines were primarily due to decreased earnings from Great Lakes, PipeLines LP and Ventures LP.

PIPELINES – FINANCIAL ANALYSIS

Canadian Mainline

The Canadian Mainline is regulated by the NEB. The NEB sets tolls which provide TCPL with the opportunity to recover its projected costs of transporting natural gas, including a return on the Canadian Mainline's average investment base. In addition, new facilities are approved by the NEB before construction begins. Net earnings of the Canadian Mainline are affected by changes in the investment base, the ROE, the level of deemed common equity and potential incentive earnings.

In April 2006, the NEB approved TCPL's application for a negotiated settlement of the 2006 Canadian Mainline tolls as filed. The settlement resulted in a revenue requirement of approximately $1.8 billion for 2006. The settlement also established the Canadian Mainline's fixed OM&A costs for 2006 at $174 million with variances between actual OM&A costs in 2006 and those agreed to in the settlement accruing to TCPL. The majority of the other cost elements of the 2006 revenue requirement were to be treated on a flow-through basis. The settlement also provided TCPL with an opportunity to realize modest additional net earnings through performance-based incentive arrangements. These incentive arrangements were focused on certain cost management activities and the management of fuel, and provided mutual benefits to both TCPL and its customers. Further, the settlement included an ROE of 8.88 per cent as determined for 2006 under the NEB's return adjustment formula, on a deemed common equity ratio of 36 per cent.

Net earnings of $239 million in 2006 were $44 million lower than 2005 net earnings of $283 million. The decrease was primarily due to a combination of a lower ROE and a lower average investment base in 2006 compared to 2005. In addition, 2005 net earnings included a positive adjustment of $13 million related to 2004 as a result of the NEB's decision in April 2005 on the Canadian Mainline's 2004 Tolls and Tariff Application (Phase II) which included an increase in the deemed common equity ratio to 36 per cent from 33 per cent for 2005 that was also effective for 2004. The 2006 NEB-approved Canadian Mainline tolls settlement that TCPL reached with its customers and other interested parties included an ROE of 8.88 per cent, which was determined for 2006 under the NEB's return adjustment formula on a deemed common equity ratio of 36 per cent. The NEB-approved ROE for 2005 was 9.46 per cent.

The Canadian Mainline generated net earnings of $283 million in 2005, an increase of $11 million over 2004 earnings. The increase in net earnings was primarily due to the NEB's decision on the 2004 Tolls and Tariff Application (Phase II). The Phase II decision resulted in a $35-million ($22 million related to 2005 and $13 million related to 2004) increase to the Canadian Mainline's 2005 net earnings compared to 2004. However, this earnings increase was partially offset by the combination of a lower average investment base, lower cost savings and a lower approved ROE in 2005. The NEB-approved ROE decreased to 9.46 per cent in 2005 from 9.56 per cent in 2004.

GRAPHIC

20 MANAGEMENT'S DISCUSSION AND ANALYSIS

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, the Alberta System's rates, tolls and other charges, and terms and conditions of service are subject to approval by the EUB.

The Alberta System is currently operating under the 2005-2007 Revenue Requirement Settlement. The settlement was reached in 2005 with shippers and other interested parties regarding the annual revenue requirements of its Alberta System for the years 2005, 2006 and 2007. The settlement was approved by the EUB in June 2005 and encompassed all elements of the Alberta System revenue requirement, including operating, maintenance and administration (OM&A) costs, ROE, depreciation and income and municipal taxes.

The Alberta System settlement fixed OM&A costs at $193 million for 2005, $201 million for 2006, and $207 million for 2007. In each year, any variance between actual OM&A and other fixed costs, and those agreed to in the settlement accrues to TCPL. The majority of other cost elements of the 2005, 2006 and 2007 revenue requirements are treated on a flow-through basis.

The ROE will be calculated annually during the term of the settlement using the EUB formula for the purpose of establishing the annual generic rate of return for Alberta utilities on deemed common equity of 35 per cent. In addition, depreciation costs are determined using the depreciation rates and methodology that the Company proposed to the EUB in its 2004 General Rate Application (GRA).

Net earnings of $136 million in 2006 were $14 million lower compared to 2005. The decrease was primarily due to a lower investment base and a lower approved rate of return in 2006. Net earnings in 2005 and 2006 reflect an ROE of 9.50 and 8.93 per cent, respectively, as prescribed by the EUB, on deemed common equity of 35 per cent.

Net earnings of $150 million in 2005 were unchanged from 2004 due to the negative impacts of a lower investment base and a lower approved rate of return in 2005 being offset by the positive impact of higher allowed operating costs in 2005 compared to 2004 as a result of cost disallowances in the EUB's decision on Phase 1 of the 2004 GRA. Net earnings in 2004 reflect an ROE of 9.60 as prescribed by the EUB, on deemed common equity of 35 per cent.

GRAPHIC

GTN

GTN is regulated by the FERC, which has authority to regulate rates for natural gas transportation in interstate commerce. Both of GTN's systems, the Gas Transmission Northwest System and North Baja, operate under fixed rate rates, under which maximum and minimum rates for various service types have been ordered by the FERC. GTN is permitted to discount or negotiate these models on a non-discriminatory basis. In 2006, the Gas Transmission Northwest System operated under a rate case that was filed in 1994 and was settled and approved by the FERC in 1996. In June 2006, the Gas Transmission Northwest System filed a new rate case with the FERC. North Baja'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 contracted levels, volumes delivered and prices charged under the various service types that are provided, as well as by variations in the costs of providing services.

MANAGEMENT'S DISCUSSION AND ANALYSIS 21

Net earnings for the year ended December 31, 2006 were $64 million, a $7-million decrease from the same period in 2005. This decrease was primarily due to lower transportation revenues, higher operating costs, the impact of a weaker U.S. dollar and a provision for non-payment of contract transportation revenue from a subsidiary of Calpine Corporation that filed for bankruptcy protection. These negative factors were partially offset by an $18-million bankruptcy settlement ($29 million pre-tax) in first quarter 2006 with Mirant, a former shipper on the Gas Transmission Northwest System. Net earnings for November and December 2004 were $14 million.

Other Pipelines

TCPL's direct and indirect investments in various natural gas pipelines are included in Other Pipelines. It also includes TCPL's project development activities related to its pursuit of new pipelines and gas and oil transmission related opportunities throughout North America.

TCPL's net earnings from Other Pipelines in 2006 were $94 million compared to $148 million and $119 million in 2005 and 2004, respectively. Excluding the gains on sale of Northern Border Partners, L.P. in 2006 and PipeLines LP units in 2005, net earnings for 2006 were $18 million lower compared to 2005. The decrease was primarily due to higher project development and support costs associated with growing the Pipelines business, reduced ownership in PipeLines LP, a weaker U.S. dollar and bankruptcy settlements received by Iroquois in 2005, partially offset by increased net earnings from Portland due to a bankruptcy settlement received in 2006.

Excluding the gains on sale of PipeLines LP units in 2005 and the Millennium Pipeline project (Millennium) in 2004, net earnings in 2005 were $13 million lower than 2004. The decrease was primarily due to lower net earnings from Great Lakes as a result of lower short-term revenues and higher operating and maintenance costs, and lower earnings from PipeLines LP as a result of the reduced ownership. Results were also negatively impacted by a weaker U.S. dollar in 2005.

PIPELINES – OPPORTUNITIES AND DEVELOPMENTS

ANR and Great Lakes Acquisition

On February 22, 2007, TCPL closed its acquisition of ANR and an additional 3.55 per cent interest in Great Lakes from El Paso Corporation for approximately US$3.4 billion, subject to certain post-closing adjustments, including approximately US$488 million of assumed long-term debt. This transaction will significantly expand the Company's continental natural gas pipeline and storage operations.

ANR operates one of the largest interstate natural gas pipeline systems in the U.S., providing transportation, storage, and various capacity-related services to a variety of customers in both the U.S. and Canada. The system consists of approximately 17,000 km of pipeline with a peak-day capacity of 6.8 Bcf/d. It transports natural gas from producing fields in Louisiana, Oklahoma, Texas and the Gulf of Mexico to markets in Wisconsin, Michigan, Illinois, Ohio and Indiana. The pipeline system also connects with numerous other pipelines providing customers with access to diverse sources of supply from western Canada and the Rocky Mountain region and access to a variety of end-user markets in the midwestern and northeastern U.S.

ANR also owns and operates numerous underground natural gas storage facilities in Michigan with a total capacity of approximately 230 Bcf. Its facilities offer customers a high level of service flexibility allowing them to meet peak-day delivery requirements and to capture the value resulting from changing supply and demand dynamics. As part of the acquisition, TCPL will also obtain certain natural gas supplies contained within production and storage reservoirs in Michigan.

Great Lakes

On February 22, 2007, PipeLines LP closed its acquisition of a 46.45 per cent interest in Great Lakes from El Paso Corporation for approximately US$962 million subject to post-closing adjustments including approximately US$212 million of assumed long-term debt. Great Lakes owns and operates a 3,402 km interstate natural gas pipeline

22 MANAGEMENT'S DISCUSSION AND ANALYSIS

system with a design capacity of 2.5 Bcf/d. TCPL is the general partner of and holds a 32.1 per cent interest in PipeLines LP.

Canadian Mainline

In May 2006, TCPL filed for approval of two Canadian Mainline services designed to meet the growing needs of natural gas-fired power generators in Ontario. These services are designed to ensure that shippers can access transportation on as little as 15 minutes notice so they can better match the timing of their natural gas transportation needs with the timing of their power generation requirements. The application was the subject of an oral public hearing in September 2006 and, in December 2006, the NEB approved implementation of the services with minor modifications.

In December 2006, TCPL applied to the NEB for approval of a new receipt point at Gros Cacouna on the Canadian Mainline. The Company is also seeking affirmation of the tolling methodology that will apply to service from that point. The new receipt point would accommodate receipts of regassified LNG at Gros Cacouna, bringing a new source of supply to the Canadian Mainline to serve markets in eastern Canada and the U.S. Northeast. The NEB has established a procedure to deal with the Gros Cacouna, Québec receipt point application which includes an oral hearing expected to begin in April 2007.

Alberta System

On February 21, 2006, the EUB issued its decision on the 2005 GRA Phase II. The EUB approved the 2005 rate design as applied for. With this decision, TCPL was able to finalize the 2005 and 2006 Alberta System tolls on March 14, 2006. The 2006 final tolls were effective April 1, 2006. TCPL had been charging interim tolls since January 1, 2006 with the EUB's approval.

TCPL filed for a Review and Variance on the Ventures LP's Transportation by Others (TBO) costs following the EUB decision on the 2004 GRA Phase I. At the time, the EUB denied certain costs associated with the Ventures LP's new TBO contract that was replacing the old TBO contract. In its decision on November 28, 2006, (Decision 2006-069), the EUB allowed for the recovery of approximately $1 million of costs due to the timing of the termination and commencement of the TBO contracts.

On November 30, 2006, the EUB finalized the 2007 generic ROE formula results. For 2007, the Alberta System's ROE will be 8.51 per cent; down from 8.93 per cent in 2006.

On December 20, 2006, the EUB approved TCPL's application to charge interim tolls for transportation service, effective January 1, 2007. Final tolls for 2007 will be determined in first quarter 2007 upon updating of the flow-through cost components of the revenue requirement to reflect actual costs and revenues from the prior year.

GTN

In June 2006, TCPL filed a rate case with the FERC for its Gas Transmission Northwest System. The rate case filing was primarily driven by decreased revenues due to contract non-renewals and shipper defaults. The comprehensive filing requested a number of tariff changes including an increase in rates for transportation services that became effective January 1, 2007, subject to refund. The proposed rates include an ROE of 14.5 per cent, a common equity ratio of 62.99 per cent and a depreciation rate for the transmission plant of 2.76 per cent. The rates in effect prior to the January 2007 rate increase were based on the last rate case filed in 1994.

In January 2007, TCPL received a procedural order from the FERC establishing a timeline for the system's rate case proceeding. The hearing into this rate case is scheduled to commence on October 31, 2007.

BC System and Foothills

TCPL filed applications with the NEB in early December 2005 for approval of 2006 tolls for Foothills and the BC System, reflecting an agreement with the Canadian Association of Petroleum Producers (CAPP) and other stakeholders to increase the deemed equity component of the capital structure of each system to 36 per cent from 30 per cent. On December 21, 2005, the NEB approved Foothills' application as filed. On February 22, 2006, the NEB finalized the BC System's 2006 tolls as filed.

MANAGEMENT'S DISCUSSION AND ANALYSIS 23

In March 2006, TCPL initiated discussions with shippers on the BC System to integrate the BC System with Foothills. The discussions culminated in a settlement agreement (Integration Settlement) between Foothills and CAPP. The Integration Settlement amended an existing settlement for Foothills and includes a sharing mechanism for anticipated cost savings through increased administrative efficiencies arising out of the integration of the two systems. TCPL filed Foothills and BC System's integration application and related approvals with the NEB on December 21, 2006. In February 2007, the NEB approved the application as filed.

Tamazunchale

In December 2006, TCPL commenced commercial operations of the Tamazunchale pipeline. The 36 inch, 130 km pipeline in central Mexico extends from the facilities of Pemex Gas near Naranjos, Veracruz and transports natural gas under a 26-year contract with the Comisión Federal de Electricdad to an electricity generation station near Tamazunchale, San Luis Potosi.

The pipeline is designed to transport initial volumes of 170 million cubic feet per day (mmcf/d). Under the contract, the capacity of the Tamazunchale pipeline is expected to be expanded, beginning in 2009, to approximately 430 mmcf/d to meet the needs of two additional proposed power plants near Tamazunchale.

North Baja

On February 7, 2006, North Baja Pipelines LLC (North Baja) filed an application with the FERC to expand and modify its existing system to facilitate the importation of up to 2.7 Bcf/d of regassified LNG from Mexico into the California and Arizona markets. Specifically, North Baja proposes to modify its existing system to accommodate bi-directional natural gas flow, to construct a new meter station and a 36 inch pipeline to interconnect with Southern California Gas Company, to construct approximately 74 km of lateral facilities to serve electric generation facilities, and to loop its entire approximately 129 km existing system with a combination of 42 inch and 48 inch diameter pipeline. In addition to its FERC certificate of public convenience and necessity, which includes a determination on environmental issues, the project will need various permits and leases from the U.S. Bureau of Land Management, the California State Lands Commission and other agencies. On October 6, 2006, the FERC issued a preliminary determination approving all aspects of North Baja's proposal other than those related to environmental issues, which will be the subject of a future order.

Keystone Pipeline

In November 2005, TCPL, ConocoPhillips Company and ConocoPhillips Pipe Line Company (CPPL) signed a Memorandum of Understanding which commits ConocoPhillips Company to ship crude oil on the proposed Keystone Pipeline, and gives CPPL the right to acquire up to a 50 per cent ownership interest in the pipeline. On January 31, 2006, TCPL announced it has secured firm, long-term contracts totalling 340,000 barrels per day with durations averaging 18 years. The commitments were obtained through the successful completion of a binding Open Season held during fourth quarter 2005. With these commitments from shippers, TCPL proceeded with regulatory filings for approval of the project.

At an estimated cost of approximately US$2.1 billion, the Keystone Pipeline is intended to transport approximately 435,000 barrels per day of crude oil from Hardisty, Alberta, to Patoka, Illinois through a 2,960 km pipeline system. The pipeline can be expanded to 590,000 barrels per day with additional pump stations. In addition to approximately 1,730 km of new pipeline construction in the U.S., the Canadian portion of the proposed project includes the construction of approximately 370 km of new pipeline and the conversion of approximately 860 km of TCPL's existing pipeline facilities from natural gas to crude oil transmission. At December 31, 2006, the Company had capitalized $39 million related to Keystone.

In 2006, TCPL and TCPL's wholly owned subsidiary, TransCanada Keystone Pipeline GP Ltd. (Keystone), filed two regulatory applications with the NEB for the Canadian leg of the Keystone Pipeline. In June 2006, TCPL filed the first application with the NEB seeking approval to transfer a portion of its Canadian Mainline natural gas transmission facilities to Keystone for use as part of the Keystone Pipeline. As part of the transfer application, TCPL sought approval to reduce the Canadian Mainline's rate base by the NBV of the transferred facilities and to add the NBV of these facilities to the Keystone Pipeline rate base. Public hearings on the transfer application were completed in mid-November 2006. Approval was received from the NEB in February 2007.

24 MANAGEMENT'S DISCUSSION AND ANALYSIS

In the second application, TCPL sought approval to construct and operate new facilities in Canada including approximately 370 km of new oil pipeline, terminal facilities at Hardisty, Alberta and required pump stations. TCPL is also seeking approval of the tolls and tariff for the pipeline. A decision on this application is anticipated from the NEB in fourth quarter 2007.

In April 2006, TCPL filed an application with the U.S. Department of State for a Presidential Permit authorizing the construction, operation and maintenance of the U.S. portion of the Keystone Pipeline. In September 2006, the Department of State issued a formal notice of the application as well as a Notice of Intent to prepare an Environmental Impact Statement for the project.

In June 2006, TCPL filed a petition with the Illinois Commerce Commission for a certificate authorizing the pipeline and granting authority to exercise eminent domain. The matter is expected to go to hearing in March 2007.

Shippers have also expressed interest in a proposed extension of the Keystone Pipeline to Cushing, Oklahoma. Through an Open Season, which will close at the end of first quarter 2007, binding commitments are being solicited to support the Cushing Extension, which would expand the Keystone Pipeline from a capacity of approximately 435,000 barrels per day to 590,000 barrels per day, and see the construction of a 468 km, 36 inch extension of the U.S. portion of the pipeline to Cushing. The expansion and extension would enable Keystone to provide access for increasing western Canadian crude supply to two key markets and transportation hubs at Patoka and Cushing. The expected capital cost is US$700 million and the targeted in-service date is fourth quarter 2010.

The Heartland extension is a proposed 190 km pipeline from Hardisty which would connect Keystone to the Fort Saskatchewan area. This extension would increase the Keystone Pipeline's market supply reach and provide incremental transportation service between Alberta's two major crude oil centres. The expected capital cost is approximately US$300 million. Discussions are under way with shippers to gauge the level of interest with an anticipation of moving forward with commercial arrangements later in 2007. The targeted in-service date of the Heartland extension is 2010/2011.

TCPL is in the business of connecting energy supplies to markets and it views the Keystone 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.

Mackenzie Gas Pipeline Project

The MGP is a 1,200 km natural gas pipeline proposed to be constructed from near Inuvik, Northwest Territories to the northern border of Alberta, where it would then connect to the Alberta System. In June 2006, TCPL submitted an application to the EUB for approval of the Dickins-Vardie facilities, a $212-million capital project required to provide the Alberta System interconnection facilities for Mackenzie gas volumes.

Throughout 2006, the MGP proponents participated in public hearings convened by the NEB and by a Joint Review Panel (JRP) constituted to assess socio-economic and environmental aspects of the project. These latter hearings are expected to conclude in second quarter 2007, with the JRP's report ultimately being submitted into the NEB review process. Concurrently, the project proponents have been reassessing the capital cost estimate and construction schedule for the MGP, in light of overall industry cost escalations and labour shortages. A revised capital estimate for the project is expected to be filed with the NEB in first quarter 2007.

Apart from the Alberta System interconnection facilities, TCPL's involvement with the MGP is derived from a 2003 agreement with the APG and the MGP by which TCPL agreed to finance the APG's one-third share of the pipeline's pre-development costs associated with the project. These costs are currently forecasted to be approximately $145 million by the end of 2007. Cumulative advances made by TCPL in this respect totalled $118 million at December 31, 2006 and are included in Other Assets. These amounts constitute a loan to the APG, which becomes repayable only after the date upon which the pipeline commences commercial operations. The total amount of the loan is expected to ultimately form part of the rate base of the pipeline, and the loan will subsequently be repaid from the

MANAGEMENT'S DISCUSSION AND ANALYSIS 25


APG's share of available future pipeline revenues or from alternate financing. If the project does not proceed, TCPL has no recourse against the APG for recovery of advances made. Accordingly, the recovery of the advances is dependent upon a successful outcome of the project.

Under the terms of certain MGP agreements, TCPL holds an option to acquire up to five per cent equity ownership in the pipeline at the time of the decision to construct. In addition, TCPL gains certain rights of first refusal to acquire 50 per cent of any divestitures by existing partners and an entitlement to obtain a one-third interest in all expansion opportunities once the APG reaches a one-third ownership share, with the other pipeline owners and the APG sharing the balance.

Alaska Highway Pipeline Project

In 2006, TCPL continued its discussions with Alaska North Slope producers and the State of Alaska regarding the Alaskan portion of the proposed Alaska Highway Pipeline Project. In early 2006, Alaska's State administration reached a preliminary agreement with ConocoPhillips Alaska Inc., BP Exploration (Alaska) Inc. and ExxonMobil Alaska Production Inc. for the pipeline project. However, the State Legislature did not ratify that agreement. Alaska's new Governor, elected in November 2006, has indicated the new administration intends to introduce a different process for the pipeline project in 2007.

Foothills Pipe Lines Ltd. (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 (NPA), following a lengthy competitive hearing before the NEB in the late 1970s, 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 facilities in Alberta, B.C. and Saskatchewan, 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.

Western Supply and Markets

The primary driver for infrastructure projects for the Alberta System is the development of natural gas supply and market demand in the various regions served by the Alberta System. In 2006, natural gas prices were lower than in 2005 which resulted in some slowdown in natural gas drilling activity levels. Nevertheless, activity remains strong which has resulted in supply growth in some regions of western Canada and an increased requirement for new transmission infrastructure. The primary source of supply growth has been deeper conventional drilling in western Alberta, northeastern B.C. and coalbed methane development in central Alberta.

TCPL will continue to focus on the cost effective and timely connection of new gas production volumes so that customers can promptly access markets. As well, service flexibility will continue to be a focus to ensure TCPL remains competitive.

TCPL received approval from the EUB in April 2006 to construct new natural gas transmission facilities to serve the firm intra-Alberta delivery contract requirements of oil sand developers in the Fort McKay area. These facilities include 127 km of pipeline and three metering facilities at an estimated capital cost of $125 million. In addition to the proposed Fort McKay facilities, TCPL constructed additional metering facilities to serve approximately 200 mmcf/d of firm intra-Alberta delivery contracts.

Eastern Supply and Markets

Historically, TCPL's eastern pipeline system has been supplied by long-haul flows from western Canada and by volumes received from storage fields and interconnecting pipelines in southwestern Ontario. In the future, the eastern pipeline system may also be supplied by LNG deliveries from proposed regassification facilities in Québec and the northeastern U.S.

Power generation continues to be the primary driver for incremental gas demand in eastern Canada and the northeastern U.S. Power projects that require significant volumes of natural gas continue to be developed, supporting utilization of the eastern pipeline system. Aligned with these power project developments, TCPL received NEB approval

26 MANAGEMENT'S DISCUSSION AND ANALYSIS


in 2006 for two new services targeted at attracting incremental demand for natural gas transportation on the Canadian Mainline system.

In addition, TCPL completed construction of three NEB-approved facilities on its Canadian Mainline system in 2006. This included the Stittsville and Deux Rivières loops of approximately 38 km of 42 inch pipe with a capital cost of approximately $113 million, and the Les Cèdres loop of approximately 21 km of 36 inch pipe with a capital cost of $56 million.

PIPELINES – BUSINESS RISKS

Competition

TCPL faces competition at both the supply end and the market end of its systems. The competition is a result of other pipelines accessing the increasingly mature WCSB as well as markets served by TCPL's pipelines. In addition, the continued expiration of long-term firm transportation (FT) contracts has resulted in significant reductions in long-term firm contracted capacity on the Canadian Mainline, the Alberta System, the BC System and the Gas Transmission Northwest System, and shifts to short-term firm contracts.

TCPL's primary source of natural gas supply is the WCSB. As of December 2005, the WCSB had remaining discovered natural gas reserves of approximately 57 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, the WCSB's natural gas supply is expected to remain essentially flat. With the expansion of capacity on TCPL'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, TCPL anticipates there will be excess pipeline capacity out of the WCSB for the foreseeable future.

TCPL's Alberta System is the major natural gas gathering and transportation system for the WCSB, connecting most of the natural gas processing plants in Alberta to domestic and export markets. The Alberta System has faced, and will continue to face, increasing competition from other pipelines. An emerging competitive issue for the Alberta System is the existence and access to natural gas liquids (NGLs) contained in the gas that is transported by the pipeline. The current extraction convention in Alberta allocates a heat content value to the receipt point shippers at the overall Alberta System average gas composition. This averaging is becoming a significant issue for northern gas producers whose gas is generally rich in NGL content as they seek to extract the full value of the NGLs. Alberta's petrochemical industry is also very interested in the issue as it relies on NGLs as their feedstock. The EUB is aware of the current extraction convention inequities and has indicated that they will commission a process to address these concerns.

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

Over the last few years, the Canadian Mainline has experienced reductions in long-haul FT contracts. This has been partially offset by increases in short-haul contracts. While decreases in throughput do not directly impact the Canadian Mainline earnings, such decreases will impact the competitiveness of its tolls. Over the course of 2005 and into early 2006, strong prices in eastern Canada and the northeastern U.S. resulted in higher than anticipated flows on the Canadian Mainline. Moderating prices in these markets in the latter part of 2006 have reduced flows toward expected

MANAGEMENT'S DISCUSSION AND ANALYSIS 27


levels. Looking forward, in the short to medium term, there is limited opportunity to further reduce per unit tolls by increasing long-haul volumes on the Canadian Mainline.

The Gas Transmission Northwest System must compete with other pipelines to access natural gas supplies as well as to access 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 in relation to natural gas supplies from the other supply regions serving these markets. The Gas Transmission Northwest System experienced significant contract non-renewals in 2005 and 2006 as 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 southwestern U.S. supply basins. In the Pacific Northwest market, natural gas transported on the Gas Transmission Northwest System competes against the Rocky Mountain natural gas supply as well as additional western Canadian supply transported by other pipelines.

In October 2006, the Gas Transmission Northwest System's largest customer, Pacific Gas & Electric Company (PG&E), extended its contract to October 31, 2008. In 2006, PG&E accounted for approximately 22 per cent of the Gas Transmission Northwest System's revenue. By October 31, 2007, PG&E will inform TCPL whether it elects to either extend the contract beyond November 2008, utilize the contract's right of first refusal process or terminate the contract.

Transportation service on North Baja 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. North Baja delivers gas to the 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 North Baja'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.

Counterparty Risk

The risk of counterparty default is always present. In December 2005, Calpine Corporation and certain of its subsidiaries (Calpine) filed for bankruptcy protection in both Canada and the U.S. Calpine repudiated its transportation contracts on certain of TCPL's Canadian pipelines effective January 1, 2007 as allowed under a Companies' Creditors Arrangement Act Order. Given that TCPL considers itself prudent in having obtained the maximum financial assurances allowable under the respective Canadian tariffs, TCPL will make an application to the regulator for recovery under the current regulatory model for any lost revenue, net of assurances and any revenues from the defaulted capacity. Should Calpine be successful in rejecting its contracts on certain of TCPL's U.S. pipelines, the unmitigated annual after-tax exposure of the contract obligations is estimated at $10 million for the Gas Transmission Northwest System. Mitigating factors exist which may reduce this exposure including recontracting the capacity where possible and recovery from bankruptcy proceedings. The potential impact of such mitigating factors and the resulting net exposure are unknown at this time.

Regulatory Financial Risk

Regulatory decisions continue to have a significant impact on the financial returns for existing and future investments in TCPL's Canadian wholly owned pipelines. TCPL remains concerned that the approved financial returns fail to be competitive with returns from assets of similar risk and will discourage additional investment in existing Canadian natural gas transmission systems. In recent years, TCPL applied for an ROE of 11 per cent on 40 per cent deemed common equity for both the Canadian Mainline and the Alberta System to the NEB and the EUB, respectively. The outcome of these proceedings resulted in the Canadian Mainline's current 36 per cent deemed equity thickness and the Alberta System's 35 per cent deemed equity thickness. Additionally, the NEB reaffirmed its ROE formula, while the EUB set a generic ROE which largely aligns with the NEB's formula. In 2006, the NEB's ROE formula declined to 8.88 per cent from the 2005 ROE of 9.46 per cent and the EUB's generic ROE declined to 8.93 per cent from 9.50 per cent in 2005. In 2007, the Canadian Mainline and the Alberta System's ROEs continued to decline, dropping to 8.46 percent and 8.51 per cent, respectively.

28 MANAGEMENT'S DISCUSSION AND ANALYSIS

Throughput Risk

As transportation contracts expire on TCPL's U.S. pipeline investments, these pipelines will be more exposed to throughput risk and their revenues are more likely to experience increased variability. Throughput risk is created by supply and market competition, gas basin pricing, economic activity, weather variability, pipeline competition and pricing of alternative fuels.

PIPELINES – OTHER

Safety

TCPL worked closely with regulators, customers and communities during 2006 to ensure the continued safety of employees and the public. In 2006, TCPL experienced two small diameter pipeline line-breaks located in remote areas of northern Alberta. The breaks released sweet natural gas and resulted in minimal impact with no injuries or property damage. Under the approved regulatory models in Canada, expenditures for pipeline integrity on the NEB and the EUB regulated pipelines are treated on a flow-through basis and, as a result, have no impact on TCPL's earnings. The Company expects to spend approximately $100 million in 2007 for pipeline integrity on its wholly owned pipelines, which approximates the amount spent in 2006. TCPL 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. TCPL utilizes a comprehensive management system of policies, programs and procedures to ensure the occupational safety of employees and contractors.

Environment

In 2006, TCPL continued to address environmental issues associated with its historical operations through proactive environmental monitoring, sampling and site remediation programs. Environmental site assessments were completed on the assets of the BC System, the Alberta System and the Canadian Mainline. The building containment integrity improvement program also continued at compressor station sites across the Canadian Mainline. Additionally, the demolition and clean up of four mainline compressor plants was carried out in 2006. TCPL will continue to actively invest in improving its environmental protection practices in 2007 and the future.

For information on management of risks with respect to the Pipelines business, refer to the "Risks and Risk Management" section of this MD&A.

PIPELINES – OUTLOOK

As demand for natural gas continues to grow across North America, TCPL's Pipelines business will continue to play a critical role in the reliable transportation of natural gas. For 2007, the business will continue to focus on the reliable delivery of natural gas to growing markets, connecting new supply, progressing development of new infrastructure to connect natural gas from the north, LNG in the east, and development of the Keystone Pipeline.

It is expected that producers will continue to explore and develop new fields, particularly in northeastern B.C. and the west central foothills regions of Alberta. There will also be significant activity aimed at unconventional resources such as coalbed methane although activity is expected to decline from last year's level. New facilities will be required to move this incremental supply from the location of the resource. New customer requests to serve markets in eastern Canada and the U.S. will require expansion of certain facilities on the Canadian Mainline for 2007 and 2008. This will include the addition of 18 MW of compression and a 7 km looping project. The estimated capital cost for these projects is $63 million.

It is expected that incremental supply from LNG will serve growing North American markets in the mid to long term. As a result, TCPL will take prudent steps to further understand the potential commercial and operational implications of connecting LNG facilities to those systems affected.

MANAGEMENT'S DISCUSSION AND ANALYSIS 29


TCPL will continue to focus on operational excellence and collaborative efforts with all stakeholders on negotiated settlements and service options that will increase the value of TCPL's business to customers and shareholders.

Earnings

With the closing of the acquisition of ANR and Great Lakes, and the Company's increased ownership in PipeLines LP, TCPL expects higher net earnings from Pipelines in 2007 compared to 2006. TCPL'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 a continued net decline in the average investment base due to depreciation. Accordingly, without an increase in ROE, deemed common equity or incentive opportunities, future earnings from the Canadian Wholly Owned Pipelines 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. In addition, the Tamazunchale pipeline will provide an increase in 2007 earnings as a result of its first full year of operations.

In November 2006, the NEB established the 2007 ROE for the Canadian Mainline at 8.46 per cent compared to 8.88 per cent in 2006. In addition, the 2007 average investment base is expected to continue to decline. These two factors are expected to lower earnings on the Canadian Mainline in 2007, relative to 2006, barring any offsetting factors.

Alberta System's earnings will be negatively influenced in 2007 by the decrease in the EUB's generic ROE to 8.51 per cent in 2007 from 8.93 per cent in 2006, and the anticipated decrease in the average investment base. The three-year revenue requirement settlement reached in 2005 does provide the opportunity for limited incentive earnings as the settlement contains some at-risk components. There is a possibility that the at-risk OM&A cost components of the settlement will have a negative impact on the Alberta System's earnings in 2007.

In 2007, reduced firm contract volumes on the Gas Transmission Northwest System, partially due to the bankruptcy of Calpine, are expected to have a negative impact on the Gas Transmission Northwest System's earnings compared to 2006. It is uncertain what impact the rate case proceeding may have on the system's financial results. Net earnings, excluding gains, from Other Pipelines are expected to be relatively consistent with 2006.

Capital Expenditures

Total capital spending for the Wholly Owned Pipelines during 2006 was $434 million. Overall capital spending for the Wholly Owned Pipelines in 2007 is expected to be approximately $400 million, excluding any capital expenditures of ANR.

30 MANAGEMENT'S DISCUSSION AND ANALYSIS

NATURAL GAS THROUGHPUT VOLUMES
(Bcf)

    2006   2005   2004
Canadian Mainline(1)   2,955   2,997   2,621
Alberta System(2)   4,051   3,999   3,909
Gas Transmission Northwest System(3)   790   777   181
Foothills   1,051   1,051   1,139
BC System   351   321   360
North Baja(3)   95   84   13
Great Lakes   816   850   801
Northern Border   799   808   845
Iroquois   384   394   356
TQM   158   166   159
Ventures LP   179   138   136
Portland   52   62   50
Tuscarora   28   25   25
Gas Pacifico   52   34   28
TransGas   22   19   18
Tamazunchale(4)   –   –   –
(1)
Canadian Mainline deliveries originating at the Alberta border and in Saskatchewan in 2006 were 2,224 Bcf (2005 – 2,215 Bcf; 2004 – 2,017 Bcf).

(2)
Field receipt volumes for the Alberta System in 2006 were 4,160 Bcf (2005 – 4,034 Bcf; 2004 – 3,952 Bcf).

(3)
TCPL acquired GTN on November 1, 2004. The delivery volumes for 2004 represent November and December 2004 throughput for GTN.

(4)
The Tamazunchale pipeline went into service December 1, 2006.

MANAGEMENT'S DISCUSSION AND ANALYSIS 31

GRAPHIC

BEAR CREEK   An 80 MW natural gas-fired cogeneration plant located near Grande Prairie, Alberta

MACKAY RIVER   A 165 MW natural gas-fired cogeneration plant located near Fort McMurray, Alberta.

REDWATER   A 40 MW natural gas-fired cogeneration plant located near Redwater, Alberta.

SUNDANCE A&B   The Sundance power facility in Alberta is the largest coal-fired electrical generating facility in Western Canada. TCPL owns the 560 MW Sundance A PPA, which expires in 2017. TCPL effectively owns 50 per cent of the 706 MW Sundance B PPA, which expires in 2020.

SHEERNESS   The Sheerness plant consists of two 390 MW coal-fired thermal power generating units. TCPL owns the 756 MW Sheerness PPA, which expires in 2020.

CARSELAND   An 80 MW natural gas-fired cogeneration plant located near Carseland, Alberta.

32 MANAGEMENT'S DISCUSSION AND ANALYSIS


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

BRUCE POWER   TCPL owns 31.6 per cent of Bruce B, consisting of operating Units 5 to 8 with approximately 3,200 MW of generating capacity. In addition, TCPL owns 48.7 per cent of Bruce A, consisting of operating Units 3 and 4 with approximately 1,500 MW of generating capacity and currently idle Units 1 and 2 with approximately 1,500 MW of generating capacity, which are currently being refurbished and are expected to restart in late 2009 or early 2010.

HALTON HILLS   The 683 MW natural gas-fired power plant near the town of Halton Hills, Ontario is under development and is expected to be placed in service in second quarter 2010.

PORTLANDS ENERGY   The 550 MW high efficiency, combined cycle natural gas generation power plant located in downtown Toronto is 50 percent owned by TCPL and is under construction. The plant is expected to be operational in simple-cycle mode, delivering 340 MW of electricity to the City of Toronto beginning June 2008. It is anticipated to be fully commissioned in its full combined-cycle mode, delivering 550 MW of power in second quarter 2009.

BÉCANCOUR   Construction of the 550 MW Bécancour natural gas-fired cogeneration power plant located near Trois-Rivières, Québec was completed and the plant placed into service in September 2006. The entire power output will be supplied to Hydro-Québec under a 20-year power purchase contract. Steam is also sold to industrial customers for use in commercial processes.

CARTIER WIND   Construction of the 740 MW Cartier Wind project, 62 per cent owned by TCPL, continued in 2006. The first of six wind projects, Baie-des-Sables, with a generation capacity of 110 MW, was placed into service in November 2006. Planning and construction on the remaining five projects will continue, subject to future appropriations and approvals.

GRANDVIEW   A 90 MW natural gas-fired cogeneration power plant located in Saint John, New Brunswick was commissioned and placed into service in January 2005. Under a 20-year tolling arrangement, 100 per cent of the plant's heat and electricity output is sold to Irving Oil.

TC HYDRO   TCPL's hydroelectric facilities on the Connecticut and Deerfield Rivers consist of 13 stations and associated dams and reservoirs with a total generating capacity of 567 MW and are located in New Hampshire, Vermont and Massachusetts.

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

EDSON   Edson is an underground natural gas storage facility connected to the Alberta System located near Edson, Alberta. The central processing system is capable of maximum injection and withdrawal rates of 725 mmcf/d of natural gas. Edson has a working natural gas storage capacity of approximately 50 Bcf. Construction of the Edson facility was substantially completed in third quarter 2006 and the facility was placed into service on December 31, 2006.

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 50 Bcf with a maximum deliverability capability of 400 mmcf/d. TCPL holds a 60 per cent ownership in CrossAlta.

CACOUNA   Cacouna, a joint venture with Petro-Canada, is a proposed LNG project in Québec at Gros Cacouna harbour on the St. Lawrence River, capable of receiving, storing and regassifying imported LNG with an average send-out capacity of approximately 500 mmcf/d of natural gas.

BROADWATER   Broadwater, a joint venture with Shell US Gas & Power LLC, is a proposed LNG project located offshore of New York State in Long Island Sound, capable of receiving, storing and regassifying imported LNG with an average send-out capacity of approximately 1 Bcf/d of natural gas.

MANAGEMENT'S DISCUSSION AND ANALYSIS 33

HIGHLIGHTS

Net Earnings

Expanding Asset Base

    Power

    Natural Gas Storage

Plant Availability

34 MANAGEMENT'S DISCUSSION AND ANALYSIS

ENERGY RESULTS-AT-A-GLANCE
Year ended December 31 (millions of dollars)

    2006   2005   2004  
 
Bruce Power   235   195   130  
Western Power Operations   297   123   138  
Eastern Power Operations   187   137   108  
Natural Gas Storage   93   32   27  
Power LP Investment   –   29   29  
General, administrative, support costs and other   (144 ) (129 ) (127 )
 
Operating income   668   387   305  
Financial charges   (23 ) (11 ) (13 )
Interest income and other   5   5   14  
Income taxes   (198 ) (123 ) (95 )
 
    452   258   211  
Gain on sale of Paiton Energy   –   115   –  
Gains related to Power LP   –   193   187  
 
Net earnings   452   566   398  
 


GRAPHIC

 

Energy's net earnings in 2006 were $452 million compared to $566 million in 2005. In 2005, TCPL sold its approximate 11 per cent interest in Paiton Energy to subsidiaries of the Tokyo Electric Power Company for gross proceeds of US$103 million ($122 million) resulting in an after-tax gain of $115 million. In August 2005, TCPL sold its ownership interest in Power LP to EPCOR Utilities Inc. (EPCOR) for net proceeds of $523 million resulting in an after-tax gain of $193 million.
Excluding the Paiton Energy and Power LP-related gains in 2005, Energy's net earnings in 2006 of $452 million increased $194 million compared to $258 million in 2005. The increase was primarily due to higher contributions from each of its
existing businesses and a $23-million favourable impact on future income taxes arising from reductions in Canadian federal and provincial corporate income tax rates enacted in 2006. Partially offsetting these increases was the loss of operating income associated with the sale of the Power LP interest in 2005 and reduced earnings in 2006 due to the effect of a weaker U.S. dollar on earnings from Energy's U.S. operations.

Included in 2004 net earnings was an after-tax gain of $187 million comprising a $15-million after-tax gain on the sale of TCPL's Curtis Palmer and ManChief power facilities to Power LP as well as $172 million of after-tax dilution gains.

Excluding the gain on the sale of Paiton Energy in 2005 and Power LP-related gains in 2005 and 2004, Energy's net earnings for the year ended December 31, 2005 of $258 million increased $47 million compared to $211 million in 2004. The increase was primarily due to higher operating income from Bruce Power and Eastern Power Operations, partially offset by a reduced contribution from Western Power Operations and lower interest income and other.

MANAGEMENT'S DISCUSSION AND ANALYSIS 35


POWER PLANTS – NOMINAL GENERATING CAPACITY AND FUEL TYPE

    MW   Fuel Type
Bruce Power(1)   2,474   Nuclear

Western Power Operations
 
 
 
 
  Sheerness(2)   756   Coal
  Sundance A(3)   560   Coal
  Sundance B(3)   353   Coal
  MacKay River   165   Natural gas
  Carseland   80   Natural gas
  Bear Creek   80   Natural gas
  Redwater   40   Natural gas
  Cancarb   27   Natural gas
    2,061    

Eastern Power Operations
 
 
 
 
  Halton Hills(4)   683   Natural gas
  TC Hydro(5)   567   Hydro
  OSP   560   Natural gas
  Bécancour(6)   550   Natural gas
  Cartier Wind(7)   458   Wind
  Portlands Energy(8)   275   Natural gas
  Grandview(9)   90   Natural gas
    3,183    
Total Nominal Generating Capacity   7,718    
(1)
Represents TCPL's 48.7 per cent proportionate interest in Bruce A and 31.6 per cent proportionate interest in Bruce B. Bruce A consists of four 750 MW reactors. Bruce A Unit 3 was returned to service in first quarter 2004. Bruce A Units 1 and 2 are currently being refurbished and are expected to restart in late 2009 or early 2010. Bruce B consists of four reactors which are currently in operation, with a combined capacity of approximately 3,200 MW.

(2)
TCPL directly acquires 756 MW from Sheerness through a long-term PPA.

(3)
TCPL 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.

(4)
Currently in development.

(5)
Acquired in second quarter 2005.

(6)
Placed in service in third quarter 2006.

(7)
First of six wind farms placed in service in fourth quarter 2006. Represents TCPL's 62 per cent share of the total 740 MW project.

(8)
Currently under construction. Represents TCPL's 50 per cent share of this 550 MW facility.

(9)
Placed in service in first quarter 2005.

ENERGY – FINANCIAL ANALYSIS

Bruce Power

On October 31, 2005, Bruce Power and the OPA completed a long-term agreement whereby Bruce A will restart and refurbish the currently idle Units 1 and 2, extend the operating life of Unit 3 by replacing its steam generators and fuel channels when required and replace the steam generators on Unit 4. As a result of an agreement between Bruce Power and the OPA, and Cameco Corporation's (Cameco) decision not to participate in the restart and refurbishment program, the Bruce A partnership was formed by TCPL and BPC Generation Infrastructure Trust (BPC), with each owning a

36 MANAGEMENT'S DISCUSSION AND ANALYSIS

48.7 per cent (2005 – 47.9 per cent) interest in Bruce A at December 31, 2006. TCPL and BPC each incurred a net cash outlay of approximately $100 million in 2005 to acquire Cameco's interest. The remaining 2.6 per cent is owned by the Power Worker's Union Trust No. 1 and The Society of Energy Professionals Trust. The Bruce A partnership subleases the Bruce A facilities, which comprises Units 1 to 4, from Bruce B. TCPL continues to own 31.6 per cent of Bruce B, which consists of Units 5 to 8.

Upon reorganization, both Bruce A and Bruce B became jointly controlled entities and TCPL proportionately consolidated these investments on a prospective basis from October 31, 2005. The following Bruce Power financial results reflect the operations of the full six-unit operation for all periods.

Bruce Power Results-at-a-Glance(1)
 Year ended December 31 (millions of dollars)

  2006   2005   2004  
 
Bruce Power (100 per cent basis)            
  Revenues            
    Power 1,861   1,907   1,563  
    Other(2) 71   35   20  
 
  1,932   1,942   1,583  
 
  Operating expenses            
    Operations and maintenance (912 ) (871 ) (793 )
    Fuel (96 ) (77 ) (68 )
    Supplemental rent (170 ) (164 ) (156 )
    Depreciation and amortization (134 ) (198 ) (161 )
 
  (1,312 ) (1,310 ) (1,178 )
 
  Revenues, net of operating expenses 620   632   405  
    Financial charges under equity accounting(3) –   (58 ) (67 )
 
  620   574   338  
 
TCPL's proportionate share 228   188   107  
Adjustments 7   7   23  
 
TCPL's operating income from Bruce Power(3) 235   195   130  
 

Bruce Power – Other Information
 
 
 
 
 
 
Plant availability 88%   80%   82%  
Sales volumes (GWh)(4)            
  Bruce Power – 100 per cent 36,470   32,900   33,600  
  TCPL's proportionate share 13,317   10,732   10,608  
Results per MWh(5)            
  Bruce A revenues $58          
  Bruce B revenues $48          
  Combined Bruce Power revenues $51   $58   $47  
  Combined Bruce Power fuel $3   $2   $2  
  Combined Bruce Power total operating expenses(6) $35   $40   $35  
Percentage of output sold to spot market 35%   49%   52%  
(1)
All information in this table includes adjustments to eliminate the effects of inter-partnership transactions between Bruce A and Bruce B.

(2)
Includes fuel cost recoveries for Bruce A of $30 million for 2006 ($4 million from November 1 to December 31, 2005).

MANAGEMENT'S DISCUSSION AND ANALYSIS 37

(3)
TCPL's consolidated equity income in 2005 includes $168 million which represents TCPL's 31.6 per cent share of Bruce Power earnings for the ten months ended October 31, 2005.

(4)
Gigawatt hours.

(5)
Megawatt hours.

(6)
Net of fuel cost recoveries.

TCPL's operating income from its combined investment in Bruce Power for 2006 was $235 million compared to $195 million for 2005. The increase of $40 million was primarily due to an increased ownership interest in the Bruce A facilities and higher sales volumes resulting from increased plant availability, partially offset by lower overall realized prices.

Combined Bruce Power prices achieved during 2006 (excluding other revenues) were $51 per MWh compared to $58 per MWh in 2005, reflecting lower prices on uncontracted volumes sold into the spot market. Bruce Power's combined operating expenses (net of fuel cost recoveries) decreased to $35 per MWh for 2006 from $40 per MWh in 2005 primarily due to increased output and higher fuel cost recoveries in 2006.

The Bruce units ran at a combined average availability of 88 per cent in 2006, compared to an 80 per cent average availability during 2005. The higher availability in 2006 was the result of 114 fewer days of planned maintenance outages as well as 65 fewer forced outage days in 2006 compared to 2005.

TCPL's operating income from its combined investment in Bruce Power for 2005 was $195 million compared to $130 million for the same period in 2004. This increase was primarily due to higher realized prices in 2005, partially offset by higher maintenance costs, higher depreciation and lower capitalization of labour and other in-house costs following the restart of Unit 3 in first quarter 2004.

Adjustments to TCPL's combined interest in Bruce Power's income before income taxes for 2005 were lower than in 2004 primarily due to a lower amortization of the purchase price allocated to the fair value of sales contracts in place at the time of acquisition.

Income from Bruce B is directly impacted by fluctuations in wholesale spot market prices for electricity. Income from both Bruce A and Bruce B units is impacted by overall plant availability, which in turn, is impacted by scheduled and unscheduled maintenance. To reduce its exposure to spot market prices, as at December 31, 2006, Bruce B entered into fixed price sales contracts to sell forward approximately 6,900 GWh for 2007 and 2,900 GWh for 2008. As a result of the contract with the OPA, all of the output from Bruce A was sold at a fixed price of $58.63 per MWh ($57.37 to March 31, 2006), before recovery of fuel costs from the OPA. Under the terms of the arrangement between Bruce A and the OPA, effective October 31, 2005, Bruce A receives a contract price for power generated, whereby the price is adjusted for inflation annually on April 1. Post refurbishment, prices are adjusted for any capital cost variances associated with the restart and refurbishment projects. Bruce A contract prices will not vary with changes in the wholesale price of power in the Ontario market. As part of this contract, sales from the Bruce B Units 5 to 8 are subject to a floor price of $45.99 per MWh ($45.00 to March 31, 2006), adjusted annually for inflation on April 1. Payments received pursuant to the Bruce B floor price mechanism may be subject to a recapture payment dependent on annual spot prices over the term of the contract. Bruce B net earnings to December 31, 2006 included no amounts received pursuant to this floor mechanism.

The overall plant availability percentage in 2007 is expected to be in the low 90s for the four Bruce B units and the mid 70s for the two operating Bruce A units. Two planned outages are scheduled for Bruce A Unit 3 with the first outage expected to last one month in second quarter 2007 and a second outage expected to last approximately two months beginning in late third quarter 2007. A one month outage of Bruce A Unit 4 is expected to commence in first quarter 2007. The only planned maintenance outage for 2007 for Bruce B is an approximately two and a half month outage for Unit 6 that began in January 2007 and is expected to be completed in early second quarter 2007.

38 MANAGEMENT'S DISCUSSION AND ANALYSIS


The Bruce partners have agreed that all excess cash from both Bruce A and Bruce B will be distributed on a monthly basis and that separate cash calls will be made for major capital projects, including the Bruce A restart and refurbishment project.

The project to restart and refurbish Bruce A Units 1 and 2 was initiated in 2005. Substantial work on the project began in 2006 after Bruce received formal acceptance of its environmental assessment from the Canadian Nuclear Safety Commission in July 2006. Bruce Power has separated Units 1 and 2 from the operating reactors in Units 3 and 4. At the end of December 2006, eight replacement steam generators had been delivered and preparations made for the installation in early 2007. Work on manufacturing the Unit 4 steam generators also occurred during the year.

Bruce Power's capital program for the restart and refurbishment project is expected to total approximately $4.25 billion and TCPL's approximately $2.125 billion share will be financed through capital contributions to 2011. A capital cost risk-and reward-sharing schedule with the OPA is in place for spending below or in excess of the $4.25 billion base case estimate. The first unit is expected to be online in late 2009, subject to approval by the Canadian Nuclear Safety Commission. Restarting Units 1 and 2, which have a capacity of approximately 1,500 MW, will boost the Bruce facilities' overall output to more than 6,200 MW. As at December 31, 2006, Bruce A had incurred $1.092 billion in costs with respect to the restart and refurbishment project.

Western Power Operations

As at December 31, 2006, Western Power Operations directly controlled approximately 2,100 MW of power supply in Alberta from its three long-term PPAs and five natural gas-fired cogeneration facilities. The Western Power Operations power supply portfolio comprises approximately 1,700 MW of low-cost, base-load coal-fired generation supply and approximately 400 MW of natural gas-fired cogeneration assets. This supply portfolio is among the lowest-cost, most competitive generation in the Alberta market area. The three long-term PPAs include the December 31, 2005 acquisition of the remaining rights and obligations of the 756 MW Sheerness PPA in addition to the Sundance A and Sundance B PPAs acquired in 2001 and 2002, respectively. The Sheerness PPA was acquired from the Alberta Balancing Pool for $585 million on December 31, 2005 and has a remaining term of approximately 14 years. The PPAs entitle TCPL to the output capacity of these coal facilities, ending in 2017 to 2020. The success of Western Power Operations is the direct result of its two integrated functions – marketing and plant operations.

The marketing function, based in Calgary, Alberta, purchases and resells electricity sourced from the PPAs, markets uncommitted generation volumes from the cogeneration facilities, and purchases and resells power and gas to maximize the value of the cogeneration facilities. The marketing function is integral to optimizing Energy's return from its portfolio of power supply and managing risks around uncontracted volumes. A portion of TCPL's supply is held for sale in the spot market for operational reasons and is also dependent upon the availability of acceptable contract terms in the forward market. This approach to portfolio management assists in minimizing costs in situations where TCPL would otherwise have to purchase power in the open market to fulfil its contractual obligations. In 2006, approximately 35 per cent of power sales volumes were sold into the spot market. To reduce exposure to spot market prices of uncontracted volumes, as at December 31, 2006, Western Power Operations entered into fixed price sales contracts to sell forward approximately 10,600 GWh for 2007 and 8,300 GWh for 2008.

Plant operations consist of five natural gas-fired cogeneration power plants located in Alberta with an approximate combined output capacity of 400 MW ranging from 27 MW to 165 MW per facility. A portion of the expected output is sold under long-term contracts and the remainder is subject to fluctuations in the price of power and gas. Market heat rate is an economic measure for natural gas-fired power plants determined by dividing the average price of power per MWh by the average price of natural gas per gigajoule (GJ) for a given period. To the extent power is not sold under long-term contracts and plant fuel gas has not been purchased under long-term contracts, the higher the market heat rate, the more profitable is a natural gas-fired generating facility. Market heat rates in Alberta increased in 2006 by more than 60 per cent as a result of a decrease in average spot market natural gas prices combined with an increase in power prices. Market heat rates averaged approximately 13.5 GJ/MWh in 2006 compared to approximately 8.3 GJ/MWh in 2005. The market heat rates are expected to return to more modest levels in 2007.

All plants in Western Power Operations operated with an average plant availability in 2006 of approximately 88 per cent compared to 85 per cent in 2005. Bear Creek returned to service in mid 2006 after experiencing an unplanned outage in 2005 resulting from technical difficulties with its gas turbine. Since its return to service, it has operated as expected.

MANAGEMENT'S DISCUSSION AND ANALYSIS 39

Western Power Operations Results-at-a-Glance
Year ended December 31 (millions of dollars)

    2006   2005   2004  
 
Revenues              
  Power   1,185   715   606  
  Other(1)   169   158   120  
 
    1,354   873   726  
 
Commodity purchases resold              
  Power   (767 ) (476 ) (377 )
  Other(1)   (135 ) (104 ) (64 )
 
    (902 ) (580 ) (441 )
 
Plant operating costs and other   (135 ) (149 ) (125 )
Depreciation   (20 ) (21 ) (22 )
 
Operating income   297   123   138  
 
(1)
Includes Cancarb Thermax and natural gas sales.

Western Power Operations Sales Volumes
Year ended December 31 (GWh)

    2006   2005   2004
Supply            
  Generation   2,259   2,245   2,105
  Purchased            
    Sundance A & B and Sheerness PPAs   12,712   6,974   6,842
    Other purchases   1,905   2,687   2,748
    16,876   11,906   11,695

Contracted vs. Spot
 
 
 
 
 
 
  Contracted   11,029   10,374   10,705
  Spot   5,847   1,532   990
    16,876   11,906   11,695

Operating income in 2006 of $297 million was $174 million higher than the $123 million earned in 2005. This increase was primarily due to incremental earnings from the December 31, 2005 acquisition of the 756 MW Sheerness PPA and increased margins from a combination of higher overall realized power prices and higher market heat rates on uncontracted volumes of power sold. Revenues and commodity purchases resold increased in 2006 compared to 2005 primarily due to the acquisition of the Sheerness PPA, as well as higher realized power prices. Plant operating costs and other, which include fuel gas consumed in generation, decreased due to lower natural gas prices. Purchased power volumes in 2006 increased compared to 2005 primarily due to the acquisition of the Sheerness PPA. In 2006, approximately 35 per cent of power sales volumes were sold into the spot market compared to 13 per cent in 2005.

Operating income for 2005 was $123 million or $15 million lower compared to $138 million earned in 2004. This decrease was primarily due to reduced margins in 2005 resulting from the lower market heat rates on uncontracted volumes of power generated, fee revenues earned in 2004 from Power LP and a lower contribution from Bear Creek. Revenues and commodity purchases resold increased in 2005, compared to 2004, primarily due to higher realized

40 MANAGEMENT'S DISCUSSION AND ANALYSIS


prices. Plant operating costs and other, which include fuel gas consumed in generation, increased due to higher operating and fuel usage costs at MacKay River resulting from a full year of operation and higher natural gas prices. Generation volumes in 2005 increased compared to 2004 primarily due to a full year of operations at MacKay River, partially offset by an unplanned outage at Bear Creek. TCPL ceased to earn fees to manage and operate Power LP's plants with the sale of Power LP in August 2005. In 2005, approximately 13 per cent of power sales volumes were sold into the spot market compared to eight per cent in 2004.

Eastern Power Operations

Eastern Power Operations conducts its business primarily in the deregulated New England power market and in eastern Canada. In the New England market, Eastern Power Operations has established a successful marketing operation and in 2006, significantly increased its marketing presence. Growth in generation capacity in eastern Canada was also significant. The first of the six Cartier Wind wind farm projects, Baie-des-Sables, was placed in service in November 2006. The 550 MW Bécancour power plant near Trois Rivières, Québec began operations in September 2006. Including facilities that are under construction or in development, Eastern Power Operations owns approximately 3,200 MW of power generation capacity. To reduce exposure to spot market prices of uncontracted volumes, as at December 31, 2006, Eastern Power Operations had fixed price sales contracts to sell forward approximately 11,900 GWh for 2007 and 9,600 GWh for 2008.

Eastern Power Operations' success in the New England deregulated power markets is the direct result of a knowledgeable, region-specific marketing operation which is conducted through its wholly owned subsidiary, TransCanada Power Marketing Ltd. (TCPM), located in Westborough, Massachusetts. TCPM has firmly established itself as a leading energy provider and marketer in the region and is focused on selling power under short – and long-term contracts to wholesale, commercial and industrial customers while managing a portfolio of power supplies sourced from both its own generation and wholesale power purchases. TCPM is a full requirement electric service provider offering varied products and services to assist customers in managing their power supply and power prices in volatile deregulated power markets.

Eastern Power Operations' current operating power generation assets are TC Hydro, OSP, Bécancour, Grandview and the Baie-des-Sables wind farm. The TC Hydro assets include 13 hydroelectric stations housing 39 hydroelectric generating units on the Connecticut River System in New Hampshire and Vermont and the Deerfield River System in Massachusetts and Vermont. Water flows in 2006 through the hydro assets were above long-term averages as a result of higher precipitation in the areas surrounding the river systems. These higher than expected water flows were partially offset by lower than expected power prices in the market during 2006.

OSP is a 560 MW natural gas-fired plant located in Rhode Island, owned 100 per cent by TCPL. In 2006, plant availability and utilization of the OSP facility improved compared to 2005. OSP realized lower overall natural gas fuel supply costs in 2006 compared to 2005 due to lower spot prices of natural gas as a result of a restructuring of its long-term gas supply contracts which took place in 2005.

Bécancour is a 550 MW natural gas-fired cogeneration plant located near Trois Rivières, Québec. After nearly three years of planning and construction, and an investment of approximately $500 million, Bécancour was placed in service in September 2006. The facility is capable of generating approximately 4,500 GWh of power per year. Under long-term contracts, the facility will supply electricity to Hydro-Québec to help meet growing electricity demands and provide an important source of steam for industrial processes.

Grandview is a 90 MW natural gas-fired cogeneration facility on the site of the Irving Oil Refinery (Irving) in Saint John, New Brunswick. Under a 20-year tolling arrangement which will expire in 2025, Irving supplies fuel for the plant and contracts for 100 per cent of the plant's heat and electricity output.

Eastern Power Operations' growing presence in eastern Canada is represented by the development of the Portlands Energy project and the Halton Hills power plant and construction in 2007 on the second and third of six proposed wind farms of the Cartier Wind project.

In November 2006, the Baie-des-Sable wind farm went into commercial operation and is currently one of the largest wind farms in Canada, providing up to 110 MW of power to the Hydro Québec grid. Baie-des-Sable is the first phase

MANAGEMENT'S DISCUSSION AND ANALYSIS 41


of a multi-phase, multi-year project called the Cartier Wind project that is owned 62 per cent by TCPL. The other phases of Cartier Wind will continue, subject to future appropriations and approvals, through 2012 at six different locations in the Gaspé region of Québec and capacity is expected to total 740 MW when all phases are complete. Commitments are in place for the 100 MW Anse à Valleau phase and the 100 MW Carleton phase Anse à Valleau is presently under construction and is expected to be placed into commercial service during third quarter 2007 and construction at Carleton will commence in late 2007 with expected commercial service to begin in fourth quarter 2008.

In September 2006, Portlands Energy, a 50/50 partnership between Ontario Power Generation and TCPL, announced that it had signed a 20-year ACES contract with the OPA to construct a 550 MW high efficiency, combined-cycle natural gas generation plant to be located in downtown Toronto, Ontario. The capital cost of the Portlands Energy project is estimated to be approximately $730 million and is expected to be operational in simple cycle mode, delivering 340 MW of electricity to the City of Toronto, beginning June 1, 2008. Upon the expected completion in second quarter 2009, the Company anticipates that this plant will provide up to 550 MW of power under the ACES contract.

In November 2006, TCPL announced that it had been awarded a 20-year Greater Toronto Area (GTA) West Trafalgar Clean Energy Supply contract by the OPA to build, own and operate a 683 MW natural gas-fired power plant near the town of Halton Hills, Ontario. TCPL expects to invest approximately $670 million in the Halton Hills Generating Station, which is anticipated to be in service in second quarter 2010.

On June 15, 2006, the FERC approved a settlement agreement to implement a newly-designed Forward Capacity Market (FCM) for power generation in the New England power markets. The FCM design is intended to promote investment in new and existing power resources needed to meet the growing consumer demand and maintain a reliable power system. The settlement agreement provides for a multi-year transition period beginning in December 2006 and ending in 2010, whereby fixed payments, ranging from US$3.05 to US$4.10 per kilowatt-month, will be made to owners of existing installed capacity. These payments will be reduced in the event of facility-forced outages. Eastern Power Operations' 560 MW OSP plant and 567 MW TC Hydro generation facilities are eligible to receive payments during the transition period starting in December 2006. Under the new FCM design, Independent System Operator New England will project the needs of the power system three years in advance and then hold an annual auction to purchase power resources to satisfy a region's future needs. June 1, 2010 is identified as the first period for which suppliers would receive payments pursuant to the FCM auction mechanism.

Eastern Power Operations Results-at-a-Glance(1)
 Year ended December 31 (millions of dollars)

    2006   2005   2004    
Revenues                
  Power   789   505   535    
  Other(2)   292   412   238    
    1,081   917   773    
Commodity purchases resold                
  Power   (379 ) (215 ) (288 )  
  Other(2)   (257 ) (373 ) (211 )  
    (636 ) (588 ) (499 )  
Plant operating costs and other   (226 ) (167 ) (146 )  
Depreciation   (32 ) (25 ) (20 )  
Operating income   187   137   108    
(1)
Curtis Palmer is included until April 30, 2004.

(2)
Other includes natural gas.

42 MANAGEMENT'S DISCUSSION AND ANALYSIS

Eastern Power Operations Sales Volumes(1)
 Year ended December 31 (GWh)

    2006   2005   2004  
Supply              
  Generation   4,700   2,879   1,467  
  Purchased   3,091   2,627   4,731  
    7,791   5,506   6,198  

Contracted vs. Spot
 
 
 
 
 
 
 
  Contracted   7,374   4,919   6,055  
  Spot   417   587   143  
    7,791   5,506   6,198  
(1)
Curtis Palmer is included until April 30, 2004.

Operating income for 2006 was $187 million or $50 million higher than the $137 million earned in 2005. This increase is primarily due to incremental income from the full year of ownership of the TC Hydro assets, the placing into service of the 550 MW Bécancour cogeneration plant in September 2006, a $10-million after-tax one-time restructuring payment in first quarter 2005 from OSP to its natural gas fuel suppliers, and higher overall margins on power sales volumes in 2006. Partially offsetting these increases was the negative impact of a weaker U.S. dollar in 2006 compared to 2005.

Eastern Power Operations' revenues in 2006 were $1,081 or $164 million higher than the $917 million earned in 2005. This is due to the placing into service of the Bécancour facility, increased sales volumes to commercial and industrial customers, and higher realized prices. Other revenue and other commodity purchases resold decreased year-over-year as a result of a reduction in the quantity of natural gas purchased and resold under the new natural gas supply contracts at OSP. Power commodity purchases resold were higher in 2006 due to the impact of higher purchased volumes, combined with higher prices for purchased power. Purchased power volumes were higher in 2006 due to higher contracted sales volumes, partially offset by the increased power generation from the purchase of the TC Hydro assets as volumes generated from the TC Hydro assets reduced the requirement to purchase power to fulfil contractual sales obligations. Plant operating costs and other in 2006 were higher primarily due to the full year of operations of the TC Hydro assets as well as the placing into service of the Bécancour and Baie-des-Sables facilities.

Operating income for 2005 was $137 million or $29 million higher than the $108 million earned in 2004. The incremental income from the acquisition of the TC Hydro assets and income from the Grandview cogeneration facility were the primary reasons for this increase. Partially offsetting these increases were the contract restructuring payment made by OSP in first quarter 2005, a $10-million after-tax reduction in income as a result of the sale of Curtis Palmer to Power LP in April 2004, and a loss of operating income primarily associated with the expiration of certain long-term sales contracts in 2004.

Power LP Divestiture

On August 31, 2005, TCPL sold all of its interest in Power LP to EPCOR for net proceeds of $523 million resulting in an after-tax gain of $193 million. This divestiture included approximately 14.5 million partnership units, representing approximately 30.6 per cent of the outstanding units, 100 per cent of the general partnership of Power LP, and management and operations agreements governing the ongoing operation of Power LP's generation assets. TCPL's investment in Power LP generated operating income of $29 million in each of 2005 and 2004.

MANAGEMENT'S DISCUSSION AND ANALYSIS 43

Plant Availability


GRAPHIC
 
Weighted average power plant availability for all plants, excluding Bruce Power, was 93 per cent in 2006 compared to 87 per cent in 2005 and 96 per cent in 2004. 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. Western Power Operations' plant availability was impacted in 2006 and 2005 by an unplanned outage at Bear Creek, which returned to service in August 2006. An additional planned outage was taken in 2005 at the MacKay River facility, further decreasing the plant availability for Western Power Operations in 2005. Availability of 95 per cent was achieved in Eastern Power Operations in 2006. Availability was lower in 2005 as a result of OSP experiencing two significant outages.

Weighted Average Plant Availability(1)
 Year ended December 31

    2006   2005   2004
Bruce Power(2)   88%   80%   82%
Western Power Operations(3)   88%   85%   95%
Eastern Power Operations(4)   95%   83%   95%
Power LP investment(5)   –       94%   97%
All plants, excluding Bruce Power investment   93%   87%   96%
All plants   91%   84%   90%
(1)
Plant availability represents the percentage of time in the period that the plant is available to generate power, whether actually running or not and is reduced by planned and unplanned outages.

(2)
Bruce A Unit 3 is included effective March 1, 2004.

(3)
The Sheerness PPA is included in Western Power Operations, effective December 31, 2005.

(4)
TC Hydro, Bécancour and Cartier Wind's Baie-des-Sables are included in Eastern Power Operations effective April 1, 2005, September 17, 2006 and November 21, 2006, respectively.

(5)
Power LP is included to August 31, 2005.

Natural Gas Storage

With the completion of the 50 Bcf Edson storage facility, TCPL became one of the largest natural gas storage providers in western Canada in 2006. TCPL owns or controls 138 Bcf of natural gas storage capacity in Alberta, which includes a 60 per cent ownership interest in CrossAlta Gas Storage & Services Ltd. (CrossAlta), an independently operated 50 Bcf storage facility. TCPL also has contracts for 38 Bcf in 2007 of long-term, Alberta-based storage capacity from a third party.

Natural Gas Storage Capacity

    Working Gas
Storage Capacity
(Bcf

)		 Maximum Injection/
Withdrawal Capacity
(mmcf/d

)		  
Edson   50   725    
CrossAlta   50   480    
Third Party Storage (for 2007)   38   630    
    138   1,835    

44 MANAGEMENT'S DISCUSSION AND ANALYSIS

TCPL believes the market fundamentals for natural gas storage are strong. The additional gas storage capacity will help balance seasonal and short-term supply and demand, and provide flexibility to the supply of natural gas to Alberta and North America. The increasing seasonal imbalance in North American natural gas supply and demand has increased gas price volatility and the demand for storage service. Alberta-based storage will continue to serve market needs and could play an important role should northern gas be connected to North American markets. Energy's natural gas storage business operates independently from TCPL's regulated natural gas transmission business.

TCPL manages its exposure to seasonal gas price spreads by hedging storage capacity with a portfolio of third party storage contracts and gas purchases and sales. TCPL offers a broad range of flexible injection and withdrawal storage alternatives specific to customer needs in multi-year contract terms. In addition to term gas storage contracts, TCPL actively manages its storage assets with a combination of gas hedging activities and short-term third party contracts to take advantage of market opportunities and meet unique customer needs. Market volatility frequently creates arbitrage opportunities and TCPL offers market centre solutions to capture these short-term price movements. Market centre products consist of short-term deliver- redeliver contracts, parking, peak-day supply and other related services.

The Edson storage operation is an underground natural gas storage facility consisting of a single depleted reservoir, the Viking D pool, a central processing facility and associated pipeline gathering system. The plant is located near Edson, Alberta. The Viking D pool produced approximately 71 Bcf of gas over its productive life from the 1980's to early 2004. The natural gas storage facility is expected to have a working natural gas capacity of approximately 50 Bcf, is connected to TCPL's Alberta System and has a central processing system capable of maximum injection and withdrawal rates of 725 mmcf/d of natural gas. Construction of the Edson facility was substantially completed in 2006 and placed into service on December 31, 2006.

The CrossAlta storage facility is a 50 Bcf natural gas storage facility located near the town of Crossfield, Alberta. CrossAlta is a joint venture with BP Canada that has been in operation since 1994 and markets its own storage capacity and services. Gas is stored in a depleted gas reservoir that has been used to produce gas at this location since the 1960s. CrossAlta successfully completed a major expansion in the fall of 2005. The expansion increased total working natural gas capacity from 40 Bcf to 50 Bcf, with the potential to expand to 80 Bcf. The storage facility has a peak withdrawal capacity of 480 mmcf/d with the potential to expand to 1,000 mmcf/d.

The third-party natural gas storage capacity contracted by TCPL is also located in Alberta. The capacity has increased annually from 18 Bcf in 2005 to 28 Bcf in 2006 and is expected to reach 38 Bcf in 2007. The contract expires in 2030, subject to mutual early termination rights in 2015.

Natural Gas Storage operating income of $93 million for the year ended December 31, 2006 increased $61 million and $66 million, compared to 2005 and 2004, respectively. The increases were primarily due to higher contributions from CrossAlta as a result of increased capacity and higher natural gas storage spreads, and income from contracted third-party natural gas storage capacity. The Edson facility did not contribute to earnings in 2006 as the asset was placed into service on December 31, 2006.

LNG Projects

TCPL continues to pursue two LNG proposals, the Broadwater and Cacouna projects. Broadwater, a joint venture with Shell US Gas & Power LLC (Shell), is a proposed LNG facility in the New York and Connecticut State waters in Long Island Sound. The Broadwater terminal would be capable of receiving, storing, and regassifying imported LNG with an average send-out capacity of approximately 1 Bcf/d of natural gas. TCPL, on behalf of Broadwater, filed an application in January 2006 with the FERC for approval of the project. The U.S. Coast Guard issued a report which determined that the waterways associated with the project are suitable if additional measures are implemented to manage the safety and security risks associated with the project. Broadwater's application to the New York Department of State for a determination that the project is consistent with New York's coastal zone policies was deemed complete by the state in November 2006. Also in November, the FERC issued a Draft Environmental Impact Statement to fulfil the requirements of the National Environmental Policy Act and the FERC's implementing regulations. The Statement concludes that with strict adherence to federal and state permit requirements and regulations, Broadwater's proposed mitigation measures

MANAGEMENT'S DISCUSSION AND ANALYSIS 45

and the FERC's recommendations, the Broadwater project will not result in a significant impact on the environment. At December 31, 2006 the Company had capitalized $31 million related to Broadwater.

Cacouna, a joint venture with Petro-Canada, is a proposed LNG project at the Gros Cacouna harbour on the St. Lawrence River in Québec. The proposed terminal would be capable of receiving, storing, and regassifying imported LNG with an average throughput capacity of approximately 500 mmcf/d of natural gas. A public hearing on the Cacouna facility was held in May and June 2006. In December 2006, the Québec government released the report of the Joint Commission on the Cacouna Energy project, which contained several recommendations and opinions but appears to be favourable to the project. TCPL continues to work towards gaining regulatory approval and, if the necessary approvals are obtained, the facility is anticipated to be in service by 2010.

ENERGY – OPPORTUNITIES AND DEVELOPMENTS

TCPL is committed to growing its North American Energy business through acquisitions and development of greenfield opportunities in markets it knows and has a competitive advantage – primarily western Canada, the northwestern U.S., eastern Canada and the northeastern U.S. The North American energy industry is expansive and will provide many opportunities for greenfield growth in power generation, power infrastructure projects and natural gas storage. In addition to greenfield growth opportunities, TCPL will endeavour to pursue acquisitions resulting from industry and corporate restructurings and corporate bankruptcies. In addition to natural gas-fired facilities, Energy will focus on generation sourced from wind, hydro and nuclear. Its diverse power supply portfolio will continue to include low-cost, base-load facilities with low operating costs and high reliability, which may be underpinned by secure long-term contracts.

The Bécancour natural gas-fired cogeneration power plant and the first of six wind farms in the Cartier Wind project, both located in Québec, were placed in service in 2006. The remaining five Cartier Wind farms will continue, although certain phases of the project are subject to future appropriations and approvals. Construction began in 2006 on Portlands Energy's 550 MW, combined cycle natural gas generation plant in downtown Toronto. In 2006, TCPL also announced that it had been awarded a 20-year GTA West Trafalgar Clean Energy Supply contract by the OPA to build, own and operate a 683 MW natural gas-fired power plant near the town of Halton Hills, Ontario which is expected to be completed in 2010. The Bruce A restart and refurbishment continued in 2006 and Units 1 and 2 are expected to be restarted in late 2009 or early 2010.

Construction of the 50 Bcf Edson natural gas storage facility was substantially completed and the facility placed into service on December 31, 2006.

TCPL is pursuing two LNG projects, Broadwater and Cacouna. Broadwater is a joint project with Shell to build a 1 Bcf/d LNG facility in the waters of the Long Island Sound. Cacouna is a joint venture with Petro-Canada to construct a 500 mmcf/d LNG facility at Gros Cacouna.

ENERGY – BUSINESS RISKS

Fluctuating Power and Natural Gas Market Prices

TCPL operates in competitive, generally deregulated power and natural gas markets in North America. Volatility in power and natural gas prices is caused by various market forces such as fluctuating supply and demand which are greatly affected by weather events. Energy's earnings from the sale of uncontracted volumes are subject to price volatility. Although Energy commits a significant portion of its supply to medium- to long-term sales contracts, it retains an amount of unsold supply in order to provide flexibility in managing the Company's portfolio of owned assets. The Company's risk management practices are described further in the section on Risk Management. See the "Uncontracted Volumes" section below.

Uncontracted Volumes

Energy has certain uncontracted power sales volumes in Western and Eastern Power Operations and through its investment in Bruce Power. Sale of uncontracted power volumes into the spot market is subject to market price

46 MANAGEMENT'S DISCUSSION AND ANALYSIS

volatility which directly impacts earnings. Bruce B has a significant amount of uncontracted volumes sold into the wholesale power spot market while 100 per cent of the Bruce A output is sold to the OPA under fixed-price contract terms. The natural gas storage business is subject to fluctuating natural gas seasonal spreads generally determined by the differential in natural gas prices in the traditional summer injection and winter withdrawal seasons. As a result, the Company hedges capacity with a portfolio of contractual commitments with varying terms.

Plant Availability

Maintaining plant availability is essential to the continued success of the Energy business. Plant operating risk is mitigated through a commitment to TCPL's operational excellence strategy that provides low-cost, reliable operating performance at each of the Company's facilities. Unexpected plant outages and/or the duration of outages could result in lower plant output and sales revenue, reduced margins and increased maintenance costs. At certain times, unplanned outages may require power or natural gas purchases at market prices to enable TCPL to meet its contractual obligations.

Weather

Extreme temperature and weather events in North America and the Gulf of Mexico often create price volatility and demand for power and natural gas. These same events may also restrict the availability of power and natural gas. Seasonal changes in temperature can also affect the efficiency and output capability of natural gas-fired power plants. Variability in wind speeds may impact the earnings of the Cartier Wind assets in Québec.

Hydrology

Energy's power business is subject to hydrology risk with its ownership of hydroelectric power generation facilities in the northeastern U.S. Weather changes, weather events, local river management and potential dam failures at these plants or upstream facilities pose potential risks to the Company.

Execution and Capital Cost

Energy's new construction program in Ontario and Québec, including its investment in Bruce Power, is subject to execution and capital cost risk. At Bruce Power, Bruce A's four unit restart and refurbishment program is also subject to a capital cost risk-and reward-sharing mechanism with the OPA.

Asset Commissioning

Recently constructed assets including Edson, Baie-des-Sables and Bécancour were all placed in service during 2006 and are in the first full year of operation in 2007. Although all of TCPL's newly constructed assets go through rigorous acceptance testing prior to being placed in service, there is a risk that these assets may have lower than expected availability or performance, especially in the assets' first year of operations.

Power Regulatory

TCPL 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 TCPL as a generator and marketer of electricity. These may be in the form of market rule changes, price caps, emission controls, unfair cost allocations to generators or attempts to control the wholesale market by encouraging new plant construction. TCPL continues to monitor regulatory issues and reform as well as participate in and lead discussions around these topics.

For information on management of risks with respect to the Energy business, refer to the "Risks and Risk Management" section of this MD&A.

ENERGY – OUTLOOK

In Energy, net earnings in 2007 are expected to approximate or be slightly lower than 2006 net earnings due to the non-recurring $23-million future tax benefit in 2006 arising from reductions in federal and provincial income tax rates. Operating income is expected to be relatively consistent with 2006, although this is very dependent on commodity prices in each region as well as other factors such as hydrology and storage spreads. TCPL's operating income from its investment in Bruce B can be significantly impacted by the effect, on uncontracted output, of changes in spot market prices for power. Excluding any changes in spot market prices for 2007 compared to 2006, Bruce Power's operating

MANAGEMENT'S DISCUSSION AND ANALYSIS 47


income is expected to decline in 2007 compared to 2006, reflecting lower projected generation volumes and higher operating costs resulting from an increase in planned outages in 2007. Western Power Operations' operating income in 2007 is expected to approximate 2006. Although TCPL has sold forward significant output from its Alberta PPAs and power plants, Western Power Operations' operating income in 2007 can be significantly impacted by changes in the spot market price of power and market heat rates in Alberta. Eastern Power Operations' operating income is expected to increase in 2007 primarily due to a full year of operations for both the Bécancour natural gas-fired cogeneration facility and the first of six wind farms of the Cartier Wind project as well as the positive impact of the NEPOOL forward capacity payments received by OSP and TC Hydro commencing December 1, 2006. Gas Storage's operating income is expected to increase in 2007 over 2006 primarily due to the placing into service of the Edson facility at the end of 2006, partially offset by expected lower storage spreads.

The earnings outlook for Energy may be affected by factors such as fluctuating market prices for power and natural gas, market heat rates, sales of uncontracted power volumes, natural gas storage spreads, plant availability, regulatory changes, weather, currency movements, and overall stability of the energy industry. See "Energy – Business Risks" for a complete discussion of these factors.

CORPORATE

CORPORATE RESULTS-AT-A-GLANCE
Year ended December 31 (millions of dollars)

    2006   2005   2004  
 
Indirect financial charges and non-controlling interests   139   131   81  
Interest income and other   (43 ) (29 ) (34 )
Income taxes   (133 ) (65 ) (43 )
 
Net (earnings)/expenses, after tax   (37 ) 37   4  
 

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

Net earnings, after tax, in Corporate were $37 million in 2006 compared to net expenses of $37 million in 2005 and $4 million in 2004.

The increase of $74 million in net earnings in 2006, compared to 2005, was primarily due to a $50-million income tax benefit related to the resolution of certain income tax matters reported in third quarter 2006, $12 million of income tax refunds and related interest income in fourth quarter 2006, and a $10-million favourable impact on future income taxes arising from reductions in Canadian federal and provincial corporate income tax rates in second quarter 2006. In addition, net earnings in 2006 were positively impacted by the effect of a weaker U.S. dollar.

The increase of $33 million in net expenses in 2005 compared to 2004 was primarily due to increased interest expense on higher average long-term debt and commercial paper balances in 2005 as well as the release in 2004 of previously

48 MANAGEMENT'S DISCUSSION AND ANALYSIS


established restructuring provisions. Income tax refunds and positive tax adjustments were comparable in 2004 and 2005.

In 2007, Corporate's net expenses are expected to be higher in 2007 compared to 2006 primarily due to income tax refunds and positive income tax adjustments realized in 2006 that are not expected to recur in 2007. Financing costs associated with the acquisition of ANR are expected to increase net expenses in Corporate in 2007. In addition, Corporate's results could be impacted by debt levels, interest rates, foreign exchange movements and income tax refunds and adjustments. The performance of the Canadian dollar relative to the U.S. dollar will either positively or negatively impact Corporate's results, although this impact is mitigated by offsetting exposures in certain of TCPL's other businesses as well as through the Company's hedging activities.

DISCONTINUED OPERATIONS

In 2006, the Company recognized income from discontinued operations of $28 million, reflecting bankruptcy settlements with Mirant related to TCPL's Gas Marketing business divested in 2001. In 2005, the Company reviewed the provision for loss on discontinued operations and concluded that the provision was adequate. In 2004, $52 million was recognized in income which related to the original $102 million after-tax deferred gain included in the sale of the Gas Marketing business.

LIQUIDITY AND CAPITAL RESOURCES

Summarized Cash Flow
Year ended December 31 (millions of dollars)

    2006   2005   2004  
 
Funds generated from operations   2,374   1,950   1,701  
(Increase)/decrease in working capital   (300 ) (48 ) 28  
 
Net cash provided by operations   2,074   1,902   1,729  
Net cash used in investing activities   (2,114 ) (1,335 ) (1,648 )
Net cash provided by/(used in) financing activities   220   (556 ) (147 )
Effect of foreign exchange rate changes on cash and short-term investments   9   11   (87 )
 
Increase/(decrease) in cash and short-term investments   189   22   (153 )
Cash and short-term investments – beginning of year   212   190   343  
 
Cash and short-term investments – end of year   401   212   190  
 

MANAGEMENT'S DISCUSSION AND ANALYSIS 49

HIGHLIGHTS

Investing Activities

Dividends


Funds Generated from Operations


GRAPHIC
 
Funds Generated from Operations Funds generated from operations were $2.4 billion in 2006 compared to $2.0 billion and $1.7 billion, in 2005 and 2004, respectively. The increase in 2006 compared to 2005 was mainly as a result of higher net income, excluding gains, and lower current income tax expense. The Pipelines business was the primary source of funds generated from operations for each of the three years. As a result of rapid growth in the Energy business in the last few years, the Energy segment's funds generated from operations increased in 2006 compared to the two prior years.

At December 31, 2006, TCPL'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 recent years.

Investing Activities

Capital expenditures, totalled $1,572 million in 2006 compared to $754 million in 2005 and $530 million in 2004, respectively. Expenditures in all three years related primarily to construction of new power plants and natural gas storage facilities in Canada as well as maintenance and capacity capital in the Pipelines business.



GRAPHIC

 

During 2006, PipeLines LP acquired an additional 49 per cent interest in Tuscarora, subject to closing adjustments, for US$100 million, in addition to indirectly assuming US$37 million of debt. In addition, PipeLines LP acquired an additional 20 per cent general partnership interest in Northern Border for US$307 million, in addition to indirectly assuming US$122 million of debt. At December 31, 2006, TCPL held a 13.4 per cent interest in PipeLines LP. In 2006, TCPL sold its 17.5 per cent general partner interest in Northern Border Partners, L.P. for proceeds of $23 million.
During 2005, TCPL acquired the remaining rights and obligations of the Sheerness PPA for $585 million, invested a net cash outlay of $100 million in Bruce A as part of the Bruce Power reorganization, purchased the TC Hydro assets from USGen New England, Inc. (USGen) for US$503 million and acquired an additional 3.52 per cent ownership interest in Iroquois for
US$14 million. TCPL sold its ownership interest in Power LP for proceeds of $444 million, net of current tax, its approximate 11 per cent ownership interest in Paiton Energy for proceeds of $125 million, net of current tax, and PipeLines LP units for proceeds of $102 million, net of current tax.

During 2004, TCPL acquired GTN for US$1.2 billion, excluding assumed debt of approximately US$500 million, and sold the ManChief and Curtis Palmer power facilities to Power LP for US$403 million, excluding closing adjustments.

Financing Activities

On February 22, 2007, the Company completed its acquisition of ANR and an additional interest in Great Lakes which was financed through the issuance of a combination of debt and common shares. At the same time, PipeLines LP completed the acquisition of its interest in Great Lakes through the issuance of a combination of debt and equity. These financings are summarized in the section "Subsequent Events" in this MD&A.

50 MANAGEMENT'S DISCUSSION AND ANALYSIS

On February 15, 2007, TCPL retired $275 million of 6.05 per cent medium term notes. In 2006, TCPL retired long-term debt of $729 million and reduced its notes payable by $495 million. In January 2006, the Company issued $300 million of 4.3 per cent five-year medium-term notes due 2011. In March 2006, the Company issued US$500 million of 5.85 per cent 30-year senior unsecured notes due 2036. In October 2006, TCPL issued $400 million of 4.65 per cent ten-year medium-term notes due 2016.

In April 2006, PipeLines LP borrowed US$307 million under its unsecured credit facility to finance the cash portion of the purchase price of its acquisition of an additional 20 per cent interest in Northern Border. In December 2006, the credit facility was repaid in full and replaced with a US$410 million syndicated revolving credit and term loan agreement, of which US$397 million was drawn as at December 31, 2006. Borrowings under the credit and term loan agreement will bear interest at the London interbank offered rate plus an applicable margin.

In 2005, TCPL retired long-term debt of $1,113 million and increased its notes payable by $416 million. In June 2005, Gas Transmission Northwest Corporation (GTNC) redeemed all of its outstanding US$150 million 7.8 per cent Senior Unsecured Debentures (Debentures) and US$250 million 7.1 per cent Senior Unsecured Notes. As a consequence, upon application by GTNC, the Debentures were de-listed from the New York Stock Exchange and GTNC no longer has any securities registered under U.S. securities laws. In June 2005, GTNC also completed a US$400-million multi-tranche private placement of senior debt with a weighted average interest rate of 5.28 per cent and weighted average life of approximately 18 years. In 2005, TCPL also issued $300 million of 5.1 per cent medium-term notes due 2017 under the Company's Canadian shelf prospectus.

In 2004, TCPL retired long-term debt of $1,005 million. The Company issued $200 million of 4.1 per cent medium-term notes due 2009, US$350 million of 5.6 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.

Financing activities included a net reduction in TCPL's proportionate share of non-recourse debt of joint ventures of $14 million in 2006 compared to $42 million in 2005 and a net increase of $105 million in 2004.

Dividends on common and preferred shares of $639 million were paid in 2006 compared to $608 million in 2005 and $574 million in 2004.

In January 2007, TransCanada's Board of Directors authorized the issue of common shares from treasury at a discount to participants in the Company's DRP. Under this plan, eligible TCPL preferred shareholders may reinvest their dividends to obtain additional TransCanada common shares. Previously, shares purchased through the DRP were purchased by TransCanada on the open market and provided to DRP participants at cost. Commencing with the dividend payable in April 2007, the shares will be provided to the participants at a two per cent discount. TransCanada reserves the right to alter the discount or return to purchasing shares on the open market at any time.

At December 31, 2006, total credit facilities of $2.1 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 five-year term syndicated credit facility. The facility is extendible on an annual basis and is revolving. In December 2006, the maturity date of this facility was extended to December 2011. The remaining amounts are either demand or non-extendible facilities.

At December 31, 2006, TCPL had used approximately $190 million of its total lines of credit for letters of credit 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.

TCPL's senior unsecured debt is rated A, with a stable outlook, by Dominion Bond Rating Service Limited (DBRS); A2, with a stable outlook, by Moody's Investors Service (Moody's); and A-, with a negative outlook, by Standard and Poor's (S&P). DBRS had placed TCPL's rating under review with developing implications on December 22, 2006 as a result of the announcement of the acquisition of ANR and Great Lakes. Moody's and S&P reaffirmed their ratings after the announcement. On February 22, 2007, DBRS confirmed their rating of TCPL and removed the rating from being under review. TransCanada's issuer rating assigned by Moody's is A3 with a stable outlook.

MANAGEMENT'S DISCUSSION AND ANALYSIS 51


CONTRACTUAL OBLIGATIONS

Obligations and Commitments

Total long-term debt at December 31, 2006 was approximately $11.5 billion compared to approximately $10.0 billion at December 31, 2005. TCPL's share of total debt of joint ventures at December 31, 2006 was $1.3 billion compared to $1.0 billion at December 31, 2005. Total notes payable at December 31, 2006, including TCPL's proportionate share of the notes payable of joint ventures, were $467 million compared to $962 million at December 31, 2005. The security provided by each joint venture, except for the capital lease obligation at Bruce Power, is limited to the rights and assets of that joint venture and does not extend to the rights and assets of TCPL, except to the extent of TCPL's investment. TCPL has provided certain pro-rata guarantees related to the capital lease obligations of Bruce Power.

CONTRACTUAL OBLIGATIONS
Year ended December 31 (millions of dollars)

 
    
   Payments Due by Period
       
    Total   Less than
one year		   1 - 3
years		   3 - 5
years		   More than
5 years
Long-term debt   12,531   750   1,605   1,803   8,373
Capital lease obligations   250   8   20   28   194
Operating leases1   919   39   83   84   713
Purchase obligations   11,871   2,707   3,274   1,403   4,487
Other long-term liabilities reflected on the balance sheet   304   10   23   27   244
Total contractual obligations   25,875   3,514   5,005   3,345   14,011
(1)
Represents future annual payments, net of sub-lease receipts, for various premises, services, equipment and a natural gas storage facility. The operating lease agreements for premises expire at various dates through 2016, with an option to renew certain lease agreements for three to 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, 2006, scheduled principal repayments and interest payments related to long-term debt and the Company's proportionate share of the long-term debt and capital lease obligations of joint ventures are as follows.

PRINCIPAL REPAYMENTS
Year ended December 31 (millions of dollars)

 
    
   Payments Due by Period
       
    Total   Less than
one year		   1 - 3
years		   3 - 5
years		   More than
5 years
Long-term debt   11,503   616   1,396   1,536   7,955
Long-term debt of joint ventures   1,028   134   209   267   418
Capital lease obligations   250   8   20   28   194
Total principal repayments   12,781   758   1,625   1,831   8,567

52 MANAGEMENT'S DISCUSSION AND ANALYSIS

INTEREST PAYMENTS
Year ended December 31 (millions of dollars)

 
    
   Payments Due by Period
       
    Total   Less than
one year		   1 - 3
years		   3 - 5
years		   More than
5 years
Interest payments on long-term debt   11,963   888   1,625   1,411   8,039
Interest payments on long-term debt of joint ventures   687   86   160   105   336
Total interest payments   12,650   974   1,785   1,516   8,375

At December 31, 2006, the Company's future purchase obligations are approximately as follows.

PURCHASE OBLIGATIONS(1)
Year ended December 31 (millions of dollars)

 
    
   Payments Due by Period
       
    Total   Less than one year   1 - 3
years		   3 - 5
years		   More than 5 years
Pipelines                    
Transportation by others(2)   648   178   257   126   87
Other   92   92   –   –   –

Energy
 
 
 
 
 
 
 
 
 
 
Commodity purchases(3)   8,807   1,396   2,051   1,101   4,259
Capital expenditures(4)   1,875   854   842   118   61
Other(5)   374   169   90   42   73

Corporate
 
 
 
 
 
 
 
 
 
 
Information technology and other   75   18   34   16   7
Total purchase obligations   11,871   2,707   3,274   1,403   4,487
(1)
The amounts in this table exclude funding contributions to pension plans and funding to the APG.

(2)
Rates are based on known 2007 levels. Beyond 2007, 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)
Represents primarily estimated capital expenditures to construct new Energy projects. Amounts are estimates and are subject to variability based on timing of construction and project enhancements. The Company expects to fund these projects with cash from operations and, if necessary, new debt.

(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.

During 2007, TCPL expects to make funding contributions to the Company's pension plans and other benefit plans in the amount of approximately $44 million and $5 million, respectively. The expected decrease in total pension and post-retirement benefits funding in 2007 from $104 million in 2006 is primarily attributed to the actual return on plan

MANAGEMENT'S DISCUSSION AND ANALYSIS 53


assets for 2006 exceeding investment performance expectations as well as additional company funding in 2006. These decreases were partially offset by increases in pension-funding liabilities due to plan experience being different from expected. During 2007, TCPL's proportionate share of expected funding contributions to be made by joint ventures to their respective pension plans and other benefit plans is approximately $33 million and $3 million, respectively.

TCPL has guaranteed the performance of all obligations of PipeLines LP with respect to its acquisition of a 46.45 per cent interest in Great Lakes pursuant to the purchase agreement.

TCPL 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.

Bruce Power

Included in Energy's capital expenditures in the previous table are TCPL's share of Bruce A's commitments to third party suppliers for the next four years for the restart and refurbishment of the currently idle Units 1 and 2, extending the operating life of Unit 3 by replacing its steam generators and fuel channels when required, and the replacement of the steam generators on Unit 4, as follows.

Year ended December 31 (millions of dollars)

2007   450
2008   164
2009   71
2010   1
2011   –
    686

In addition to the Bruce restart and refurbishment, the Company is committed to capital expenditures of approximately $1.2 billion for the construction of its Halton Hills, Portlands Energy and remaining Cartier Wind projects, subject to future appropriations and approvals.

Aboriginal Pipeline Group

On June 18, 2003, the Mackenzie Delta gas producers, the APG and TCPL reached an agreement which governs TCPL's role in the MGP project. The project would result in a natural gas pipeline being constructed from Inuvik, Northwest Territories, to the northern border of Alberta, where it would connect with the Alberta System. Under the agreement, TCPL agreed to finance the APG for its one-third share of pre-development costs. These costs are currently forecasted to be approximately $145 million by the end of 2007.

Guarantees

TCPL had no outstanding guarantees related to the long-term debt of unrelated third parties at December 31, 2006.

The Company, together with Cameco and BPC, has severally guaranteed one-third of certain contingent financial obligations of Bruce B related to power sales agreements, operator licenses, the lease agreement, and contractor services. The terms of the guarantees range from 2007 to 2018.

As part of the reorganization of Bruce Power in 2005, including the formation of Bruce A and the commitment to restart and refurbish the Bruce A units, the Company, together with BPC, severally guaranteed one-half of certain contingent financial obligations of Bruce A related to the refurbishment agreement with the OPA and cost sharing and sublease agreements with Bruce B. The terms of the guarantees range from 2019 to 2036.

TCPL's share of the net exposure under these Bruce Power guarantees at December 31, 2006 was estimated to be approximately $586 million of a calculated maximum of $658 million. The current carrying amount of the liability related to these guarantees is nil and the fair value is approximately $17 million.

54 MANAGEMENT'S DISCUSSION AND ANALYSIS


TCPL has guaranteed the equity undertaking of a subsidiary which supports the payment, under certain conditions, of principal and interest on US$105 million of public debt obligations of TransGas de Occidente S.A. (TransGas). The Company has a 46.5 per cent interest in TransGas. Under the terms of the agreement, the Company, severally with another major multinational company, may be required to fund more than their proportionate share of debt obligations of TransGas in the event that the minority shareholders fail to contribute. Any payments made by TCPL under this agreement convert into share capital of TransGas. The potential exposure is contingent on the impact of any change of law on TransGas' ability to service the debt. From the issuance of the debt in 1995 to date, there has been no change in applicable law and thus no exposure to TCPL. The debt matures in 2010 and the Company has made no provision related to this guarantee.

In connection with the acquisition of GTN in 2004, US$241 million of the purchase price was deposited into an escrow account. As at December 31, 2006, there was US$24 million remaining in the escrow account, which represented the full face amount of the potential liability under certain GTN guarantees. In February 2007, the funds were released and a portion of the monies were used to satisfy the liability of GTN under these designated guarantees.

Contingencies

The Canadian Alliance of Pipeline Landowners' Associations (CAPLA) and two individual landowners commenced an action in 2003 under Ontario's Class Proceedings Act, 1992, against TCPL and Enbridge Inc. for damages of $500 million alleged to arise from the creation of a control zone within 30 metres of the pipeline pursuant to Section 112 of the NEB Act. In November 2006, TCPL and Enbridge Inc. were granted a dismissal of the case but CAPLA has appealed that decision. The Company continues to believe 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, purchases and sells energy commodities, including amounts in foreign currencies, 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 exposure that results from these activities. The use of derivatives is subject to the Company's overall risk management policies and procedures.

Derivatives and other instruments must be designated and be effective to qualify for hedge accounting. Derivatives are recorded at their fair value at each balance sheet date. For cash flow and fair value hedges, gains or losses relating to derivatives are deferred and recognized in the same period and in the same financial statement category as the corresponding hedged transactions. For hedges of net investments in self-sustaining foreign operations, exchange gains or losses on derivatives, after tax, and designated foreign currency denominated debt are offset against the exchange gains or losses arising on the translation of the financial statements of the foreign operations included in the foreign exchange adjustment account in Shareholders' Equity. In the event that a derivative does not meet the designation or effectiveness criteria, realized and unrealized gains or losses are recognized in income each period in the same financial statement category as the underlying transaction. Premiums paid or received with respect to derivatives that are hedges are deferred and amortized to income over the term of the hedge.

If a derivative that previously qualified as a hedge is settled, de-designated or ceases to be effective, the gain or loss at that date is deferred and recognized in the same period and in the same financial statement category as the corresponding hedged transactions. If a hedged anticipated transaction is no longer likely to occur, related deferred gains or losses are recognized in income in the current period.

MANAGEMENT'S DISCUSSION AND ANALYSIS 55

The recognition of gains and losses on the derivatives for the Canadian Mainline, Alberta System, Foothills and the BC System exposures is determined through the regulatory process. The gains and losses on derivatives accounted for as part of rate-regulated accounting that do not meet the criteria for hedge accounting are deferred.

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

Net Investment in Foreign Operations

At December 31, 2006 and 2005, the Company had net investments in self-sustaining foreign operations with a U.S. dollar functional currency which created an exposure to changes in exchange rates. The Company uses U.S. dollar denominated debt and derivatives to hedge this exposure on an after-tax basis. The fair value for derivatives used to manage the exposure is shown in the table below.

Asset/(Liability)

        2006   2005
       
December 31 (millions of dollars)   Accounting Treatment   Fair Value   Notional or Principal Amount   Fair Value   Notional or
Principal
Amount
US dollar cross-currency swaps                    
  (maturing 2007 to 2013)   Hedge   58   U.S. 400   119   U.S. 450
US dollar forward foreign exchange contracts                    
  (maturing 2007)   Hedge   (7 ) U.S. 390   5   U.S. 525
US dollar options                    
  (maturing 2007)   Hedge   (6 ) U.S. 500   –   U.S. 60

Reconciliation of Foreign Exchange Adjustment

December 31 (millions of dollars)   2006   2005  
 
Balance at January 1 (loss)   (90 ) (71 )
Translation gains/(losses) on foreign currency denominated net assets(1)   8   (21 )
(Losses)/gains on derivatives   (9 ) 23  
Income taxes   1   (21 )
 
Balance at December 31 (loss)   (90 ) (90 )
 
(1)
The amount for 2006 includes gains of $6 million (2005 – $80 million) related to foreign currency denominated debt designated as a hedge.

Foreign Exchange and Interest Rate Management Activity

The Company manages the foreign exchange and interest rate risks related to its U.S. dollar denominated debt and transactions and interest rate exposures of the Canadian Mainline, the Alberta System and the BC 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.

56 MANAGEMENT'S DISCUSSION AND ANALYSIS

Asset/(Liability)

        2006   2005
       
December 31
(millions of dollars) 		  Accounting Treatment   Fair Value   Notional or Principal Amount   Fair Value   Notional or
Principal
Amount
Foreign Exchange                    
Cross-currency and interest-rate swaps                    
  (maturing 2013)   Hedge   (32 ) 136/U.S. 100   –    
  (maturing 2010 to 2012)   Non-hedge   (52 ) 227/U.S. 157   (86 ) 363/U.S. 257
       
     
   
        (84 )     (86 )  
       
     
   

Interest Rate
 
 
 
 
 
 
 
 
 
 
Interest rate swaps                    
Canadian dollars                    
  (maturing 2007 to 2008)   Hedge   2   100   4   100
  (maturing 2007 to 2009)   Non-hedge   5   300   7   374
       
     
   
        7       11    
US dollars                    
  (maturing 2007 to 2009)   Non-hedge   4   U.S. 100   5   U.S. 100

MANAGEMENT'S DISCUSSION AND ANALYSIS 57

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)

        2006   2005
       
December 31
(millions of dollars) 		  Accounting Treatment   Fair Value   Notional or Principal Amount   Fair Value   Notional or Principal Amount
Foreign Exchange                    
Options (maturing 2007)   Non-hedge   –   U.S. 95   1   U.S. 195
Forward foreign exchange contracts                    
    Hedge   –   –   2   U.S. 29
  (maturing 2007)   Non-hedge   (3 ) U.S. 250   1   U.S. 208
       
     
   
        (3 )     4    
       
     
   

Interest Rate
 
 
 
 
 
 
 
 
 
 
Options (maturing 2007)   Non-hedge   –   U.S. 50   –   –
Interest rate swaps                    
Canadian dollar                    
  (maturing 2007 to 2011)   Hedge   –   150   1   100
  (maturing 2009 to 2011)   Non-hedge   –   164   1   423
       
     
   
        –       2    
       
     
   
US dollar                    
  (maturing 2011 to 2017)   Hedge   (2 ) U.S. 350   –   U.S. 50
  (maturing 2007 to 2016)   Non-hedge   9   U.S. 450   18   U.S. 550
       
     
   
        7       18    
       
     
   

For the year ended December 31, 2006, the Company had net losses of $1 million (2005 – net gains of $10 million; 2004 – net gains of $5 million) associated with interest rate swaps, which included a $6-million loss (2005 – $5-million loss; 2004 – $7-million gain) relating to a change in mark-to-market positions on non-hedges. The net losses are included in Financial Charges on the Consolidated Income Statement.

Foreign exchange gains included in Other Expenses/(Income) for the year ended December 31, 2006 are $4 million (2005 – $19 million; 2004 – $6 million).

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, 2006 and 2005 was nil.

58 MANAGEMENT'S DISCUSSION AND ANALYSIS

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 value and notional volumes of contracts for differences and the swap, future, option and heat rate contracts are shown in the tables below.

Energy

Asset/(Liability)

        2006   2005  
       
 
December 31 (millions of dollars)   Accounting Treatment   Fair Value   Fair Value  
 
Power – swaps and contracts for differences              
  (maturing 2007 to 2011)   Hedge   (179 ) (130 )
  (maturing 2007 to 2010)   Non-hedge   (7 ) 13  
Gas – swaps, futures and options              
  (maturing 2007 to 2016)   Hedge   (66 ) 17  
  (maturing 2007 to 2008)   Non-hedge   30   (11 )
Heat rate contracts   Non-hedge   –   –  

Notional Volumes

        Power (GWh)   Gas (Bcf)
       
December 31, 2006   Accounting Treatment   Purchases   Sales   Purchases   Sales
Power – swaps and contracts for differences                    
  (maturing 2007 to 2011)   Hedge   6,654   12,349   –   –
  (maturing 2007 to 2010)   Non-hedge   1,402   964   –   –
Gas – swaps, futures and options                    
  (maturing 2007 to 2016)   Hedge   –   –   77   59
  (maturing 2007 to 2008)   Non-hedge   –   –   11   15
Heat rate contracts   Non-hedge   –   9   –   –
 
December 31, 2005                    
Power – swaps and contracts for differences   Hedge   2,566   7,780   –   –
    Non-hedge   1,332   456   –   –
Gas – swaps, futures and options   Hedge   –   –   91   69
    Non-hedge   –   –   15   18
Heat rate contracts   Non-hedge   –   35   –   –

During 2006, the Company recorded net gains of $41 million (2005 – net losses of $12 million; 2004 – net losses of $1 million) as a result of the non-hedge gas swaps, futures and options. These net gains were partially offset by losses from the non-hedge power swaps and contracts of $19 million (2005 – net gains of $16 million; 2004 – net losses of $3 million). The net impact of gains and losses on non-hedge derivatives for power, gas, and heat rate contracts were net gains of $22 million (2005 – net gains of $4 million; 2004 – net losses of $4 million) for the year included in Revenue.

MANAGEMENT'S DISCUSSION AND ANALYSIS 59

At December 31, 2006, the Company had unrealized net losses of $222 million (2005 – net losses of $111 million) as a result of its energy swaps, futures, options and contracts that had not settled by year end. There were unrealized losses from unsettled energy derivatives of $144 million (2005 – $107 million) included in Accounts Payable and $158 million (2005 – $105 million) included in Deferred Amounts. These losses were partially offset by unrealized gains of $39 million (2005 – $44 million) included in Other Assets and $41 million (2005 – $57 million) included in Other Current Assets.

Certain of the Company's joint ventures use power derivatives to manage energy price risk exposures. The Company's proportionate share of the fair value of these outstanding power sales derivatives at December 31, 2006 was $55 million (2005 – $(38) million) and related to contracts which cover the period 2007 to 2010. The Company's proportionate share of the notional sales volumes associated with this exposure at December 31, 2006 was 4,500 GWh (2005 – 2,058 GWh).

RISKS AND RISK MANAGEMENT

Risk Management Overview

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

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

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

TCPL manages market, financial and counterparty risks and related exposures in accordance with the Company's market risk, interest rate and foreign exchange risk and counterparty risk policies. The Company's primary market and financial risks result from volatility in commodity prices, interest rates and foreign currency exchange rates.

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

Market Risk Management

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

60 MANAGEMENT'S DISCUSSION AND ANALYSIS

Financial Risk Management

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

Counterparty Risk Management

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

The Company's counterparty risk management practices and positions are further described in Note 15 to the consolidated financial statements.

Development Projects and Acquisitions

TCPL continues to focus on growing its Pipelines and Energy operations through greenfield projects and acquisitions. TCPL defers costs incurred on certain of its development projects during the period prior to construction when the project meets specific criteria including an expectation that the project will proceed to ultimate completion. If an individual project does not proceed, the related deferred costs would be expensed at that time. With respect to TCPL's acquisition of existing assets and operations, there is a risk that certain commercial opportunities and operational synergies may not materialize as originally expected.

Foreign Exchange

A portion of TCPL's earnings from its Pipelines and Energy operations in the U.S. are generated in U.S. dollars and are subject to currency fluctuations. The performance of the Canadian dollar relative to the U.S. dollar could either positively or negatively impact TCPL's net earnings, although much of this foreign exchange impact is offset by exposures in certain of TCPL's businesses as well as through the Company's hedging activities. With the acquisition of ANR and a greater ownership interest in PipeLines LP, TCPL expects to have a greater exposure to U.S. dollar fluctuations.

Risks and Risk Management Related to Environmental Regulations

Climate change remains a serious issue for TCPL. The change of government in Canada in early 2006 resulted in a shift of focus from meeting greenhouse gas reduction targets to a broader emphasis on clean air as well as greenhouse gas emissions. The Government of Canada released the Clean Air Act on October 19, 2006. At this time however, the policy framework for the new regulations has not been released by the federal government and detailed sectoral targets and timeframes as well as compliance options have not been set. At a provincial level, the Québec government has passed legislation for a hydrocarbon royalty on industrial greenhouse gas emitters. The details as to how the royalty will be applied have not yet been determined but it is expected these details will be set in the coming year. In Alberta, the government has indicated it will continue with its own plan for implementing regulations to manage greenhouse gas emissions. It is yet to be determined how this effort will tie into a federal program.

In the U.S., state level initiatives are under way to limit greenhouse gas emissions, particularly in the northeastern U.S. and California. Details have not been finalized and the impact to TCPL's U.S.-based assets is uncertain.

Despite this uncertainty, TCPL continues with its programs to manage greenhouse gas emissions from its assets, and to evaluate new processes and technologies that result in improved efficiencies and lower greenhouse gas emissions rates. In addition, TCPL remains involved in policy discussions in those jurisdictions where policy development is under way and where the Company has operations.

MANAGEMENT'S DISCUSSION AND ANALYSIS 61


CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in reports filed with, or submitted to, securities regulatory authorities is recorded, processed, summarized and reported within the time periods specified under Canadian and U.S. securities laws. The information is accumulated and communicated to management, including the President and Chief Executive Officer and the Chief Financial Officer, to allow timely decisions regarding required disclosure.

As of December 31, 2006, an evaluation was carried out, under the supervision of and with the participation of management, including the President and Chief Executive Officer and Chief Financial Officer, of the effectiveness of TCPL's disclosure controls and procedures as defined under the rules adopted by the Canadian securities regulatory authorities and by the U.S. Securities and Exchange Commission (SEC). Based on that evaluation, the President and Chief Executive Officer and Chief Financial Officer concluded that the design and operation of TCPL's disclosure controls and procedures were effective as at December 31, 2006.

Management's Annual Report on Internal Control over Financial Reporting

Internal control over financial reporting is a process designed by, or under the supervision of, senior management, and effected by the Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and preparation of consolidated financial statements for external purposes in accordance with Canadian GAAP, including a reconciliation to U.S. GAAP.

Management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting, no matter how well designed, has inherent limitations and can only provide reasonable assurance with respect to the preparation and fair presentation of published financial statements. Under the supervision of, and with the participation of, management, including the President and Chief Executive Officer and Chief Financial Officer, management conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, according to these criteria, management concluded that internal control over financial reporting is effective as of December 31, 2006 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes.

During the year ended December 31, 2006, there has been no change in TCPL's internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, TCPL's internal control over financial reporting.

CEO and CFO Certifications

With respect to the year ending December 31, 2006, TCPL's President and Chief Executive Officer has provided the New York Stock Exchange with the annual CEO certification regarding TCPL's compliance with the New York Stock Exchange's corporate governance listing standards applicable to foreign issuers. In addition, TCPL's President and Chief Executive Officer and Chief Financial Officer have filed with the SEC and the Canadian securities regulators certifications regarding the quality of TCPL's public disclosures relating to its fiscal 2006 reports filed with the SEC and the Canadian securities regulators.

Compliance Expenditures

The total cost incurred by TCPL comply with the requirements of the SEC and Canadian securities regulatory authorities arising out of the Sarbanes-Oxley Act of 2002 for the period January 1, 2002 to December 31, 2006, was estimated to be $14 million, including third party charges of $4 million.

SIGNIFICANT ACCOUNTING POLICIES AND CRITICAL ACCOUNTING ESTIMATES

Since determining the value 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.

62 MANAGEMENT'S DISCUSSION AND ANALYSIS


Regulated Accounting

The Company accounts for the impacts of rate regulation in accordance with GAAP as outlined in Notes 1 and 11 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 as detailed in Note 11 to the consolidated financial statements.

Derivative Accounting

The Company enters into the following financial instruments to manage its risk exposure:

Derivatives are recorded at their fair value at each balance sheet date. Derivatives and other instruments must be designated and be effective to qualify for hedge accounting. For cash flow and fair value hedges, gains or losses relating to derivatives are deferred and recognized in the same period and in the same financial statement category as the corresponding hedged transactions. Unrealized long-term gains and losses are included in Other Assets and Deferred Amounts, respectively. Unrealized current gains and losses are included in Other Current Assets and Accounts Payable, respectively. For hedges of net investments in self-sustaining foreign operations, exchange gains or losses on derivatives, after tax, and designated foreign currency denominated debt are offset against the exchange losses or gains arising on the translation of the financial statements of the foreign operations included in the foreign exchange adjustment account in Shareholders' Equity.

Assessment of effectiveness for those derivatives classified as hedges occurs at inception and on an ongoing basis. The determination of whether a derivative contract qualifies as a cash flow hedge includes an analysis of historical market price information to assess whether the derivatives are expected to be highly effective in achieving offsetting cash flows attributable to the hedged risk. In the event that a derivative does not meet the designation or effectiveness criteria, realized and unrealized gains or losses are recognized in income each period in the same financial category as the underlying transaction giving rise to the exposure being economically hedged. If an anticipated transaction is hedged and the transaction is no longer probable to occur, the related deferred gains or losses are recognized in income in the current period.

The recognition of gains and losses on derivatives for the Canadian Mainline, Alberta System, Foothills and the BC System exposures is determined through the regulatory process. Certain of the realized gains and losses on these derivatives are shared with shippers on predetermined terms. The gains and losses on derivatives accounted for as part of rate-regulated accounting that do not meet the criteria for hedge accounting are deferred.

The fair value for derivative contracts is determined based on the nature of the transactions and the market in which transactions are executed. Assumptions and judgements about counterparty performance and credit considerations are incorporated in the determination of fair value.

The Company estimates the fair value of derivative contracts by using readily available price quotes in similar markets and other market analyses. The number of transactions executed without quoted market prices is limited. The fair value of all derivative contracts is continually subject to change as the underlying commodity market changes and TCPL's

MANAGEMENT'S DISCUSSION AND ANALYSIS 63


assumptions and judgments change. The fair value of foreign exchange and interest rate derivatives has been calculated using year end market rates. The fair value of power, natural gas and heat rate derivatives is calculated using estimated forward prices for the relevant period.

The chart below shows the effect that a one dollar change in the price of power (per MWh) or gas (per GJ) would have on the calculation of the fair values of derivatives as recorded on the balance sheet.

    Increase $1   Decrease $1
   
(millions of dollars)   Effect on fair value   Effect on fair value
Western Power Operations – power   -8   +8
Eastern Power Operations – power   +2   -3
Eastern Power Operations – gas   +19   -19

Depreciation and Amortization Expense

TCPL's plant, property and equipment are depreciated on a straight-line basis over their estimated useful lives. Pipeline and compression equipment are depreciated at annual rates from two to six per cent. Major power generation and natural gas storage plant, equipment and structures in the Energy business are depreciated at average annual rates ranging from two to ten per cent. Nuclear power generation assets under capital lease are amortized over the shorter of their useful life or the remaining terms of their lease. Other equipment is depreciated at various rates.

Depreciation expense for the year ended December 31, 2006 was $1,059 million and primarily impacts the Pipelines and Energy segments of the Company. In Pipelines, depreciation rates are approved by the regulators, where applicable, and depreciation expense is 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 Pipelines segment would, if recovery through rates is permitted by the regulators, have no material impact on TCPL's net income but would directly impact funds generated from operations.

ACCOUNTING CHANGES

Non-Monetary Transactions

Effective for non-monetary transactions initiated in periods beginning on or after January 1, 2006, the new Handbook Section 3831 "Non-Monetary Transactions" requires all non-monetary transactions to be measured at fair value, subject to certain exceptions. Commercial substance replaces culmination of the earnings process as the test for fair value measurement and is a function of the cash flows expected from the exchanged assets. Adopting the provisions of this standard in 2006 did not have an impact on the Company's consolidated financial statements.

Financial Instruments – Recognition and Measurement

Effective for interim and annual financial statements beginning on or after October 1, 2006, the new Handbook Section 3855 "Financial Instruments – Recognition and Measurement" prescribes that all financial instruments within the scope of this standard, including derivatives, be included on a company's balance sheet. Contracts that can be settled by receipt or delivery of a commodity will also be included in the scope of the section. These financial instruments must be measured, either at their fair value or, in limited circumstances when fair value may not be considered the most relevant measurement method, at cost or amortized cost. It also specifies when gains and losses as a result of changes in fair value are to be recognized in the income statement. This new Handbook section will be adopted by the Company as of January 1, 2007 on a prospective basis. TCPL does not expect this new requirement to have a significant impact on the Company's consolidated financial statements.

64 MANAGEMENT'S DISCUSSION AND ANALYSIS

Hedges

Effective for interim and annual financial statements for fiscal years beginning on or after October 1, 2006, the new Handbook Section 3865 "Hedges" specifies the circumstances under which hedge accounting is permissible, how hedge accounting may be performed, and where the impacts should be recorded. The provisions of this standard introduce three specific types of hedging relationships: fair value hedges, cash flow hedges and hedges of a net investment in self-sustaining foreign operations. This new Handbook section will be adopted by the Company as of January 1, 2007 on a prospective basis. TCPL does not expect this new requirement to have a significant impact on the Company's consolidated financial statements.

Comprehensive Income

Effective for interim and annual financial statements for fiscal years beginning on or after October 1, 2006, the new Handbook Section 1530 "Comprehensive Income" requires that an enterprise present comprehensive income and its components in a separate financial statement that is displayed with the same prominence as other financial statements. This Section introduces a new requirement to present certain gains and losses temporarily outside net income. This Handbook section will be adopted by the Company as of January 1, 2007 on a prospective basis. Beginning first quarter 2007, TCPL's financial statements will include a Statement of Comprehensive Income and a Statement of Accumulated Comprehensive Income.

SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA(1)

 
   2006
   
(millions of dollars except per share amounts)   Fourth   Third   Second   First
Revenues   2,091   1,850   1,685   1,894
Net Income Applicable to Common Shares                
  Continuing operations   268   293   244   244
  Discontinued operations   –   –   –   28
    268   293   244   272
Per Common Share Data                
Net income – Basic and Diluted                
  Continuing operations   $0.56   $0.60   $0.51   $0.50
  Discontinued operations   –   –   –   0.06
    $0.56   $0.60   $0.51   $0.56
 
 
   2005
   
(millions of dollars except per share amounts)   Fourth   Third   Second   First
Revenues   1,771   1,494   1,449   1,410
Net Income                
  Continuing operations   349   428   199   232
  Discontinued operations   –   –   –   –
    349   428   199   232
Per Common Share Data                
Net income – Basic and Diluted                
  Continuing operations   $0.72   $0.89   $0.41   $0.48
  Discontinued operations   –   –   –   –
    $0.72   $0.89   $0.41   $0.48
(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 Notes 1 and 22 of TCPL's 2006 audited consolidated financial statements included in TCPL's 2006 Annual Report.

MANAGEMENT'S DISCUSSION AND ANALYSIS 65

Factors Impacting Quarterly Financial Information

In Pipelines, 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 net earnings during any particular fiscal year remain relatively stable with fluctuations arising as a result of adjustments being recorded due to regulatory decisions and negotiated settlements with shippers, seasonal fluctuations in short-term throughput volumes on U.S. pipelines and items outside of the normal course of operations.

In Energy, which consists primarily of the Company's investments in electrical power generation plants and natural gas storage facilities, 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 2006 and 2005 quarterly net earnings are as follows.

66 MANAGEMENT'S DISCUSSION AND ANALYSIS

FOURTH QUARTER 2006 HIGHLIGHTS

SEGMENT RESULTS-AT-A-GLANCE
Three months ended December 31

(millions of dollars)   2006   2005  
 
Pipelines   126   155  
 

Energy
 
 
 
 
 
  Excluding gains   132   87  
  Gain on sale of Paiton Energy   –   115  
 
    132   202  
 
Corporate   10   (8 )
 
Net Income Applicable to Common Shares(1)   268   349  
 
  (1)Net Income Applicable to Common Shares        
    Excluding gain   268   234
    Gain on sale of Paiton Energy   –   115
        268   349

Net income for fourth quarter 2006 of $268 million decreased by $81 million compared to $349 million for fourth quarter 2005. This decrease was primarily due to an after-tax gain of $115 million from the sale of Paiton Energy in fourth quarter 2005.

Excluding the $115-million gain related to the sale of Paiton Energy, net income for fourth quarter 2006 increased $34 million compared to fourth quarter 2005. This was primarily due to increases of $45 million and $18 million in net earnings from Energy and Corporate, respectively, partially offset by a decrease of $29 million in net earnings from the Pipelines business.

For fourth quarter 2006, Pipeline's net income decreased $29 million compared to fourth quarter 2005 due to a $22-million reduction in net earnings from Wholly Owned Pipelines and a $7-million decrease in net earnings from the Other Pipelines businesses. Wholly Owned Pipelines' net earnings decreased primarily due to a lower ROE and lower average investment bases in the Canadian Mainline and the Alberta System. Net earnings from GTN decreased due to increased operating costs and lower transportation revenues. Net earnings for TCPL's Other Pipelines decreased primarily due to higher project development and support costs and the impact of a weaker U.S. dollar.

Excluding the gain of $115 million in 2005, Energy's net earnings increased $45 million in fourth quarter 2006, compared to fourth quarter 2005, due to higher operating income from Western Power Operations, Natural Gas Storage and Bruce Power. Partially offsetting these increases were lower operating income from Eastern Power Operations and higher general, administrative and support costs.

Bruce Power's contribution to operating income increased $6 million in fourth quarter 2006, compared to fourth quarter 2005, primarily due to an increased ownership interest in the Bruce A facilities and the positive impact of higher generation volumes, partially offset by lower overall realized prices and higher operating expenses.

Western Power Operations' operating income was $76 million higher in fourth quarter 2006, compared to fourth quarter 2005, primarily due to incremental earnings from the December 31, 2005 acquisition of the 756 MW Sheerness PPA and increased margins from a combination of higher overall realized power prices and higher market heat rates on sales of uncontracted power volumes.

MANAGEMENT'S DISCUSSION AND ANALYSIS 67


Eastern Power Operations' operating income was $13 million lower in fourth quarter 2006, compared to fourth quarter 2005, primarily due to record hurricane activity in the Gulf of Mexico in 2005 which caused a significant increase in certain commodity prices and increased hydro generation volumes. As a result, higher profits were earned in 2005 from increased generation volumes as a result of unusually high water flows through the TC Hydro facilities, increased margins on the natural gas purchased and resold under the OSP gas supply contracts and higher prices realized on power sold into the spot market. The quarter-over-quarter decrease was partially offset by incremental income earned in 2006 from the startup of the 550 MW Bécancour cogeneration plant in September 2006 and the first wind farm of the Cartier Wind project in November 2006.

Natural Gas Storage operating income increased $13 million in fourth quarter 2006, compared to fourth quarter 2005, primarily due to higher contributions from CrossAlta as a result of increased storage capacity and higher natural gas storage spreads.

General, administrative, support costs and other of the Energy business increased $8 million in fourth quarter 2006, compared to fourth quarter 2005, primarily due to higher business development costs associated with growing the Energy business.

Corporate's net earnings increased $18 million to $10 million in fourth quarter 2006 primarily due to income tax refunds and related interest of approximately $12 million and other positive income tax adjustments.

SHARE INFORMATION

At February 22, 2007, TCPL had 483,344,109 issued and outstanding common shares and there were no outstanding options to purchase common shares.

OTHER INFORMATION

Additional information relating to TCPL, including the Company's Annual Information Form and other continuous disclosure documents, is available on SEDAR at www.sedar.com under TransCanada PipeLines Limited.

Other selected consolidated financial information for the years ended December 31, 2006, 2005, 2004, 2003, 2002, 2001 and 2000 is found under the heading "Seven-Year Financial Highlights" on pages 111 and 112 of this Annual Report.

68 MANAGEMENT'S DISCUSSION AND ANALYSIS

GLOSSARY OF TERMS

ACES   Accelerated Clean Energy Supply
ANR   The American Natural Resources Company and the ANR Storage Company, collectively
APG   Aboriginal Pipeline Group
B.C.   British Columbia
Bcf   Billion cubic feet
Bcf/d   Billion cubic feet per day
BPC   BPC Generation Infrastructure Trust
Broadwater   Broadwater Energy project
Bruce A   Bruce Power A L.P.
Bruce B   Bruce Power L.P.
Bruce Power   The collective investments in Bruce A and Bruce B
Cacouna   Cacouna Energy project
Calpine   Calpine Corporation and certain of its subsidiaries
Cameco   Cameco Corporation
CAPLA   Canadian Alliance of Pipeline Landowners' Associations
CAPP   Canadian Association of Petroleum Producers
CPPL   ConocoPhillips Pipe Line Company
CrossAlta   CrossAlta Gas Storage & Services Ltd.
DBRS   Dominion Bond Rating Service Limited
DRP   Dividend Reinvestment and Share Purchase Plan
EPCOR   EPCOR Utilities Inc.
EUB   Alberta Energy and Utilities Board
FCM   Forward Capacity Market
FERC   Federal Energy Regulatory Commission
Foothills   Foothills Pipe Lines Ltd.
FT   Firm transportation
GAAP   Generally accepted accounting principles
Gas Pacifico   Gasoducto del Pacifico S.A.
GJ   Gigajoule
GRA   General Rate Application
Great Lakes   Great Lakes Gas Transmission Limited Partnership
GTA   Greater Toronto Area
GTN   Gas Transmission Northwest System and the North Baja system, collectively
GTNC   Gas Transmission Northwest Corporation
GWh   Gigawatt hours
INNERGY   INNERGY Holdings S.A.
Iroquois   Iroquois Gas Transmission System, L.P.
JRP   Joint Review Panel
Keystone   TransCanada Keystone Pipeline GP Ltd.
km   Kilometres
LNG   Liquefied natural gas
MD&A   Management's Discussion and Analysis
MGP   Mackenzie Gas Pipeline
Millennium   Millennium Pipeline project
Mirant   Mirant Corporation and certain of its subsidiaries
mmcf/d   Million cubic feet per day
Moody's   Moody's Investors Service
MW   Megawatt
MWh   Megawatt hour
NBV   Net book value
NEB   National Energy Board
Net earnings   Net income from continuing operations
NEPOOL   New England Power Pool
NGLs   Natural gas liquids
Northern Border   Northern Border Pipeline Company
NPA   Northern Pipeline Act of Canada
OM&A   Operating, maintenance and administration
OPA   Ontario Power Authority
OSP   Ocean State Power
Paiton Energy   P.T. Paiton Energy Company
PG&E   Pacific Gas & Electric Company
PipeLines LP   TC PipeLines, LP
Portland   Portland Natural Gas Transmission System
Portlands Energy   Portlands Energy Centre L.P.
Power LP   TransCanada Power, L.P.
PPA   Power purchase arrangement
ROE   Rate of return on common equity
S&P   Standard & Poor's
SEC   U.S. Securities and Exchange Commission
Shell   Shell US Gas & Power LLC
TBO   Transportation by Others
TCPL or the Company   TransCanada PipeLines Limited
TCPM   TransCanada Power Marketing Ltd.
TQM   Trans Québec & Maritimes System
TransCanada   TransCanada Corporation
TransGas   TransGas de Occidente S.A.
Tuscarora   Tuscarora Gas Transmission Company
U.S.   United States
USGen   USGen New England, Inc.
Ventures LP   TransCanada Pipeline Ventures Limited Partnership
WCSB   Western Canada Sedimentary Basin

MANAGEMENT'S DISCUSSION AND ANALYSIS 69






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 2006 to 2005 and should be read in conjunction with the consolidated financial statements and accompanying notes. In addition, significant changes between 2005 and 2004 are highlighted.

Management has designed 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.

Under the supervision and with the participation of the President and Chief Executive Officer and Chief Financial Officer, Management conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment according to these criteria, Management concluded that internal control over financial reporting is effective as of December 31, 2006 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes.

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 in accordance with the terms of the charter of the Audit Committee as set out in the Annual Information Form. 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 outlines the scope of their examination and their opinion on the consolidated financial statements.
 
 
    SIG   SIG
    Harold N. Kvisle   Gregory A. Lohnes
    President and
Chief Executive Officer		   Executive Vice-President and
Chief Financial Officer

 
 
February 22, 2007
 
 

70 TRANSCANADA PIPELINES LIMITED





Auditors'
Report

 

To the Shareholders of TransCanada PipeLines Limited

We have audited the consolidated balance sheets of TransCanada PipeLines Limited as at December 31, 2006 and 2005 and the consolidated statements of income, retained earnings and cash flows for each of the years in the three-year period ended December 31, 2006. 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. With respect to the consolidated financial statements for the years ended December 31, 2006 and 2005, we also conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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, 2006 and 2005 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2006 in accordance with Canadian generally accepted accounting principles.
 
 

 
 
GRAPHIC
    Chartered Accountants
Calgary, Canada

 
 
February 22, 2007

CONSOLIDATED FINANCIAL STATEMENTS 71

TRANSCANADA PIPELINES LIMITED
CONSOLIDATED INCOME

Year ended December 31
(millions of dollars except per share amounts) 		  2006   2005   2004    
Revenues   7,520   6,124   5,497    

Operating Expenses
 
 
 
 
 
 
 
 
Plant operating costs and other   2,411   1,825   1,615    
Commodity purchases resold   1,707   1,232   940    
Depreciation   1,059   1,017   948    
    5,177   4,074   3,503    
    2,343   2,050   1,994    

Other Expenses/(Income)
 
 
 
 
 
 
 
 
Financial charges (Note 8)   828   837   860    
Financial charges of joint ventures (Note 9)   92   66   63    
Income from equity investments (Note 6)   (33 ) (247 ) (213 )  
Interest income and other   (123 ) (63 ) (59 )  
Gains on sale of assets (Note 7)   (23 ) (445 ) (204 )  
    741   148   447    
Income from Continuing Operations before Income Taxes and Non-Controlling Interests   1,602   1,902   1,547    

Income Taxes (Note 17)
 
 
 
 
 
 
 
 
  Current   300   550   414    
  Future   175   60   77    
    475   610   491    
Non-Controlling Interests (Note 13)   56   62   56    
Net Income from Continuing Operations   1,071   1,230   1,000    
Net Income from Discontinued Operations (Note 23)   28   –   52    
Net Income   1,099   1,230   1,052    
Preferred Share Dividends   22   22   22    
Net Income Applicable to Common Shares   1,077   1,208   1,030    

Net Income Applicable to Common Shares
 
 
 
 
 
 
 
 
  Continuing operations   1,049   1,208   978    
  Discontinued operations   28   –   52    
    1,077   1,208   1,030    

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

72 CONSOLIDATED FINANCIAL STATEMENTS

TRANSCANADA PIPELINES LIMITED
CONSOLIDATED CASH FLOWS

Year ended December 31 (millions of dollars)   2006   2005   2004    
Cash Generated from Operations                
Net income   1,099   1,230   1,052    
Depreciation   1,059   1,017   948    
Gains on sale of assets, net of current tax (Note 7)   (11 ) (318 ) (204 )  
Income from equity investments in excess of distributions received (Note 6)   (9 ) (71 ) (113 )  
Future income taxes (Note 17)   175   60   77    
Non-controlling interests (Note 13)   56   62   56    
Funding of employee future benefits in excess of expense (Note 20)   (31 ) (9 ) (29 )  
Other   36   (21 ) (86 )  
    2,374   1,950   1,701    
(Increase)/decrease in operating working capital (Note 21)   (300 ) (48 ) 28    
Net cash provided by operations   2,074   1,902   1,729    

Investing Activities
 
 
 
 
 
 
 
 
Capital expenditures   (1,572 ) (754 ) (530 )  
Acquisitions, net of cash acquired (Note 7)   (470 ) (1,317 ) (1,516 )  
Disposition of assets, net of current tax (Note 7)   23   671   410    
Deferred amounts and other   (95 ) 65   (12 )  
Net cash used in investing activities   (2,114 ) (1,335 ) (1,648 )  

Financing Activities
 
 
 
 
 
 
 
 
Dividends on common and preferred shares   (639 ) (608 ) (574 )  
Distributions paid to non-controlling interests   (50 ) (52 ) (65 )  
Advances from/(repayments to) parent   40   (36 ) 35    
Notes payable (repaid)/issued, net   (495 ) 416   179    
Long-term debt issued   2,107   799   1,090    
Repayment of long-term debt   (729 ) (1,113 ) (1,005 )  
Long-term debt of joint ventures issued   56   38   217    
Repayment of long-term debt of joint ventures   (70 ) (80 ) (112 )  
Common shares issued (Note 15)   –   80   –    
Partnership units of joint ventures issued   –   –   88    
Net cash provided by/(used in) financing activities   220   (556 ) (147 )  

Effect of Foreign Exchange Rate Changes on Cash and Short-Term Investments
 
9
 
11
 
(87
)
 
Increase/(Decrease) in Cash and Short-Term Investments   189   22   (153 )  

Cash and Short-Term Investments
 
 
 
 
 
 
 
 
Beginning of year   212   190   343    

Cash and Short-Term Investments
 
 
 
 
 
 
 
 
End of year   401   212   190    

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

CONSOLIDATED FINANCIAL STATEMENTS 73

TRANSCANADA PIPELINES LIMITED
CONSOLIDATED BALANCE SHEET

December 31
(millions of dollars) 		  2006   2005    
ASSETS            

Current Assets
 
 
 
 
 
 
Cash and short-term investments   401   212    
Accounts receivable   1,001   796    
Inventories   392   281    
Other   297   277    
    2,091   1,566    
Long-Term Investments (Note 6)   71   400    
Plant, Property and Equipment (Note 3)   21,487   20,038    
Goodwill   281   57    
Other Assets (Note 4)   1,978   2,052    
    25,908   24,113    

LIABILITIES AND SHAREHOLDERS' EQUITY
 
 
 
 
 
 

Current Liabilities
 
 
 
 
 
 
Notes payable (Note 18)   467   962    
Accounts payable   1,582   1,536    
Accrued interest   264   222    
Current portion of long-term debt (Note 8)   616   393    
Current portion of long-term debt of joint ventures (Note 9)   142   41    
    3,071   3,154    
Deferred Amounts (Note 10)   1,029   1,196    
Future Income Taxes (Note 17)   876   703    
Long-Term Debt (Note 8)   10,887   9,640    
Long-Term Debt of Joint Ventures (Note 9)   1,136   937    
Preferred Securities (Note 12)   536   536    
    17,535   16,166    
Non-Controlling Interests (Note 13)   366   394    

Shareholders' Equity
 
 
 
 
 
 
Preferred shares (Note 14)   389   389    
Common shares (Note 15)   4,712   4,712    
Contributed surplus   277   275    
Retained earnings   2,719   2,267    
Foreign exchange adjustment (Note 16)   (90 ) (90 )  
    8,007   7,553    

Commitments, Contingencies and Guarantees (Note 22)
 
 
 
 
 
 
Subsequent Events (Note 24)            
    25,908   24,113    

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

On behalf of the Board:

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

74 CONSOLIDATED FINANCIAL STATEMENTS

TRANSCANADA PIPELINES LIMITED
CONSOLIDATED RETAINED EARNINGS

Year ended December 31
(millions of dollars) 		  2006   2005   2004    
Balance at beginning of year   2,267   1,653   1,185    
Net income   1,099   1,230   1,052    
Preferred share dividends   (22 ) (22 ) (22 )  
Common share dividends   (625 ) (594 ) (562 )  
    2,719   2,267   1,653    

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

CONSOLIDATED FINANCIAL STATEMENTS 75

TRANSCANADA PIPELINES LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

TransCanada PipeLines Limited (the Company or TCPL) is a leading North American energy company. TCPL operates in two business segments, Pipelines and Energy, each of which offers different products and services.

Pipelines

The Pipelines 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./United States border and to the Saskatchewan/U.S. border (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);

•
natural gas transmission systems in Alberta, owned by TransCanada Pipeline Ventures Limited Partnership (Ventures LP), that supply natural gas to the oil sands region of northern Alberta and to a petrochemical complex at Joffre, Alberta;

•
a natural gas transmission system in Mexico extending from Naranjos, Veracruz to Tamazunchale, San Luis Potosi (Tamazunchale);

•
a 61.7 per cent interest in Portland Natural Gas Transmission System (Portland), which owns a pipeline system that extends from a point near East Hereford, Québec and delivers natural gas to the northeastern U.S.; and

•
a 50 per cent interest in TQM Services Limited Partnership (TQM), which owns a pipeline system that connects with the Canadian Mainline and transports natural gas in Québec, from Montreal to Québec City, and to the Portland System.

Pipelines also holds the Company's investments in other natural gas pipelines primarily in North America. TCPL's other significant pipeline investments include:

•
a 50 per cent interest in Great Lakes Gas Transmission Limited Partnership (Great Lakes), which owns a natural gas pipeline system that connects to the Canadian Mainline and serves markets in Central Canada and Eastern and Midwestern U.S.; and

•
a 44.5 per cent interest in Iroquois Gas Transmission System, L.P. (Iroquois), which owns a natural gas pipeline system that connects with the Canadian Mainline near Waddington, New York and delivers to customers in the northeastern U.S.

In addition, Pipelines investigates and develops new natural gas and crude oil pipelines in North America.

TCPL is the general partner of and consolidates its 13.4 per cent (at December 31, 2006) interest in TC PipeLines LP (PipeLines LP), which holds the following investments:

•
a 50 per cent interest in Northern Border Pipeline Company (Northern Border), which owns a pipeline system that transports natural gas from a point near Monchy, Saskatchewan to the U.S. Midwest. TCPL expects to begin operating Northern Border in April 2007. TCPL's effective ownership in Northern Border is 6.7 per cent; and

•
owns or controls a 99 per cent interest in Tuscarora Gas Transmission Company (Tucarora), which owns a pipeline system that transports natural gas from Malin, Oregon to Wadsworth, Nevada. TCPL became the operator of Tuscarora in December 2006. TCPL's effectively owns or controls 14.3 per cent of Tuscarora, including one per cent owned directly by TCPL.

Energy

The Energy segment builds, owns and operates electrical power generation plants, and sells electricity. Energy also holds the Company's investments in other electrical power generation plants, natural gas storage facilities as well as the Company's interest in liquefied natural gas (LNG) regassification projects in North America. This business operates in Canada and the U.S. as follows:

TCPL owns and operates:

•
hydroelectric generation assets located in New Hampshire, Vermont and Massachusetts (TC Hydro);

•
a natural gas-fired, combined-cycle plant in Burrillville, Rhode Island (Ocean State Power);

•
natural gas-fired cogeneration plants in Alberta at Carseland, Redwater, Bear Creek and MacKay River;

•
a natural gas-fired cogeneration plant near Saint John, New Brunswick (Grandview);

76 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

•
a waste-heat fuelled power plant at the Cancarb facility in Medicine Hat, Alberta (Cancarb);

•
a natural gas-fired cogeneration plant near Trois-Rivières, Québec (Bécancour); and

•
a natural gas storage facility near Edson, Alberta (Edson).

TCPL owns but does not operate:

•
a 48.7 per cent partnership interest and a 31.6 per cent partnership interest in the nuclear power generation facilities of Bruce Power A L.P. (Bruce A) and Bruce Power L.P. (Bruce B), respectively (collectively Bruce Power), located near Lake Huron, Ontario;

•
a 60 per cent interest in CrossAlta Gas Storage & Services Ltd. (CrossAlta), which owns an underground natural gas storage facility near Crossfield, Alberta; and

•
a 62 per cent interest in one (Baie-des-Sables) of six wind farms in Gaspé, Québec (Cartier Wind).

TCPL has long-term power purchase arrangements (PPAs) in place for:

•
100 per cent of the production of the Sundance A power facilities and 50 per cent, through a partnership, of the production of the Sundance B power facilities near Wabamun, Alberta; and

•
100 per cent of the production of the Sheerness power facility near Hanna, Alberta.

TCPL has under construction:

•
phase two of the six-phase Cartier Wind project in Québec, owned 62 per cent by TCPL;

•
a combined-cycle natural gas cogeneration plant in downtown Toronto, Ontario, owned 50 per cent by TCPL (Portlands Energy); and

•
a natural gas-fired, combined-cycle power plant near Toronto, Ontario (Halton Hills).

NOTE 1    ACCOUNTING POLICIES

The consolidated financial statements of the Company have been prepared by Management in accordance with Canadian GAAP. 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

The consolidated financial statements include the accounts of TCPL and its subsidiaries as well as its proportionate share of the accounts of its joint ventures. TCPL uses the equity method of accounting for investments over which the Company is able to exercise significant influence.

Regulation

The Canadian Mainline, the BC System, Foothills and Trans Québec & Maritimes (TQM) 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). The Gas Transmission Northwest System, North Baja and the other natural gas pipelines in the U.S. are subject to the authority of the Federal Energy Regulatory Commission (FERC). These natural gas transmission operations are regulated with respect to the determination of revenues, tolls, construction and operations. 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. The impact of rate regulation on TCPL is provided in Note 11.

Revenue Recognition

Pipelines

In the Pipelines segment, revenues from the Canadian rate-regulated operations are recognized in accordance with decisions made by the NEB and EUB. Revenues from the U.S. rate-regulated operations are recorded in accordance with FERC rules and regulations. Revenues from non-regulated operations are recorded when products have been delivered or services have been performed.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 77

Energy

i)      Power

The majority of revenues from the Power business are derived from the sale of electricity from energy marketing activities and are recorded in the month of delivery. Revenues from the Power business are also derived from the sale of unutilized natural gas fuel and include the impact of energy derivative contracts, including financial swaps, futures contracts and options.

ii)     Natural Gas Storage

The majority of the revenues earned from natural gas storage are derived from the sale of storage services recognized in accordance with the term of the gas storage contracts. Revenues earned on the sale of gas held in inventory are recorded in the month of delivery. These revenues include the impact of energy derivative contracts, including financial swaps, futures contracts and options.

Dilution Gains

Dilution gains resulting from the sale of units by partnerships in which TCPL has an ownership interest are recognized immediately in net income.

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 consisting of natural gas in storage, uranium, materials and supplies, including spare parts, are carried at the lower of average cost or net realizable value.

Plant, Property and Equipment

Pipelines

Plant, property and equipment of the Pipelines 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 equipment 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.

Energy

Major power generation and natural gas storage plant, equipment and structures in the Energy business are recorded at cost and depreciated on a straight-line basis over estimated service lives at average annual rates ranging from two to ten per cent. Nuclear power generation assets under capital lease are initially recorded at the present value of minimum lease payments at the inception of the lease and amortized on a straight-line basis over the shorter of their useful life or remaining lease term. Other equipment is depreciated at various rates. The cost of major overhauls of equipment is capitalized and depreciated over the estimated service lives. Interest is capitalized on plants under construction.

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.

Acquisitions and Goodwill

The Company accounts for business acquisitions using the purchase method of accounting and, accordingly, the assets and liabilities of the acquired entities are recorded at their estimated fair values at the date of acquisition. The excess of the purchase price over the fair value of net assets acquired is attributed to goodwill. Goodwill is not amortized for accounting purposes but is amortized for tax purposes. Goodwill is re-evaluated on an annual basis for impairment. Currently, all goodwill relates to Pipelines' operations.

Power Purchase Arrangements

PPAs are long-term contracts for the purchase or sale of power on a predetermined basis. The initial payments for PPAs acquired are deferred and amortized over the terms of the contracts, which range from ten to 19 years. Certain PPAs under which TCPL sells power are accounted for as operating leases and, accordingly, the related plant, property and equipment are accounted for as assets under operating leases.

78 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 which the Company does not intend to repatriate in the foreseeable future.

Foreign Currency Translation

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.

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 and Hedging Activities

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.

Derivatives are recorded at their fair value at each balance sheet date. Derivatives and other instruments must be designated and be effective to qualify for hedge accounting. For cash flow and fair value hedges, gains or losses relating to derivatives are deferred and recognized in the same period and in the same financial statement category as the corresponding hedged transactions. For hedges of net investments in self-sustaining foreign operations, exchange gains or losses on derivatives, after tax, and designated foreign currency denominated debt are offset against the exchange losses or gains arising on the translation of the financial statements of the foreign operations included in the foreign exchange adjustment account in Shareholders' Equity. Assessment of effectiveness for those derivatives classified as hedges occurs at inception and on an ongoing basis. In the event that a derivative does not meet the designation or effectiveness criteria, realized and unrealized gains or losses are recognized in income each period in the same financial statement category as the underlying transaction. Premiums paid or received with respect to derivatives that are hedges are deferred and amortized to income over the term of the hedge.

If a derivative that previously qualified as a hedge is settled, de-designated or ceases to be effective, the gain or loss at that date is deferred and recognized in the same period and in the same financial statement category as the corresponding hedged transactions. If an anticipated transaction is hedged and the transaction is no longer probable to occur, the related deferred gains or losses are recognized in income in the current period.

The recognition of gains and losses on the derivatives for the Canadian Mainline, the Alberta System, the BC System and Foothills exposures is determined through the regulatory process. The gains and losses on derivatives accounted for as part of rate-regulated accounting that do not meet the criteria for hedge accounting are deferred.

Asset Retirement Obligation

The Company recognizes the fair value of a liability for an asset retirement obligation, where a legal obligation exists, 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 and the liability is accreted at the end of each period through charges to operating expenses.

No amount is 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 inability to determine the scope and timing 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 the hydroelectric power plant assets, as it is not possible to make a reasonable estimate of the fair value of the liability due to the inability to determine the scope and timing of the asset retirements, no amount has been recorded for asset retirement obligations. For the Bruce

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 79


Power nuclear assets, as the lessor is responsible for decommissioning liabilities under the lease agreement, no amount has been recorded for asset retirement obligations.

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. Past service costs are amortized over the expected average remaining service life of the employees. 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 net actuarial gains or losses 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 has broad-based, medium-term employee incentive plans, which grant units to each eligible employee and are payable in cash. Employees have the option of designating, in advance of the payout determination, some or all of their payment to purchase shares through TCPL's stock savings plan. The expense related to these incentive plans is accounted for on an accrual basis. 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.

Certain of the Company's joint ventures sponsor DB Plans and other post-employment benefit plans. The Company records its proportionate share of expenses, funding contributions and accrued benefit assets and liabilities related to these plans.

NOTE 2    SEGMENTED INFORMATION

Effective June 1, 2006, TCPL revised the composition and names of its reportable business segments to Pipelines and Energy. The financial reporting of these segments was aligned to reflect the internal organizational structure of the Company. Pipelines principally comprises the Company's pipelines in Canada, the U.S. and Mexico. Energy includes the Company's power operations, natural gas storage business and LNG projects in Canada and the U.S. The segmented information has been retroactively restated to reflect the changes in reportable segments. These changes had no impact on consolidated income. These changes resulted in increases to net income in the Energy segment of $5 million in 2005 and $2 million in 2004, and corresponding decreases to net income in the Pipelines segment for the same years.

NET INCOME/(LOSS)(1)

Year ended December 31, 2006 (millions of dollars)   Pipelines   Energy   Corporate     Total    
Revenues   3,990   3,530   –     7,520    
Plant operating costs and other   (1,380 ) (1,024 ) (7 )   (2,411 )  
Commodity purchases resold   –   (1,707 ) –     (1,707 )  
Depreciation   (927 ) (131 ) (1 )   (1,059 )  
    1,683   668   (8 )   2,343    
Financial charges and non-controlling interests   (767 ) –   (139 )   (906 )  
Financial charges of joint ventures   (69 ) (23 ) –     (92 )  
Income from equity investments   33   –   –     33    
Interest income and other   67   5   51     123    
Gain on sale of assets   23   –   –     23    
Income taxes   (410 ) (198 ) 133     (475 )  
Net income from continuing operations   560   452   37     1,049    
     
Net income from discontinued operations                 28    
                 
Net Income Applicable to Common Shares                 1,077    
                 

80 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 
Year ended December 31, 2005 (millions of dollars)   Pipelines   Energy   Corporate     Total    
Revenues   3,993   2,131   –     6,124    
Plant operating costs and other   (1,226 ) (595 ) (4 )   (1,825 )  
Commodity purchases resold   –   (1,232 ) –     (1,232 )  
Depreciation   (932 ) (85 ) –     (1,017 )  
    1,835   219   (4 )   2,050    
Financial charges and non-controlling interests   (788 ) (2 ) (131 )   (921 )  
Financial charges of joint ventures   (57 ) (9 ) –     (66 )  
Income from equity investments   79   168   –     247    
Interest income and other   25   5   33     63    
Gains on sale of assets   82   363   –     445    
Income taxes   (497 ) (178 ) 65     (610 )  
Net income from continuing operations   679   566   (37 )   1,208    
     
Net income from discontinued operations                 –    
                 
Net Income Applicable to Common Shares                 1,208    
                 
 
Year ended December 31, 2004 (millions of dollars)                      
Revenues   3,854   1,643   –     5,497    
Plant operating costs and other   (1,161 ) (451 ) (3 )   (1,615 )  
Commodity purchases resold   –   (940 ) –     (940 )  
Depreciation   (871 ) (77 ) –     (948 )  
    1,822   175   (3 )   1,994    
Financial charges and non-controlling interests   (848 ) (9 ) (81 )   (938 )  
Financial charges of joint ventures   (59 ) (4 ) –     (63 )  
Income from equity investments   83   130   –     213    
Interest income and other   8   14   37     59    
Gains on sale of assets   7   197   –     204    
Income taxes   (429 ) (105 ) 43     (491 )  
Net income from continuing operations   584   398   (4 )   978    
     
Net income from discontinued operations                 52    
                 
Net Income Applicable to Common Shares                 1,030    
                 
(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.

TOTAL ASSETS

December 31 (millions of dollars)   2006   2005      
   
Pipelines   18,320   17,872      
Energy   6,500   5,303      
Corporate   1,088   938      
   
    25,908   24,113      
   

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 81

GEOGRAPHIC INFORMATION

Year ended December 31 (millions of dollars)   2006   2005   2004  
Revenues(1)              
Canada – domestic   4,956   3,499   3,214  
Canada – export   972   1,160   1,261  
United States and other   1,592   1,465   1,022  
    7,520   6,124   5,497  
(1)
Revenues are attributed to countries based on country of origin of product or service.

December 31 (millions of dollars)   2006   2005      
   
Plant, Property and Equipment              
Canada   16,204   15,647      
United States   5,109   4,306      
Mexico   174   85      
   
    21,487   20,038      
   

CAPITAL EXPENDITURES

Year ended December 31 (millions of dollars)   2006   2005   2004  
Pipelines   560   244   221  
Energy   976   506   305  
Corporate   36   4   4  
    1,572   754   530  

82 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 3    PLANT, PROPERTY AND EQUIPMENT

 
   2006
   2005
  
   
December 31
(millions of dollars) 		  Cost   Accumulated
Depreciation		   Net
Book Value		   Cost   Accumulated
Depreciation		   Net
Book Value		  
Pipelines                          
Canadian Mainline                          
  Pipeline   8,850   3,911   4,939   8,701   3,665   5,036  
  Compression   3,343   1,181   2,162   3,341   1,066   2,275  
  Metering and other   346   136   210   359   134   225  
    12,539   5,228   7,311   12,401   4,865   7,536  
  Under construction   23   –   23   15   –   15  
    12,562   5,228   7,334   12,416   4,865   7,551  
Alberta System                          
  Pipeline   5,120   2,352   2,768   5,020   2,203   2,817  
  Compression   1,510   760   750   1,493   676   817  
  Metering and other   806   271   535   799   247   552  
    7,436   3,383   4,053   7,312   3,126   4,186  
  Under construction   98   –   98   25   –   25  
    7,534   3,383   4,151   7,337   3,126   4,211  
GTN(1)                          
  Pipeline   1,386   111   1,275   1,381   60   1,321  
  Compression   512   32   480   507   15   492  
  Metering and other   89   –   89   90   –   90  
    1,987   143   1,844   1,978   75   1,903  
  Under construction   17   –   17   18   –   18  
    2,004   143   1,861   1,996   75   1,921  
Foothills                          
  Pipeline   815   405   410   815   377   438  
  Compression   377   141   236   377   128   249  
  Metering and other   72   35   37   71   31   40  
    1,264   581   683   1,263   536   727  
Joint Ventures and Other                          
  Great Lakes   1,187   600   587   1,181   566   615  
  Northern Border(2)   1,451   585   866   –   –   –  
  Other(3)   2,274   615   1,659   2,064   522   1,542  
    4,912   1,800   3,112   3,245   1,088   2,157  
    28,276   11,135   17,141   26,257   9,690   16,567  

Energy(4)
 
 
 
 
 
 
 
 
 
 
 
 
 
  Nuclear(5)   1,349   214   1,135   1,265   143   1,122  
  Natural gas   1,636   383   1,253   1,121   347   774  
  Hydro   592   21   571   598   9   589  
  Natural gas storage   344   22   322   45   20   25  
  Other   284   72   212   117   55   62  
    4,205   712   3,493   3,146   574   2,572  
  Under construction   809   –   809   872   –   872  
    5,014   712   4,302   4,018   574   3,444  
Corporate   65   21   44   73   46   27  
    33,355   11,868   21,487   30,348   10,310   20,038  
(1)
Gas Transmission Northwest System and North Baja system (collectively GTN).

(2)
In April 2006, PipeLines LP acquired an additional 20 per cent general partnership interest in Northern Border, bringing its total general partnership interest to 50 per cent. Northern Border became a jointly controlled entity and TCPL commenced proportionately consolidating its investment in Northern Border on a prospective basis. At December 31, 2006 the Company's effective ownership, net of non-controlling interests, is 6.7 per cent (2005 – 4.0 per cent) as a result of the Company holding a 13.4 per cent interest in PipeLines LP.

(3)
Includes $4 million of plant under construction (2005 – $85 million).

(4)
Certain power generation facilities are accounted for as assets under operating leases. At December 31, 2006, the net book value of these facilities was $81 million (2005 – $87 million). In 2006, revenues of $13 million (2005 – $23 million) were recognized through the sale of electricity under the related PPAs.

(5)
Includes assets under capital lease relating to Bruce Power.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 83

NOTE 4    OTHER ASSETS

December 31 (millions of dollars)   2006   2005      
   
PPAs(1)   767   825      
Pension and other benefit plans   268   304      
Regulatory assets   171   169      
Derivative contracts   142   209      
Hedging deferrals   152   118      
Loans and advances(2)   121   91      
Debt issue costs   77   72      
Deferred project development costs(3)   70   25      
Other   210   239      
   
    1,978   2,052      
   
(1)
The following amounts related to the PPAs are included in the consolidated financial statements.

 
   2006
   2005
  
   
December 31
(millions of dollars) 		  Cost   Accumulated
Amortization		   Net
Book Value		   Cost   Accumulated
Amortization		   Net
Book Value		  
PPAs   915   148   767   915   90   825  
(2)
The December 31, 2006 balance includes a $118 million loan (2005 – $87 million) to the Aboriginal Pipeline Group (APG) to finance the APG for its one-third share of project development costs related to the Mackenzie Gas Pipeline (MGP) project. The ability to recover this investment remains dependent upon the successful outcome of the project.

(3)
The December 31, 2006 balance includes $39 million (2005 — $6 million) and $31 million (2005 — $19 million) related to the Keystone oil project and the Broadwater LNG project respectively.

84 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 5    JOINT VENTURE INVESTMENTS

 
    
   TCPL's Proportionate Share
  
       
 
    
   Income Before Income Taxes
Year ended December 31
   Net Assets
December 31
  
       
(millions of dollars)   Ownership Interest(1)   2006   2005   2004   2006   2005  
Pipelines                          
Great Lakes   50.0%   69   73   86   370   375  
Iroquois   44.5% (2) 25   29   28   194   190  
Trans Québec & Maritimes   50.0%   11   13   13   75   73  
Northern Border   6.7% (3) 47   –   –   634   –  
Other   Various (4) 11   15   12   26   67  

Energy
 
 
 
 
 
 
 
 
 
 
 
 
 
Bruce A   48.7% (5) 75   19   –   916   563  
Bruce B   31.6% (5) 140   5   –   425   434  
ASTC Power Partnership   50.0% (6) –   –   –   82   88  
Power LP     (7) –   25   32   –   –  
CrossAlta   60.0%   64   31   20   36   30  
Portlands Energy Centre   50.0% (8) –   –   –   90   –  
Cartier Wind   62.0% (9) 2   –       172      
        444   210   191   3,020   1,820  
(1)
All ownership interests are as at December 31, 2006. Changes due to the February 22, 2007 acquisition of ANR are discussed in Note 24 "Subsequent Events".

(2)
In June 2005, the Company acquired an additional 3.5 per cent ownership interest in Iroquois.

(3)
In April 2006, PipeLines LP acquired an additional 20 per cent general partnership interest in Northern Border, bringing its total general partnership interest to 50 per cent. Northern Border became a jointly controlled entity and TCPL commenced proportionately consolidating its investment in Northern Border on a prospective basis. At December 31, 2006, the Company's effective ownership, net of non-controlling interests, was 6.7 per cent (2005 – 4.0 per cent) as a result of the Company holding a 13.4 per cent interest in PipeLines LP.

(4)
In December 2006, PipeLines LP acquired an additional 49 per cent general partnership interest in Tuscarora. As a result of this transaction, PipeLines LP owns or controls 99 per cent of Tuscarora. PipeLines LP began consolidating its investment in Tuscarora at the date of this additional acquisition. At December 31, 2006, the Company effectively owned or controled an aggregate 14.3 per cent (2005 – 7.6 per cent) interest in Tuscarora of which 13.3 per cent was held indirectly through TCPL's 13.4 per cent interest in PipeLines LP and the remaining one per cent was owned directly.

(5)
TCPL acquired a 47.4 per cent ownership interest in Bruce A on October 31, 2005. The Company increased its ownership interest in Bruce A to 48.7 per cent during 2006 (December 31, 2005 – 47.9 per cent) as a result of certain other partners not participating in capital contributions to Bruce A. The Company proportionately consolidated its investments in Bruce A and Bruce B, on a prospective basis, effective October 31, 2005.

(6)
The Company has a 50 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 per cent ownership interest in the Partnership are effectively transferred to TCPL.

(7)
In April 2004, the Company's interest in TransCanada Power, L.P. (Power LP) decreased to 30.6 per cent from 35.6 per cent. In August 2005, the Company sold its 30.6 per cent interest in Power LP.

(8)
Portlands Energy is a limited partnership between Ontario Power Generation and TCPL with both parties having a 50 per cent interest.

(9)
TCPL proportionately consolidates 62 per cent of the assets, liabilities, revenues and expenses of its Cartier Wind project. Baie-des-Sables began operating in November 2006.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 85

Summarized Financial Information of Joint Ventures

Year ended December 31 (millions of dollars)   2006   2005   2004    
Income                
Revenues   1,379   687   572    
Plant operating costs and other   (689 ) (328 ) (240 )  
Depreciation   (162 ) (93 ) (90 )  
Financial charges and other   (84 ) (56 ) (51 )  
Proportionate share of income before income taxes of joint ventures   444   210   191    
 
Year ended December 31 (millions of dollars)   2006   2005   2004    
Cash Flows                
Operating activities   645   346   270    
Investing activities   (641 ) (133 ) (287 )  
Financing activities(1)   (31 ) (152 ) 35    
Effect of foreign exchange rate changes on cash and short-term investments   9   (1 ) (5 )  
Proportionate share of (decrease)/increase in cash and short-term investments of joint ventures   (18 ) 60   13    
(1)
Financing activities include cash outflows resulting from distributions paid to TCPL of $470 million (2005 – $201 million; 2004 – $158 million) and cash inflows resulting from capital contributions paid by TCPL of $452 million (2005 – $92 million and 2004 – nil).

December 31 (millions of dollars)   2006   2005        
   
Balance Sheet                
Cash and short-term investments   127   123        
Other current assets   304   281        
Plant, property and equipment   4,110   2,707        
Other assets/(deferred amounts) (net)   78   (45 )      
Current liabilities   (443 ) (291 )      
Long-term debt   (1,136 ) (937 )      
Future income taxes   (20 ) (18 )      
   
Proportionate share of net assets of joint ventures   3,020   1,820        
   

86 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6    LONG-TERM INVESTMENTS

 
    
   TCPL's Share
  
       
 
    
   Distributions
from Equity Investments
Year ended December 31
   Income from
Equity Investments
Year ended December 31
   Equity Investments
December 31
       
(millions of dollars)   Ownership Interest   2006   2005   2004   2006   2005   2004   2006   2005  
Pipelines                                      
Northern Border     (1) 13   76   79   13   61   65   –   315  
TransGas   46.5% (2) 7   6   8   11   11   11   66   62  
Other   Various   4   10   13   9   7   7   5   23  

Energy
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Bruce B   31.6% (3) –   84   –   –   168   130   –   –  
        24   176   100   33   247   213   71   400  
(1)
In April 2006, PipeLines LP acquired an additional 20 per cent general partnership interest in Northern Border, bringing its total general partnership interest to 50 per cent. Northern Border became a jointly controlled entity and TCPL commenced proportionately consolidating its investment in Northern Border on a prospective basis.

(2)
TransGas de Occidente S.A. (TransGas).

(3)
The Company proportionately consolidated its 31.6 per cent ownership interest in Bruce B, on a prospective basis, effective October 31, 2005.

NOTE 7    ACQUISITIONS AND DISPOSITIONS

Acquisitions

Pipelines

Tuscarora

In December 2006, PipeLines LP acquired an additional 49 per cent controlling general partner interest in Tuscarora, subject to closing adjustments, for US$100 million, with the option to purchase Sierra Pacific Resources' remaining one per cent interest in Tuscarora in approximately one year. In addition, the Company indirectly assumed US$37 million of debt. The purchase price was allocated US$79 million to goodwill, US$37 million to long-term debt, and the balance primarily to plant, property and equipment. Factors that contributed to goodwill include opportunities for expansion and a stronger competitive position.

As a result of this transaction, PipeLines LP owns or controls 99 per cent of Tuscarora. At December 31, 2006, TCPL's effective ownership in Tuscarora, net of non-controlling interests, was 14.3 per cent as a result of it holding a 13.4 per cent interest in PipeLines LP, and its direct ownership of the remaining one per cent of Tuscarora. PipeLines LP began consolidating its investment in Tuscarora at the date of acquisition. In connection with this transaction, TransCanada became the operator of Tuscarora in December 2006.

Northern Border Pipeline

In April 2006, PipeLines LP acquired an additional 20 per cent general partnership interest in Northern Border for US$307 million, in addition to indirectly assuming US$122 million of debt. The purchase price was allocated US$114 million to goodwill, US$122 million to long-term debt and the balance primarily to plant, property and equipment. Factors that contributed to goodwill include opportunities for expansion and a stronger competitive position.

This transaction increased PipeLines LP's total general partnership interest in Northern Border to 50 per cent. At December 31, 2006, TCPL's effective ownership, net of non-controlling interests, was 6.7 per cent as a result of it holding a 13.4 per cent interest in PipeLines LP. PipeLines LP proportionately consolidated its 50 per cent interest in Northern Border at the date of acquisition. In connection with this transaction, TransCanada expects to become the operator of Northern Border in April 2007.

Energy

Sheerness PPA

Effective December 31, 2005, TCPL acquired the remaining rights and obligations of the Sheerness PPA from the Alberta Balancing Pool for $585 million. The PPA terminates December 2021.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 87

Bruce Power

In October 2005, as part of an agreement to restart the currently idle Bruce A Units 1 and 2, TCPL acquired a partnership interest in a newly created partnership, Bruce A, which subleased Bruce A Units 1 to 4 from Bruce B (the Bruce A Sublease) and purchased certain other related assets. TCPL incurred a net cash outlay of $100 million as a result of this transaction. As part of this reorganization, both Bruce A and Bruce B became jointly controlled entities and TCPL commenced proportionately consolidating its investment in both Bruce A and Bruce B, on a prospective basis, effective October 31, 2005. At December 31, 2006 the Company held 48.7 per cent and 31.6 per cent interests in Bruce A and Bruce B, respectively.

TC Hydro

In April 2005, TCPL acquired certain hydroelectric generation assets from USGen New England, Inc. for approximately US$503 million. Substantially all of the purchase price was allocated to plant, property and equipment.

Dispositions

The pre-tax gains on sale of assets are comprise the following.

Year ended December 31 (millions of dollars)   2006   2005   2004      
   
Gain on sale of Northern Border Partners, L.P. interest   23   –   –      
Gains related to Power LP   –   245   197      
Gain on sale of Paiton Energy(1)   –   118   –      
Gain on sale of PipeLines LP units   –   82   –      
Gain on sale of Millennium(1)   –   –   7      
   
    23   445   204      
   
(1)
PT Paiton Energy Company (Paiton Energy); Millennium Pipeline project (Millennium).

Northern Border Partners, L.P. Interest

In April 2006, TCPL sold its 17.5 per cent general partner interest in Northern Border Partners L.P. for net proceeds of $33 million (US$30 million), and recognized an after-tax gain on sale of $13 million. The net gain was recorded in the Pipelines segment and the Company recorded a $10 million income tax charge, including $12 million of current income tax expense, on this transaction.

Power LP

In August 2005, TCPL sold its ownership interest in Power LP to EPCOR Utilities Inc. (EPCOR) for net proceeds of $523 million and realized an after-tax gain of $193 million. The net gain was recorded in the Energy segment and the Company recorded a $52 million income tax charge, including $79 million of current income tax expense, on this transaction. The book value of Power LP's assets and liabilities disposed of under this sale were $452 million and $174 million, respectively. EPCOR's acquisition included 14.5 million limited partnership units of Power LP, representing 30.6 per cent of the outstanding units, 100 per cent ownership of the general partner of Power LP, and the management and operations agreements governing the ongoing operation of Power LP's generation assets.

In April 2004, TCPL sold the ManChief and Curtis Palmer power facilities to Power LP for $539 million (US$403 million) plus closing adjustments of $17 million (US$13 million) and recognized an after-tax gain on sale of $15 million. The net gain was recorded in the Energy segment and the Company recorded a $10 million income tax charge.

At a special meeting held on April 29, 2004, Power LP's unitholders approved an amendment to the terms of the Power LP Partnership Agreement to remove Power LP's obligation to redeem all units not owned by TCPL at June 30, 2017. TCPL was required to fund this redemption, thus the removal of Power LP's obligation eliminated this requirement. The removal of the obligation and the reduction in TCPL's ownership interest in Power LP resulted in a gain of $172 million.

Paiton Energy

In November 2005, TCPL sold its approximately 11 per cent ownership interest in Paiton Energy to subsidiaries of The Tokyo Electric Power Company for gross proceeds of $122 million (US$103 million) and recognized an after-tax gain on sale of $115 million. The net gain was recorded in the Energy segment and the Company recorded a $3 million income tax charge, including $3 million of current income tax recovery.

PipeLines LP

In March and April 2005, TCPL sold 3,574,200 common units of PipeLines LP for net proceeds of $153 million and recorded an after-tax gain of $49 million. The net gain was recorded in the Pipelines segment and the Company recorded a $33 million income tax charge, including $51 million of current income tax expense, on this transaction. Subsequent to these transactions, TCPL owned a 13.4 per cent interest in PipeLines LP represented by a general partner interest of 2.0 per cent and an 11.4 per cent limited partner interest.

88 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 8    LONG-TERM DEBT

 
    
   2006
   2005
  
       
    Maturity Dates   Outstanding
December 31(1)		   Weighted
Average
Interest
Rate(2)		   Outstanding
December 31(1)		   Weighted
Average
Interest
Rate(2)		  
TRANSCANADA PIPELINES LIMITED                      
First Mortgage Pipe Line Bonds                      
  Pounds Sterling (2006 and 2005 – £25)   2007   57   16.5%   50   16.5%  
Debentures                      
  Canadian dollars   2008 to 2020   1,355   10.9%   1,355   10.9%  
  U.S. dollars (2006 and 2005 – US$600)   2012 to 2021   699   9.5%   700   9.5%  
Medium-Term Notes                      
  Canadian dollars   2007 to 2031   3,848   6.0%   3,228   6.4%  
  U.S. dollars (2006 – US$2,223; 2005 – US$1,841)   2009 to 2036   2,590   5.8%   2,146   5.8%  
Subordinated Debentures                      
  U.S. dollars (2005 – US$57)       –       66   9.1%  
       
   
   
        8,549       7,545      
       
   
   

NOVA GAS TRANSMISSION LTD.
 
 
 
 
 
 
 
 
 
 
 
Debentures and Notes                      
  Canadian dollars   2007 to 2024   564   11.6%   585   11.6%  
  U.S. dollars (2006 and 2005 – US$375)   2012 to 2023   437   8.2%   437   8.2%  
Medium-Term Notes                      
  Canadian dollars   2007 to 2030   609   7.1%   665   7.2%  
  U.S. dollars (2006 and 2005 – US$33)   2026   38   7.5%   38   7.5%  
       
   
   
        1,648       1,725      
       
   
   

GAS TRANSMISSION NORTHWEST CORPORATION
 
 
 
 
 
 
 
 
 
 
 
Unsecured Debentures and Notes                      
  U.S. Dollars (2006 and 2005 – US$400)   2010 to 2035   466   5.3%   466   5.3%  
       
   
   

TC PIPELINES, LP
 
 
 
 
 
 
 
 
 
 
 
Unsecured Loan                      
  U.S. dollars (2006 – US$397; 2005 – US$14)   2007   463   5.4%   16   5.6%  
       
   
   

PORTLAND NATURAL GAS TRANSMISSION SYSTEM
 
 
 
 
 
 
 
 
 
 
 
Senior Secured Notes                      
  U.S. dollars (2006 – US$226; 2005 – US$241)   2018   263   5.9%   281   5.9%  
       
   
   

TUSCARORA GAS TRANSMISSION COMPANY
 
 
 
 
 
 
 
 
 
 
 
Senior Unsecured Notes                      
  U.S. dollars (2006 – US$74)   2010 to 2012   86   7.2%          
       
           

OTHER
 
 
 
 
 
 
 
 
 
 
 
Secured Notes                      
  U.S. dollars (2006 – US$24)   2011   28   7.3%          
       
   
   
        11,503       10,033      
Less: Current Portion of Long-Term Debt       616       393      
       
   
   
        10,887       9,640      
       
   
   
(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: TCPL's U.S. dollar medium-term notes – 5.8 per cent (2005 – 5.9 per cent) and TCPL's U.S. dollar subordinated debentures in 2005 – 9.0 per cent.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 89

Principal Repayments

Principal repayments on the long-term debt of the Company approximate: 2007 – $616 million; 2008 – $549 million; 2009 – $847 million; 2010 – $653 million; and 2011 – $883 million.

Debt Shelf Programs

At December 31, 2006, $500 million of medium-term note debentures were available for issue under a debt shelf program in Canada and US$500 million of debt securities were available for issue under a debt shelf program in the U.S. Under the Canadian debt shelf program, the Company issued $300 million of five-year medium-term notes bearing interest of 4.3 per cent in January 2006 and $400 million of ten-year medium-term notes bearing interest of 4.65 per cent in October 2006. In March 2006, the Company issued US$500 million of 30-year medium-term notes bearing interest of 5.85 per cent under the U.S. base shelf program. Both the Canadian and U.S. debt shelf programs expired in January 2007.

PipeLines LP

In April 2006, PipeLines LP borrowed US$307 million under its unsecured credit facility to finance the cash portion of the purchase price of its acquisition of an additional 20 per cent interest in Northern Border. In December 2006, the credit facility was repaid in full and replaced with a US$410 million syndicated revolving credit and term loan agreement, of which US$397 million was drawn as at December 31, 2006. Borrowings under the credit and term loan agreement will bear interest at the London interbank offered rate plus an applicable margin.

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.

Debentures

Debentures issued by Nova Gas Transmission Ltd. (NGTL), amounting to $225 million, have retraction provisions which entitle the holders to require redemption of up to eight per cent of the then outstanding principal plus accrued and unpaid interest on specified repayment dates. No redemptions have been made to December 31, 2006.

Medium-Term Notes

On February 15, 2007, the Company retired $275 million of 6.05 per cent medium term notes.

Medium-term notes issued by NGTL, 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.

Financial Charges

Year ended December 31 (millions of dollars)   2006   2005   2004    
Interest on long-term debt   849   849   864    
Interest on short-term debt   23   23   7    
Capitalized interest   (60 ) (24 ) (11 )  
Amortization and other financial charges   16   (11 ) –    
    828   837   860    

The Company made interest payments of $771 million for the year ended December 31, 2006 (2005 – $838 million; 2004 – $864 million).

90 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


NOTE 9    LONG-TERM DEBT OF JOINT VENTURES

 
    
   2006
   2005
  
       
    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                      
  (2006 and 2005 – US$230)   2011 to 2030   262   7.8%   268   7.9%  

Bruce Power
 
 
 
 
 
 
 
 
 
 
 
Capital Lease Obligations   2018   250   7.5%   254   7.5%  

Iroquois
 
 
 
 
 
 
 
 
 
 
 
Senior Unsecured Notes                      
  (2006 and 2005 – US$165)   2010 to 2027   192   7.5%   192   7.5%  
Bank Loan                      
  (2006 – US$15; 2005 – US$25)   2008   17   6.2%   29   4.3%  

Trans Québec & Maritimes
 
 
 
 
 
 
 
 
 
 
 
Bonds   2009 to 2010   138   6.0%   138   6.0%  
Term Loan   2010   32   4.4%   29   3.5%  

Northern Border
 
 
 
 
 
 
 
 
 
 
 
Senior Unsecured Notes                      
  (2006 – US$316)   2007 to 2021   368   6.9%   –   –  
Other   2007 to 2012   19   3.8%   68   6.1%  
       
   
   
        1,278       978      
Less: Current Portion of Long-Term Debt of Joint Ventures       142       41      
       
   
   
        1,136       937      
       
   
   
(1)
Amounts outstanding represent TCPL's proportionate share and are stated in millions of Canadian dollars; amounts denominated in U.S. dollars are stated in millions.

(2)
Weighted average interest rates are stated as at the respective outstanding dates. At December 31, 2006, the effective weighted average interest rates resulting from swap agreements are as follows: Iroquois bank loan – 6.9 per cent (2005 – 5.4 per cent).

The long-term debt of joint ventures is non-recourse to TCPL, except that TCPL has provided certain pro-rata guarantees related to the capital lease obligations of Bruce Power. The security provided with respect to the debt by each joint venture is limited to the rights and assets of that joint venture and does not extend to the rights and assets of TCPL, except to the extent of TCPL's investment.

The Company's proportionate share of principal repayments resulting from maturities and sinking fund obligations of the non-recourse joint venture debt approximates: 2007 – $134 million; 2008 – $17 million; 2009 – $192 million; 2010 – $246 million; and 2011 – $21 million.

The Company's proportionate share of principal payments resulting from the capital lease obligations of Bruce Power approximates: 2007 – $8 million; 2008 – $9 million; 2009 – $11 million; 2010 – $13 million; and 2011 – $15 million.

Financial Charges of Joint Ventures

Year ended December 31 (millions of dollars)   2006   2005   2004  
Interest on long-term debt   67   60   59  
Interest on capital lease obligations   19   3   –  
Short-term interest and other financial charges   3   1   2  
Deferrals and amortization   3   2   2  
    92   66   63  

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 91

The Company's proportionate share of the interest payments of joint ventures was $73 million for the year ended December 31, 2006 (2005 – $62 million; 2004 – $58 million).

The Company's proportionate share of interest payments from the capital lease obligations of Bruce Power was $20 million for the year ended December 31, 2006 (2005 – $3 million; 2004 – nil).

Subject to meeting certain requirements, the Bruce Power capital lease agreements provide for renewals commencing January 1, 2019. The first renewal is for a period of one year, and each of the second to thirteenth renewals is for a period of two years.

NOTE 10    DEFERRED AMOUNTS

December 31 (millions of dollars)   2006   2005      
   
Regulatory liabilities   386   597      
Derivative contracts   254   212      
Hedging deferrals   84   72      
Employee benefit plans   195   168      
Asset retirement obligations   45   33      
Deferred revenue   32   42      
Other   33   72      
   
    1,029   1,196      
   

NOTE 11    REGULATED BUSINESSES

Regulatory assets and liabilities represent future revenues which are expected to be recovered from or refunded to customers in future periods as a result of the rate-setting process associated with certain costs and revenues, incurred in the current period or in prior periods, and under or over collection of revenues in the current or prior periods.

Canadian Regulated Operations

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.

Rates charged by TCPL's wholly-owned and partially-owned Canadian regulated pipelines are typically set through a process that involves filing of an application for a change in rates with the regulator. Under the regulation, rates are underpinned by the total annual revenue requirement, which includes a specified annual return on capital, including debt and equity, and all necessary operating expenses, taxes and depreciation.

TCPL's Canadian regulated pipelines have generally been regulated using a cost-of-service model where the forecast costs plus a return on capital equals the revenues for the upcoming year. To the extent that actual costs are more or less than the forecast costs, the regulators generally allow the difference to be deferred to a future period and recovered or refunded in revenues at that time. Those costs for which the regulator does not allow the difference between actual and forecast costs to be deferred are included in the determination of net income in the year in which they are incurred.

The Canadian Mainline, the BC System, Foothills and TQM are regulated by the NEB under the National Energy Board Act. The Alberta System is regulated by the EUB primarily under the provisions of the Gas Utilities Act (Alberta) and the Pipeline Act (Alberta). The NEB and the EUB regulate the construction, operations, tolls and the determination of revenues of the Canadian natural gas transmission operations.

Canadian Mainline

In March 2006, TCPL and its Canadian Mainline shippers entered into a negotiated settlement that addressed all elements of the Canadian Mainline's 2006 tolls (2006 Settlement). The 2006 Settlement was approved by the NEB in April 2006. Pursuant to the 2006 Settlement, the cost of capital in the Canadian Mainline's 2006 revenue requirement and resulting tolls were determined based on the RH-2-2004 Phase II proceeding relating to the 2004 cost of capital of the Canadian Mainline. The RH-2-2004 Phase II decision increased the deemed capital structure for the Canadian Mainline to 36 per cent from 33 per cent, effective January 1, 2004. The return on equity of the Canadian Mainline continues to be based on the NEB's approved rate of return on common equity (ROE) formula, which was established in the RH-2-94 Multi-Pipeline Cost of Capital proceeding.

92 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Under the 2006 Settlement, the Canadian Mainline's operating, maintenance and administrative (OM&A) costs for 2006 were fixed and variances between the 2006 negotiated and actual level of OM&A costs accrued to TCPL. All other cost and revenue component variances were treated on a full recovery basis. The allowed ROE in 2006 was 8.88 per cent.

Alberta System

The Alberta System operates under the 2005-2007 Revenue Requirement Settlement. This settlement, approved by the EUB in June 2005, encompassed all elements of the Alberta System's revenue requirement for 2005, 2006 and 2007 and established methodologies for calculation of the revenue requirement for all three years, based on the recovery of all cost components and the use of deferral accounts.

Fixed costs are operating costs and certain other costs, including foreign exchange on interest payments, uninsured losses and amortization of severance costs. These costs were set for each of 2005, 2006 and 2007 and any difference between actual and forecast fixed costs will be included in the determination of net income in the year in which they are incurred. Costs other than fixed costs are forecast at the beginning of each year and included in the calculation of the revenue requirement. Any variance between the forecast and actual costs incurred will be included in a deferral account and adjusted in the following year's revenue requirement. The settlement also set the ROE using the formula for determining the annual generic ROE on common equity established in the EUB's General Cost of Capital Decision 2004-052 on a deemed common equity of 35 per cent for all three years. The allowed ROE in 2006 was 8.93 per cent.

Other Canadian Pipelines

Similar to the Canadian Mainline, the NEB approves pipeline tolls on an annual cost of service basis for the BC System, the Foothills System and the TQM System. The NEB allows each pipeline to charge a schedule of tolls based on the estimated cost of service. This schedule of tolls is used for a current year until a new toll filing is made for the following year. Differences between the estimated cost of service and the actual cost of service are included in the following year's tolls. The ROE for these Canadian pipelines is based on the NEB's approved ROE formula which was established in the RH-2-94 Multi-Pipeline Cost of Capital proceeding, being 8.88 per cent in 2006. The deemed equity component of each of the pipelines' capital structure was set at 36 per cent for the BC System and Foothills and 30 per cent for TQM for 2006.

U.S. Regulated Operations

TCPL's wholly-owned and partially-owned U.S. pipelines are 'natural gas companies' operating under the provisions of the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, and are subject to the jurisdiction of the FERC. The Natural Gas Act of 1938 grants the FERC authority over the construction and operation of pipelines and related facilities. The FERC also has authority to regulate rates for natural gas transportation in interstate commerce.

Gas Transmission Northwest System and North Baja System

Rates and tariffs of the Gas Transmission Northwest System and North Baja have been approved by the FERC. These two systems operate under fixed rate models, whereby maximum and minimum rates for various service types have been ordered by the FERC and under which each of the two systems are permitted to discount or negotiate rates on a non-discriminatory basis. General rates for mainline capacity on the Gas Transmission Northwest System were last reviewed by the FERC in a 1994 rate proceeding. A settlement of the 1994 rate proceeding, which set rate levels that remained in effect through December 2006, was approved by the FERC in 1996. In June 2006, Gas Transmission Northwest Corporation filed a general rate case under Section 4 of the Natural Gas Act of 1938. New rates on the Gas Transmission Northwest System went into effect on January 1, 2007, subject to refund, upon approval of final rates by the FERC. The FERC rate case hearing is scheduled to commence in October 2007. Rates for capacity on North Baja were established in 2002 in the FERC's initial order certificating construction and operations of North Baja.

Portland

In 2003, Portland received final approval from the FERC of its general rate case under the Natural Gas Act of 1938. Portland is required to file a general rate case under the Natural Gas Act of 1938 with a proposed effective date of April 1, 2008.

Northern Border

As required by the provisions of the settlement of its last rate case, on November 1, 2005, Northern Border filed a rate case with the FERC. In December 2005, the FERC issued an order accepting the proposed rates but suspended their effectiveness until May 1, 2006. Since May 1, 2006, the new rates were collected subject to refund. The settlement was reached between Northern Border Pipeline and its customers and was supported by the FERC trial staff. The FERC approved the Northern Border settlement in November 2006.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 93

Regulatory Assets and Liabilities

Year ended December 31 (millions of dollars)   2006   2005     Remaining
Recovery/
Settlement
Period		  
              (years)  
Regulatory Assets                
  Unrealized losses on derivatives – Canadian Mainline(1)   44   43     1 - 4  
  Unrealized losses on derivatives – BC System(1)   33   33     7  
  Foreign exchange reserve – Alberta System(2)   33   32     23  
  Phase II Preliminary Expenditures – Foothills(3)   20   23     9  
  Transitional other benefit obligations – Canadian Mainline(4)   9   10     10  
  Other   32   28     n/a  
     
Total Regulatory Assets (Other Assets)   171   169        
     

Regulatory Liabilities
 
 
 
 
 
 
 
 
  Operating and debt service regulatory liabilities(5)   70   273     1  
  Foreign exchange on long-term debt – Canadian Mainline(6)   195   202     1 - 41  
  Foreign exchange on long-term debt – Alberta System(6)   60   59     6 - 23  
  Foreign exchange on long-term debt – BC System(6)   19   20     7  
  Post-retirement benefits other than pension – Gas Transmission Northwest System(7)   19   17     n/a  
  Other   23   26     n/a  
     
Total Regulatory Liabilities (Deferred Amounts)   386   597        
     
(1)
Unrealized losses on derivatives represent the net position of fair value gains and losses on cross currency and interest rate swaps which act as economic hedges. The cross currency swaps relate to the Canadian Mainline and the BC System related foreign debt instruments. The Canadian Mainline interest rate swaps were entered into as a result of the Mainline Interest Rate Management Program approved by the NEB as a component of the 1996 - 1999 Incentive Cost Recovery and Revenue Settlement. Interest savings or losses are determined when the interest swaps are settled. In the absence of rate-regulated accounting, Canadian GAAP would require the inclusion of these fair value losses in the operating results of the Canadian Mainline as they were not documented as hedges for accounting purposes. In the absence of rate-regulated accounting, pre-tax operating results of the Canadian Mainline for 2006 would have been $1 million lower (2005 – $8 million lower). Effective January 1, 2006, the BC System cross-currency swap has been designated and is effective to qualify for hedge accounting. The regulatory asset with respect to the BC System represents the unrealized losses for the ineffective period of the derivative from inception to December 31, 2005. In the absence of rate-regulated accounting, pre-tax operating results would have been the same (2005 – $2 million lower) for the BC System.

(2)
The foreign exchange reserve account in the Alberta System, as approved by the EUB, is designed to facilitate the recovery or refund of foreign exchange gains and losses over the life of the foreign currency debt issues. The estimated gain/(loss) on foreign currency debt is amortized over the remaining years of the longest outstanding U.S. debt issue. The annual amortization amount is included in the determination of tolls for the year.

(3)
Phase II Preliminary Expenditures are costs incurred by Foothills prior to 1981 related to development of Canadian facilities to deliver Alaskan gas that have been approved by the regulator for collection through straight-line amortization over the period November 1, 2002 to December 31, 2015. In the absence of rate-regulated accounting, GAAP would require these costs to be expensed in the year incurred, increasing pre-tax operating results in 2006 by $3 million (2005 – $2 million higher).

(4)
The regulatory asset with respect to the transitional other benefit obligations is being amortized over 17 years, starting January 1, 2000. Amortization will be completed by December 31, 2016, at which time the full transitional obligation will have been recovered through tolls. In the absence of rate-regulated accounting, pre-tax operating results would have been $1 million higher (2005 – $1 million higher).

(5)
Operating and debt service regulatory liabilities represent the accumulation of cost and revenue variances approved by the regulatory authority for inclusion in determination of the tolls for the immediate following calendar year. In the absence of rate-regulated accounting, GAAP would have required the inclusion of these variances in the operating results of the year in which the variances were incurred. Pre-tax operating results for 2006 and 2005 are the same as would have been the case in the absence of rate-regulated accounting.

(6)
The foreign exchange on long-term debt of the Canadian Mainline, the Alberta System and the BC System represent the variance resulting from revaluing foreign currency denominated debt instruments from their historic foreign exchange rate to the current foreign exchange rate. Foreign exchange gains/(losses) realized when foreign debt matures or is redeemed early are expected to be recovered or refunded through the determination of future tolls. In the absence of rate-regulated accounting, GAAP would have required the inclusion

94 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(7)
In Gas Transmission Northwest System's rates, an amount is recovered for post-retirement benefits other than pension (PBOP). This regulatory liability represents the difference between the amount collected in rates and the amount of PBOP expense determined under GAAP. In the absence of rate-regulated accounting, GAAP would require the inclusion of this amount in operating results and pre-tax operating results in 2006 would have been $2 million higher than reported (2005 – $1 million higher).

As prescribed by the regulators, the taxes payable method of accounting for income taxes is used for tollmaking purposes for Canadian regulated natural gas transmission operations. As permitted by GAAP, this method is also used for accounting purposes, since there is reasonable expectation that future income taxes payable will be included in future costs of service and recorded in revenues at that time. Consequently, future income tax liabilities have not been recognized as it is expected that when these amounts become payable, they will be recovered through future rate revenues. In the absence of rate-regulated accounting, GAAP would require the recognition of future income tax liabilities. If the liability method of accounting had been used, additional future income tax liabilities in the amount of $1,355 million at December 31, 2006 (2005 – $1,619 million) would have been recorded and would be recoverable from future revenues. In the second quarter of 2006, a reduction in enacted Canadian federal and provincial corporate future income tax rates resulted in a decrease of $182 million to this unrecorded future income tax liability. For the U.S. natural gas transmission operations, the liability method of accounting is used for both accounting and tollmaking purposes, whereby future income tax assets and liabilities are recognized based on the differences between financial statement carrying amounts and the tax basis of such assets and liabilities. As this method is also used for tollmaking purposes for the U.S. natural gas transmission operations, the current year's revenues include a tax provision which is calculated based on the liability method of accounting and therefore, there is no recognition of a related regulatory asset or liability.

NOTE 12    PREFERRED SECURITIES

The US$460 million (2006 and 2005 – $536 million) 8.25 per cent preferred securities are redeemable by the Company at par at any time. The Company may elect to defer interest payments on the preferred securities and settle the deferred interest in either cash or common shares.

NOTE 13    NON-CONTROLLING INTERESTS

The Company's non-controlling interests included in the consolidated balance sheet are as follows.

December 31 (millions of dollars)   2006   2005      
   
Non-controlling interest in PipeLines LP   287   318      
Other   79   76      
   
    366   394      
   

The Company's non-controlling interests included in the consolidated income statement are as follows.

Year ended December 31 (millions of dollars)   2006   2005   2004  
Non-controlling interest in PipeLines LP   43   52   46  
Other   13   10   10  
    56   62   56  

Non-Controlling Interest in PipeLines LP and Other

As at December 31, 2006, the non-controlling interest in PipeLines LP represents the 86.6 per cent of the limited partnership held by the limited partners. Other non-controlling interests include the 38.3 per cent non-controlling interest in Portland held by an unrelated partner. Revenues received from PipeLines LP and Portland with respect to services provided by TCPL for the year ended December 31, 2006 were $1 million (2005 – $1 million; 2004 – $1 million) and $6 million (2005 – $6 million; 2004 – $4 million), respectively.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 95

NOTE 14    PREFERRED SHARES

December 31 Number of
Shares		   Dividend Rate
Per Share		   Redemption
Price Per Share		   2006   2005  
  (thousands)           (millions of dollars)   (millions of dollars)  
Cumulative First Preferred Shares                    
Series U 4,000   $2.80   $50.00   195   195  
Series Y 4,000   $2.80   $50.00   194   194  
             
              389   389  
             

The authorized number of preferred shares issuable in series is unlimited. All of the cumulative first preferred shares are without par value.

On or after October 15, 2013, for the Series U shares, and on or after March 5, 2014, for the Series Y shares, the issuer may redeem the shares at $50 per share.

NOTE 15    COMMON SHARES

    Number of Shares   Amount  
    (thousands)   (millions of dollars)  
Outstanding at January 1, and December 31, 2004   480,668   4,632  
Issued for cash or cash equivalent   2,676   80  
Outstanding at December 31, 2005 and 2006   483,344   4,712  

Common Shares Issued and Outstanding

The Company is authorized to issue an unlimited number of common shares of no par value.

Restriction on Dividends

Certain terms of the Company's preferred shares, preferred securities, and debt instruments could restrict the Company's ability to declare dividends on preferred and common shares. At December 31, 2006, under the most restrictive provisions, approximately $1.9 billion (2005 – $1.7 billion) was available for the payment of dividends on common shares.

Dividend Reinvestment and Share Purchase Plan

In January 2007, the Board of Directors of TransCanada Corporation (TransCanada) authorized the issue of common shares from treasury at a discount of two per cent to participants in TransCanada's Dividend Reinvestment and Share Purchase Plan (DRP). Under this plan, eligible TCPL preferred shareholders may reinvest their dividends and make optional cash payments to obtain additional TransCanada common shares. Previously, shares purchased through the DRP were purchased by TransCanada on the open market and provided to DRP participants at cost. Commencing with the dividend payable in April 2007, the DRP shares will be provided to the participants at a two per cent discount to the average market price in the five days before dividend payment. TransCanada reserves the right to alter the discount or return to purchasing shares on the open market at any time.

NOTE 16    RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

The Company issues short-term and long-term debt, purchases and sells energy commodities, including amounts in foreign currencies, and invests in foreign operations. These activities result in exposures to changing interest rates, energy commodity prices and foreign currency exchange rates. The Company uses derivatives to manage the exposure that results from these activities. The use of derivatives is subject to the Company's overall risk management policies and procedures.

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

96 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Net Investment in Foreign Operations

At December 31, 2006 and 2005, the Company had net investments in self-sustaining foreign operations with a U.S. dollar functional currency which created an exposure to changes in exchange rates. The Company uses U.S. dollar denominated debt and derivatives to hedge this exposure on an after-tax basis. The fair value for derivatives used to manage the exposure is shown in the table below.

 
    
   2006
   2005
  
       

Asset/(Liability)
December 31 (millions of dollars)
 
Accounting
Treatment
 
Fair Value
 
Notional or
Principal
Amount
 
Fair Value
 
Notional or
Principal
Amount
 
U.S. dollar cross-currency swaps
(maturing 2007 to 2013)		   Hedge   58   U.S. 400   119   U.S. 450  
U.S. dollar forward foreign exchange contracts
(maturing 2007)		   Hedge   (7 ) U.S. 390   5   U.S. 525  
U.S. dollar options
(maturing 2007)		   Hedge   (6 ) U.S. 500   –   U.S. 60  

Reconciliation of Foreign Exchange Adjustment

December 31 (millions of dollars)   2006   2005        
   
Balance at January 1 (loss)   (90 ) (71 )      
Translation gains/(losses) on foreign currency denominated net assets(1)   8   (21 )      
(Losses)/gains on derivatives   (9 ) 23        
Income taxes   1   (21 )      
   
   
Balance at December 31 (loss)   (90 ) (90 )      
   
   
(1)
The amount for 2006 includes gains of $6 million (2005 – $80 million) related to foreign currency denominated debt designated as a hedge.

Foreign Exchange and Interest Rate Management Activity

The Company manages the foreign exchange and interest rate risks related to its U.S. dollar denominated debt and transactions and interest rate exposures of the Canadian Mainline, the Alberta System and the BC 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.

 
    
   2006
    
   2005
  
       
 

Asset/(Liability)
December 31 (millions of dollars)
 
Accounting
Treatment
 
Fair Value
 
 
 
Notional or
Principal
Amount
 
Fair Value
 
 
 
Notional or
Principal
Amount
 
Foreign Exchange                              
Cross-currency and interest-rate swaps
(maturing 2013)		   Hedge   (32 )     136/U.S. 100   –       –  
  (maturing 2010 to 2012)   Non-hedge   (52 )     227/U.S. 157   (86 )     363/U.S. 257  
       
     
     
        (84 )         (86 )        
       
     
     

Interest Rate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest rate swaps                              
  Canadian dollars                              
    (maturing 2007 to 2008)   Hedge   2       100   4       100  
    (maturing 2007 to 2009)   Non-hedge   5       300   7       374  
       
     
     
        7           11          
       
     
     
  U.S. dollars                              
    (maturing 2007 to 2009)   Non-hedge   4       U.S. 100   5       U.S. 100  

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 97

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.

 
    
   2006
   2005
  
       
 

Asset/(Liability)
December 31 (millions of dollars)
 
Accounting
Treatment
 
Fair Value
 
 
 
Notional or
Principal
Amount
 
Fair Value
 
 
Notional or
Principal
Amount
 
Foreign Exchange                            
Options (maturing 2007)   Non-hedge   –       U.S. 95   1     U.S. 195  
Forward foreign exchange contracts                            
    Hedge   –       –   2     U.S. 29  
  (maturing 2007)   Non-hedge   (3 )     U.S. 250   1     U.S. 208  
       
     
     
        (3 )         4        
       
     
     

Interest Rate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Options (maturing 2007)   Non-hedge   –       U.S. 50   –     –  
Interest rate swaps                            
  Canadian dollar                            
    (maturing 2007 to 2011)   Hedge   –       150   1     100  
    (maturing 2009 to 2011)   Non-hedge   –       164   1     423  
       
     
     
        –           2        
       
     
     
  U.S. dollars                            
    (maturing 2011 to 2017)   Hedge   (2 )     U.S. 350   –     U.S. 50  
    (maturing 2007 to 2016)   Non-hedge   9       U.S. 450   18     U.S. 550  
       
     
     
        7           18        
       
     
     

Foreign exchange gains included in Other Expenses/(Income) for the year ended December 31, 2006 are $4 million (2005 – $19 million; 2004 – $6 million).

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 these outstanding derivatives at December 31, 2006 and 2005 was nil.

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 value and notional volumes of contracts for differences and the swap, option, future and heat rate contracts are shown in the tables below.

Energy

Asset/(Liability)

 
    
   2006
   2005
    
       
December 31 (millions of dollars)   Accounting
Treatment 		  Fair Value   Fair Value    
Power – swaps and contracts for differences                
  (maturing 2007 to 2011)   Hedge   (179 ) (130 )  
  (maturing 2007 to 2010)   Non-hedge   (7 ) 13    
Gas – swaps, futures and options                
  (maturing 2007 to 2016)   Hedge   (66 ) 17    
  (maturing 2007 to 2008)   Non-hedge   30   (11 )  
Heat rate contracts   Non-hedge   –   –    

98 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Notional Volumes

 
    
   Power (GWh)(1)
   Gas (Bcf)(1)
  
       
December 31, 2006   Accounting
Treatment 		  Purchases   Sales   Purchases   Sales  
Power – swaps and contracts for differences                      
  (maturing 2007 to 2011)   Hedge   6,654   12,349   –   –  
  (maturing 2007 to 2010)   Non-hedge   1,402   964   –   –  
Gas – swaps, futures and options                      
  (maturing 2007 to 2016)   Hedge   –   –   77   59  
  (maturing 2007 to 2008)   Non-hedge   –   –   11   15  
Heat rate contracts   Non-hedge   –   9   –   –  
December 31, 2005                      
Power – swaps and contracts for differences   Hedge   2,566   7,780   –   –  
    Non-hedge   1,332   456   –   –  
Gas – swaps, futures and options   Hedge   –   –   91   69  
    Non-hedge   –   –   15   18  
Heat rate contracts   Non-hedge   –   35   –   –  
(1)
Gigawatt hours (GWh); billion cubic feet (Bcf).

Certain of the Company's joint ventures use power derivatives to manage energy price risk exposures. The Company's proportionate share of the fair value of these outstanding power sales derivatives at December 31, 2006 was $55 million (2005 – $(38) million) and related to contracts which cover the period 2007 to 2010. The Company's proportionate share of the notional sales volumes of power associated with this exposure at December 31, 2006 was 4,500 GWh (2005 – 2,058 GWh).

Fair Value of Financial Instruments

The fair value of cash and short-term investments and notes payable approximates their carrying amounts due to the short period to maturity. The fair value of long-term debt, long-term debt of joint ventures and preferred securities is determined using market prices for the same or similar issues.

 
   2006
   2005
  
   
December 31 (millions of dollars)   Carrying
Amount		   Fair Value   Carrying
Amount		   Fair Value  
Long-Term Debt                  
TransCanada PipeLines Limited   8,549   9,738   7,545   9,071  
NOVA Gas Transmission Ltd.   1,648   2,111   1,725   2,267  
Gas Transmission Northwest Corporation   466   450   466   470  
Portland Natural Gas Transmission System   263   265   281   292  
TC PipeLines, LP   463   463   16   16  
Tuscarora Gas Transmission Company   86   94          
Other   28   28          
Long-Term Debt of Joint Ventures   1,278   1,295   978   1,101  
Preferred Securities   536   532   536   554  

The fair value is provided solely for information purposes and is not recorded in the consolidated balance sheet.

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, 2006, for foreign currency and interest rate derivatives, total credit risk and the largest credit exposure to a single counterparty were $38 million and $11 million, respectively. At December 31, 2006, for power, natural gas and heat rate derivatives, total credit risk and the largest credit exposure to a single counterparty were $21 million and $11 million, respectively.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 99

NOTE 17    INCOME TAXES

Provision for Income Taxes

Year ended December 31 (millions of dollars)   2006   2005   2004  
Current              
Canada   263   499   373  
Foreign   37   51   41  
    300   550   414  

Future
 
 
 
 
 
 
 
Canada   104   (46 ) 34  
Foreign   71   106   43  
    175   60   77  
    475   610   491  

Geographic Components of Income

Year ended December 31 (millions of dollars)   2006   2005   2004  
Canada   1,158   1,315   1,205  
Foreign   444   587   342  
Income from continuing operations before income taxes and non-controlling interests   1,602   1,902   1,547  

Reconciliation of Income Tax Expense

Year ended December 31 (millions of dollars)   2006   2005   2004    
Income from continuing operations before income taxes and non-controlling interests   1,602   1,902   1,547    
Federal and provincial statutory tax rate   32.5 % 33.6 % 33.9 %  
Expected income tax expense   521   639   524    
Income tax differential related to regulated operations   72   71   62    
Higher effective foreign tax rates   –   2   2    
Tax rate reductions(1)   (33 ) –   –    
Large corporations tax   –   15   21    
Income from equity investments and non-controlling interests   (27 ) (29 ) (24 )  
Non-taxable portion of gains on sale of assets   –   (68 ) (66 )  
Change in valuation allowance   –   –   (7 )  
Other(2)   (58 ) (20 ) (21 )  
Actual income tax expense   475   610   491    
(1)
In second quarter 2006, TCPL recorded a $33 million future income tax benefit as a result of reductions in future Canadian federal and provincial corporate income tax rates enacted in that quarter.

(2)
Includes income tax benefits of $51 million recorded in 2006 on the resolution of certain income tax matters with taxation authorities and changes in estimates.

100 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Future Income Tax Assets and Liabilities

December 31 (millions of dollars)   2006   2005  
Deferred costs   65   129  
Other post-employment benefits   45   39  
Deferred revenue   6   11  
Other   47   50  
    163   229  
Less: Valuation allowance   14   14  
Future income tax assets, net of valuation allowance   149   215  
Difference in accounting and tax bases of plant, equipment and PPAs   768   637  
Investments in subsidiaries and partnerships   113   131  
Pension benefits   59   58  
Unrealized foreign exchange gains on long-term debt   39   68  
Other   46   24  
Future income tax liabilities   1,025   918  
Net future income tax liabilities   876   703  

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 $72 million at December 31, 2006 (2005 – $61 million).

Income Tax Payments

Income tax payments of $494 million were made during the year ended December 31, 2006 (2005 – $530 million; 2004 – $419 million).

NOTE 18    NOTES PAYABLE

 
   2006
   2005
  
   
    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)      
Canadian dollars   467     4.3%   765   3.4%  
U.S. dollars (2006 – nil; 2005 – US$169)   –         197   4.5%  
   
     
   
    467         962      
   
     
   

Notes payable consists of commercial paper and line of credit drawings. At December 31, 2006, total credit facilities of $2.1 billion were available to support the Company's commercial paper programs and for general corporate purposes. Of this total, $1.5 billion was a committed five-year term syndicated credit facility. This facility is extendible on an annual basis and is revolving. In December 2006, the facility was extended to December 2011. The remaining amounts are either demand or non-extendible facilities.

At December 31, 2006, the Company had used approximately $190 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 is 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 was $2 million for the year ended December 31, 2006 (2005 – $2 million).

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 101


NOTE 19    ASSET RETIREMENT OBLIGATIONS

At December 31, 2006, the estimated undiscounted cash flows required to settle the asset retirement obligations with respect to the non-regulated operations in Pipelines were $39 million (2005 – $39 million), calculated using an inflation rate ranging from two to three per cent per annum. The estimated fair value of this liability was $9 million (2005 – $4 million) after discounting the estimated cash flows at rates ranging from 5.4 per cent to 6.6 per cent. At December 31, 2006, the expected timing of payment for settlement of the obligations is 23 years.

At December 31, 2006, the estimated undiscounted cash flows required to settle the asset retirement obligations with respect to the Energy business were $162 million (2005 – $114 million), calculated using an inflation rate ranging from two to three per cent per annum. The estimated fair value of this liability was $36 million (2005 – $29 million) after discounting the estimated cash flows at rates ranging from 5.4 per cent to 6.6 per cent. At December 31, 2006, the expected timing of payment for settlement of the obligations ranges from 11 to 33 years.

Reconciliation of Asset Retirement Obligations

(millions of dollars)   Pipelines   Energy   Total  
Balance at January 1, 2004   1   8   9  
New obligations and revisions in estimated cash flows   4   26   30  
Removal of Power LP redemption obligations   –   (5)   (5)  
Accretion expense   –   2   2  
Balance at December 31, 2004   5   31   36  
New obligations and revisions in estimated cash flows   (1)   1   –  
Sale of Power LP   –   (5)   (5)  
Accretion expense   –   2   2  
Balance at December 31, 2005   4   29   33  
New obligations and revisions in estimated cash flows   4   6   10  
Accretion expense   1   1   2  
Balance at December 31, 2006   9   36   45  

NOTE 20    EMPLOYEE FUTURE BENEFITS

The Company sponsors DB Plans that cover substantially all employees. 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 (CPI). 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 post-employment benefits other than pensions, including termination benefits and defined life insurance and medical benefits beyond those provided by government-sponsored plans. Past service costs are amortized over the expected average remaining life expectancy of former employees, which at December 31, 2006 was approximately 13 years.

In 2006, the Company expensed $2 million (2005 – $2 million; 2004 – $1 million) related to retirement savings plans for its U.S. employees.

Total cash payments for employee future benefits for 2006, consisting of cash contributed by the Company to the DB Plans and other benefit plans was $104 million (2005 – $74 million).

102 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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, 2007, and the next required valuation is as of January 1, 2008.

 
   Pension Benefit Plans
   Other Benefit Plans
    
   
(millions of dollars)   2006   2005   2006   2005    
Change in Benefit Obligation                    
  Benefit obligation – beginning of year   1,282   1,100   148   123    
  Current service cost   39   32   3   3    
  Interest cost   65   63   8   7    
  Employee contributions   3   3   –   –    
  Benefits paid   (64 ) (60 ) (7 ) (6 )  
  Actuarial loss/(gain)   53   149   (2 ) 21    
  Foreign exchange rate changes   –   (3 ) –   –    
  Plan amendment   –   –   (18 ) –    
  Curtailment   –   (2 ) –   –    
  Benefit obligation – end of year   1,378   1,282   132   148    

Change in Plan Assets
 
 
 
 
 
 
 
 
 
 
  Plan assets at fair value – beginning of year   1,096   970   27   26    
  Actual return on plan assets   134   119   6   2    
  Employer contributions   95   67   7   5    
  Employee contributions   3   3   –   –    
  Benefits paid   (64 ) (60 ) (7 ) (6 )  
  Foreign exchange rate changes   –   (3 ) –   –    
  Plan assets at fair value – end of year   1,264   1,096   33   27    
Funded status – plan deficit   (114 ) (186 ) (99 ) (121 )  
Unamortized net actuarial loss   291   331   39   45    
Unamortized past service costs   32   36   (12 ) 8    
Accrued benefit asset/(liability), net of valuation allowance of nil   209   181   (72 ) (68 )  

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

 
   Pension Benefit Plans
   Other Benefit Plans
    
   
(millions of dollars)   2006   2005   2006   2005    
Other assets   230   268   5   4    
Accounts payable   –   (70 ) –   (7 )  
Deferred amounts   (21 ) (17 ) (77 ) (65 )  
Total   209   181   (72 ) (68 )  

Included in the above benefit obligation and fair value of plan assets at December 31 are the following amounts in respect of plans that are not fully funded.

 
   Pension Benefit Plans
   Other Benefit Plans
    
   
(millions of dollars)   2006   2005   2006   2005    
Benefit obligation   (1,359 ) (1,263 ) (102 ) (124 )  
Plan assets at fair value   1,243   1,075   –   –    
Funded status – plan deficit   (116 ) (188 ) (102 ) (124 )  

The Company's expected contributions for the year ended December 31, 2007 are approximately $44 million for the pension benefit plans and approximately $5 million for the other benefit plans.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 103


The following are estimated future benefit payments, which reflect expected future service.

(millions of dollars)   Pension
Benefits		   Other
Benefits		  
2007   59   7  
2008   62   7  
2009   65   8  
2010   68   8  
2011   71   8  
Years 2012 to 2016   406   42  

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
  
   
    2006   2005   2006   2005  
Discount rate   5.00%   5.00%   5.20%   5.15%  
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
  
   
    2006   2005   2004   2006   2005   2004  
Discount rate   5.00%   5.75%   6.00%   5.15%   6.00%   6.25%  
Expected long-term rate of return on plan assets   6.90%   6.90%   6.90%   7.75%   7.20%      
Rate of compensation increase   3.50%   3.50%   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. The discount rate is based on market interest rates of high quality bonds that match the timing and benefits expected to be paid under each plan.

For measurement purposes, a nine per cent annual rate of increase in the per capita cost of covered health care benefits was assumed for 2007. The rate was assumed to decrease gradually to five per cent for 2015 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   4   (3 )  
Effect on post-employment benefit obligation   8   (7 )  

104 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company's net benefit cost is as follows.

 
   Pension Benefit Plans
   Other Benefit Plans
    
   
Year ended December 31 (millions of dollars)   2006   2005   2004   2006   2005   2004    
Current service cost   39   32   28   3   3   3    
Interest cost   65   63   58   8   7   7    
Actual return on plan assets   (134 ) (119 ) (97 ) (6 ) (2 ) (1 )  
Actuarial loss/(gain)   53   149   46   (2 ) 21   (12 )  
Plan amendment   –   –   –   (18 ) –   –    
Elements of net benefit cost prior to adjustments to recognize the long-term nature of net benefit cost   23   125   35   (15 ) 29   (3 )  
Difference between expected and actual return on plan assets   63   54   39   4   –   1    
Difference between actuarial loss recognized and actual actuarial loss on accrued benefit obligation   (27 ) (131 ) (32 ) 4   (20 ) 13    
Difference between amortization of past service costs and actual plan amendments   4   3   3   19   1   –    
Amortization of transitional obligation related to regulated business   –   –   –   2   2   2    
Net benefit cost recognized   63   51   45   14   12   13    

The Company's pension plans' weighted average asset allocations 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   2006   2005     2006  
Debt securities   40%   43%     35% to 60%  
Equity securities   60%   57%     40% to 65%  
   
     
    100%   100%        
   
     

Debt securities include the Company's debt in the amount of $4 million (0.3 per cent of total plan assets) and $3 million (0.3 per cent of total plan assets) at December 31, 2006 and 2005, respectively. Equity securities include the Company's common shares in the amounts of $6 million (0.5 per cent of total plan assets) and $5 million (0.5 per cent of total plan assets) at December 31, 2006 and 2005, respectively.

The assets of the pension plans are managed on a going concern basis subject to legislative restrictions. The plans' investment policies are to maximize returns within an acceptable risk tolerance. Pension assets are invested in a diversified manner with consideration given to the demographics of the plans' participants.

Employee Future Benefits of Joint Ventures

In addition to these plans, certain of the Company's joint ventures sponsor DB Plans, as well as post-employment benefits other than pensions, including defined life insurance and medical benefits beyond those provided by government-sponsored plans. The obligations of these plans are non-recourse to TCPL. The amounts that follow represent TCPL's proportionate share with respect to these plans.

Total cash payments for employee future benefits for 2006, consisting of cash contributed by the Company's joint ventures to DB Plans and other benefit plans was $25 million (2005 – $4 million).

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 105


The Company's joint ventures measure the benefit obligations and the fair value of plan assets for accounting purposes as at December 31 of each year. The most recent actuarial valuations of the pension plans for funding purposes were as of January 1, 2007, and the next required valuations will be as of January 1, 2008.

 
   Pension Benefit Plans
   Other Benefit Plans
    
   
(millions of dollars)   2006   2005   2006   2005    
Change in Benefit Obligation                    
  Benefit obligation – beginning of year   679   45   81   2    
  Current service cost   24   4   7   1    
  Interest cost   37   7   5   1    
  Employee contributions   5   –   –   –    
  Benefits paid   (15 ) (3 ) (2 ) –    
  Actuarial loss   77   17   72   2    
  Foreign exchange rate changes   –   (1 ) –   –    
  Bruce B(1)   –   610   –   75    
  Plan amendment   –   –   6   –    
  Benefit obligation – end of year   807   679   169   81    

Change in Plan Assets
 
 
 
 
 
 
 
 
 
 
  Plan assets at fair value – beginning of year   585   57   –   –    
  Actual return on plan assets   68   18   –   –    
  Employer contributions   23   4   2   –    
  Employee contributions   5   –   –   –    
  Benefits paid   (15 ) (3 ) (2 ) –    
  Foreign exchange rate changes   –   (1 ) –   –    
  Bruce B(1)   –   510   –   –    
  Plan assets at fair value – end of year   666   585   –   –    
Funded status – plan deficit   (141 ) (94 ) (169 ) (81 )  
Unamortized net actuarial loss/(gain)   174   125   66   (5 )  
Unamortized past service costs   –   1   6   –    
Accrued benefit asset/(liability), net of valuation allowance of nil   33   32   (97 ) (86 )  
(1)
The Company proportionately consolidated Bruce B, on a prospective basis at 31.6 per cent, effective October 31, 2005.

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

 
   Pension Benefit Plans
   Other Benefit Plans
    
   
(millions of dollars)   2006   2005   2006   2005    
Other assets   33   32   –   –    
Deferred amounts   –   –   (97 ) (86 )  
Total   33   32   (97 ) (86 )  

Included in the above benefit obligation and fair value of plan assets at December 31 are the following amounts in respect of plans that are not fully funded.

 
   Pension Benefit Plans
   Other Benefit Plans
    
   
(millions of dollars)   2006   2005   2006   2005    
Benefit obligation   (773 ) (645 ) (169 ) (81 )  
Plan assets at fair value   609   534   –   –    
Funded status – plan deficit   (164 ) (111 ) (169 ) (81 )  

106 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company's joint ventures' expected contributions for the year ended December 31, 2007 are approximately $33 million for the pension benefit plans and approximately $3 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		  
2007   13   3  
2008   15   4  
2009   19   4  
2010   23   5  
2011   27   6  
Years 2012 to 2016   194   40  

The significant weighted average actuarial assumptions adopted in measuring the Company's joint ventures' benefit obligations at December 31 are as follows.

 
   Pension Benefit Plans
   Other Benefit Plans
  
   
    2006   2005   2006   2005  
Discount rate   5.05%   5.30%   4.95%   5.15%  
Rate of compensation increase   3.50%   3.50%          

The significant weighted average actuarial assumptions adopted in measuring the Company's joint ventures' net benefit plan cost for years ended December 31 are as follows.

 
   Pension Benefit Plans
   Other Benefit Plans
  
   
    2006   2005   2004   2006   2005   2004  
Discount rate   5.25%   6.20%   6.00%   5.15%   6.25%   6.00%  
Expected long-term rate of return on plan assets   7.30%   7.40%   8.50%              
Rate of compensation increase   3.50%   3.50%   4.00%              

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   24   (20 )  

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 107

The Company's proportionate share of net benefit cost of joint ventures is as follows.

 
   Pension Benefit Plans
   Other Benefit Plans
  
   
Year ended December 31 (millions of dollars)   2006   2005   2004   2006   2005   2004  
Current service cost   24   4   1   7   1   –  
Interest cost   37   7   3   5   1   –  
Actual return on plan assets   (68 ) (18 ) (7 ) –   –   –  
Actuarial loss   77   17   –   72   2   –  
Plan amendment   –   –   –   6   –   –  
Elements of net benefit cost prior to adjustments to recognize the long-term nature of net benefit cost   70   10   (3 ) 90   4   –  
Difference between expected and actual return on plan assets   26   9   2   –   –   –  
Difference between actuarial loss recognized and actual actuarial loss on accrued benefit obligation   (70 ) (16 ) 1   (72 ) (3 ) –  
Difference between amortization of past service costs and actual plan amendments   –   –   –   (6 ) –   –  
Net benefit cost recognized related to joint ventures   26   3   –   12   1   –  

The Company's joint ventures' pension plans' weighted average asset allocations and weighted average target allocation at December 31, by asset category, are as follows.

 
   Percentage of Plan Assets
   Target Allocation
  
   
Asset Category   2006   2005     2006  
Debt securities   29%   30%     30%  
Equity securities   71%   70%     70%  
   
     
    100%   100%        
   
     

Debt securities include the Company's debt in the amount of $1 million (0.2 per cent of total plan assets) and $1 million (0.2 per cent of total plan assets) at December 31, 2006 and 2005, respectively. Equity securities include the Company's common shares in the amounts of $6 million (1 per cent of total plan assets) and $5 million (0.9 per cent of total plan assets) at December 31, 2006 and 2005, respectively.

The assets of the pension plans are managed on a going concern basis subject to legislative restrictions. The plans' investment policies are to maximize returns within an acceptable risk tolerance. Pension assets are invested in a diversified manner with consideration given to the demographics of the plans' participants.

NOTE 21    CHANGES IN OPERATING WORKING CAPITAL

Year ended December 31 (millions of dollars)   2006   2005   2004    
(Increase)/decrease in accounts receivable   (186 ) (100 ) 15    
Increase in inventories   (108 ) (50 ) –    
(Increase)/decrease in other current assets   (6 ) (1 ) 24    
(Decrease)/increase in accounts payable   (41 ) 98   (4 )  
Increase/(decrease) in accrued interest   41   5   (7 )  
    (300 ) (48 ) 28    

108 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 22    COMMITMENTS, CONTINGENCIES AND GUARANTEES

Commitments

Operating leases

Future annual payments, net of sub-lease receipts, under the Company's operating leases for various premises, services, equipment 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		  
2007   52   (13 ) 39  
2008   54   (13 ) 41  
2009   54   (12 ) 42  
2010   53   (12 ) 41  
2011   55   (12 ) 43  
2012 and thereafter   731   (18 ) 713  
Total   999   (80 ) 919  

The operating lease agreements for premises, services and equipment expire at various dates through 2016, with an option to renew certain lease agreements for three to 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, 2006 was $25 million (2005 – $17 million; 2004 – $7 million).

Bruce Power

TCPL's share of Bruce A's signed commitments to third party suppliers for the next four years for the restart and refurbishment of the currently idle Units 1 and 2, extending the operating life of Unit 3 by replacing its steam generators and fuel channels when required, and replacing the steam generators on Unit 4, is as follows.

Year ended December 31 (millions of dollars)      
2007   450  
2008   164  
2009   71  
2010   1  
2011   –  
    686  

In addition to these capital commitments, the Company is committed to capital expenditures of approximately $1.2 billion for the construction of its Halton Hills, Portlands Energy and remaining Cartier Wind projects.

TCPL has guaranteed the performance of all obligations of PipeLines LP with respect to its acquisition of a 46.45 per cent interest in Great Lakes pursuant to the purchase agreement.

Aboriginal Pipeline Group

On June 18, 2003, the Mackenzie Delta gas producers, the APG and TCPL reached an agreement which governs TCPL's role in the MGP Project. The project would result in a natural gas pipeline being constructed from Inuvik, Northwest Territories, to the northern border of Alberta, where it would connect with the Alberta System. Under the agreement, TCPL agreed to finance the APG for its one-third share of project development costs. These costs are currently forecasted to be approximately $145 million by the end of 2007.

Contingencies

The Canadian Alliance of Pipeline Landowners' Associations (CAPLA) and two individual landowners commenced an action in 2003 under Ontario's Class Proceedings Act, 1992, against TCPL and Enbridge Inc. for damages of $500 million alleged to arise from the creation of a control zone within 30 metres of the pipeline pursuant to Section 112 of the NEB Act. In November 2006, TCPL and Enbridge Inc. were granted a dismissal of the case but CAPLA has appealed that decision. The Company continues to believe 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 109

Guarantees

The Company, together with Cameco Corporation and BPC Generation Infrastructure Trust (BPC), has severally guaranteed one-third of certain contingent financial obligations of Bruce B related to power sales agreements, operator licenses, the lease agreement and contractor services. The terms of the guarantees range from 2007 to 2018.

As part of the reorganization of Bruce Power in 2005, including the formation of Bruce A and the commitment to restart and refurbish the Bruce A units, the Company, together with BPC, severally guaranteed one-half of certain contingent financial obligations of Bruce A related to the refurbishment agreement with the Ontario Power Authority and cost sharing and sublease agreements with Bruce B. The terms of the guarantees range from 2019 to 2036.

TCPL's share of the exposure under these Bruce Power guarantees at December 31, 2006 was estimated to be approximately $586 million to a calculated maximum of $658 million. The current carrying amount of the liability related to these guarantees is nil and the fair value is approximately $17 million.

TCPL has guaranteed the equity undertaking of a subsidiary which supports the payment, under certain conditions, of principal and interest on US$105 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 TCPL under this agreement convert into share capital of TransGas. The potential exposure is contingent on the impact of any change of law on TransGas' ability to service the debt. From the issuance of the debt in 1995 to date, there has been no change in applicable law and thus no exposure to TCPL. The debt matures in 2010. The Company has made no provision related to this guarantee.

In connection with the acquisition of GTN, US$241 million of the purchase price was deposited into an escrow account. At December 31, 2006, there was US$24 million remaining in the escrow account which represented the full face amount of the potential liability under certain GTN guarantees. In February 2007, the funds were released and a portion of the monies were used to satisfy the liability of GTN under these designated guarantees.

NOTE 23    DISCONTINUED OPERATIONS

TCPL's net income for the year ended December 31, 2006 includes $28 million or $0.06 per share of net income from discontinued operations reflecting settlements received from bankruptcy claims related to TCPL's Gas Marketing business divested in 2001 (2005 – nil; 2004 – $52 million net of $27 million of income taxes)

NOTE 24    SUBSEQUENT EVENTS

On February 22, 2007, TCPL closed the acquisition of the American Natural Resources Company and the ANR Storage Company (together ANR), and an additional 3.55 per cent interest in Great Lakes from El Paso Corporation for approximately US$3.4 billion, subject to certain post-closing adjustments, including approximately US$488 million of assumed long-term debt. The acquisition was financed with a combination of proceeds from the Company's issuance of $1.3 billion of common shares, cash on hand and funds drawn on existing and newly established loan facilities, discussed below.

In February 2007, TCPL issued $1.3 billion of common shares to TransCanada to partially finance the acquisition of ANR.

In February 2007, the Company through a wholly owned subsidiary, executed an agreement with a syndicate of banks to establish a new US$1.0 billion credit facility, consisting of a US$700 million five-year term loan and a US$300 million five-year extendible revolving facility. This facility is committed and unsecured. The Company utilized US$1.0 billion from this facility and an additional US$100 million from an existing demand line to partially finance the ANR acquisitions as well addtional investments in PipeLines LP; described below.

Great Lakes Acquisition

On February 22, 2007, PipeLines LP closed its acquisition of a 46.45 per cent interest in Great Lakes from El Paso Corporation for approximately US$962 million, which included approximately US$212 million of assumed long-term debt, subject to certain post-closing adjustments. At December 31, 2006, TCPL had a 13.4 per cent interest in PipeLines LP.

In February 2007, PipeLines LP increased the size of its syndicated revolving credit and term loan agreement from US$410 million to US$950 million. Incremental draws of approximately US$126 million received under this agreement were used to partially finance PipeLines LP's Great Lakes acquisition.

On February 22, 2007, PipeLines LP completed a private placement offering of 17,356,086 common units at a price of US$34.57 per unit, of which 50 per cent of the units were acquired by TCPL, for US$300 million. TCPL also invested an additional approximately US$12 million to maintain its general partnership interest in PipeLines LP. As a result of TCPL's additional investments in PipeLines LP, its ownership in PipeLines LP increased to 32.1 per cent. The total private placement resulted in gross proceeds to PipeLines LP of approximately US$612 million, which were used to partially finance its Great Lakes acquisition. As a result of TCPL's increased ownership in PipeLines LP, TCPL's effective ownership in Tuscarora, Northern Border and Great Lakes increased to 32.5 per cent (including one per cent held directly), 16.1 per cent and 68.5 per cent, respectively.

110 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEVEN YEAR FINANCIAL HIGHLIGHTS

(millions of dollars except where indicated)   2006   2005   2004   2003   2002   2001   2000  
 
Income Statement                              
Revenues   7,520   6,124   5,497   5,636   5,225   5,285   4,384  
Net income from continuing operations   1,071   1,230   1,000   823   769   708   663  
Net income   1,099   1,230   1,052   873   769   641   724  
Net income/(loss) by segment                              
  Pipelines   560   679   584   625   639   572   613  
  Energy   452   566   398   217   160   181   95  
  Corporate   37   (37 ) (4 ) (41 ) (52 ) (67 ) (80 )
  Continuing operations   1,049   1,208   978   801   747   686   628  
  Discontinued operations   28   –   52   50   –   (67 ) 61  
Net income applicable to common shares   1,077   1,208   1,030   851   747   619   689  

Cash Flow Statement
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Funds generated from operations   2,374   1,950   1,701   1,822   1,843   1,625   1,484  
(Increase)/decrease in operating working capital   (300 ) (48 ) 28   93   92   (487 ) 437  
 
Net cash provided by continuing operations   2,074   1,902   1,729   1,915   1,935   1,138   1,921  
Capital expenditures and acquisitions   (2,042 ) (2,071 ) (2,046 ) (965 ) (851 ) (1,082 ) (1,144 )
Disposition of assests, net of current tax   23   671   410   –   –   1,170   2,233  
Dividends on common and preferred shares   (639 ) (608 ) (574 ) (532 ) (488 ) (440 ) (458 )

Balance Sheet
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets                              
Plant, property and equipment                              
  Pipelines   17,141   16,528   17,306   16,064   16,158   16,562   16,937  
  Energy   4,302   3,483   1,421   1,368   1,340   1,116   776  
  Corporate   44   27   37   50   64   66   111  
Total assets                              
  Continuing operations   25,908   24,113   22,414   20,873   20,416   20,255   20,238  
  Discontinued operations   –   –   7   11   139   276   5,007  
 
    25,908   24,113   22,421   20,884   20,555   20,531   25,245  

Capitalization
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term debt   10,887   9,640   9,749   9,516   8,899   9,444   10,008  
Long-term debt of joint ventures   1,136   937   808   741   1,193   1,262   1,280  
Preferred securities   536   536   554   598   944   950   1,208  
Non-controlling interests   366   394   311   324   288   286   257  
Preferred shares   389   389   389   389   389   389   389  
Common shareholders' equity   7,618   7,164   6,484   6,044   5,747   5,426   5,211  
                               

SUPPLEMENTARY INFORMATION 111

Per Common Share Data (dollars)                              
Net income – Basic                              
  Continuing operations   $2.17   $2.50   $2.03   $1.66   $1.56   $1.44   $1.32  
  Discontinued operations   0.06   –   0.11   0.11   –   (0.14 ) 0.13  
 
    $2.23   $2.50   $2.14   $1.77   $1.56   $1.30   $1.45  
 
Net income – Diluted                              
  Continuing operations   $2.17   $2.50   $2.03   $1.66   $1.55   $1.44   $1.32  
  Discontinued operations   0.06   –   0.11   0.11   –   (0.14 ) 0.13  
 
    $2.23   $2.50   $2.14   $1.77   $1.55   $1.30   $1.45  
 
Dividends declared   $1.28   $1.23   $1.17   $1.08   $1.00   $0.90   $0.80  

Per Preferred Share Data (dollars)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Series U Cumulative First Preferred Shares   $2.80   $2.80   $2.80   $2.80   $2.80   $2.80   $2.80  
Series Y Cumulative First Preferred Shares   $2.80   $2.80   $2.80   $2.80   $2.80   $2.80   $2.80  

Financial Ratios
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Earnings to fixed charges(1)   2.6   2.9   2.5   2.3   2.3   2.1   1.9  
(1)
The ratio of earnings to fixed charges is determined by dividing the financial charges incurred by the company (including capitalized interest) into its income from continuing operations before financial charges and income taxes, excluding undistributed income from equity investees.

112 SUPPLEMENTARY INFORMATION

GRAPHIC

GRAPHIC

TRANSCANADA PIPELINES LIMITED
RECONCILIATION TO UNITED STATES GAAP

December 31, 2006

AUDIT REPORT ON RECONCILIATION TO UNITED STATES GAAP

To the Board of Directors of TransCanada PipeLines Limited

        On February 22, 2007, we reported on the consolidated balance sheets of TransCanada PipeLines Limited as at December 31, 2006 and 2005 and the consolidated statements of income, retained earnings and cash flows for each of the years in the three-year period ended December 31, 2006 which are included in the Annual Report on Form 40-F.

        In connection with our audits conducted in accordance with Canadian generally accepted auditing standards and also in accordance with the Standards of the Public Company Accounting Oversight Board (United States) of the afore-mentioned consolidated financial statements, we also have audited the related supplemental note entitled "Reconciliation to United States GAAP" included in the Form 40-F. This supplemental note is the responsibility of the Company's management. Our responsibility is to express an opinion on this supplemental note based on our audits.

        In our opinion, such supplemental note, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ KPMG LLP

Chartered Accountants

Calgary, Canada
February 22, 2007

TRANSCANADA PIPELINES LIMITED
RECONCILIATION TO UNITED STATES GAAP

        The 2006 audited consolidated financial statements of TransCanada Pipelines Limited (TCPL or the Company) have been prepared in accordance with Canadian generally accepted accounting principles (GAAP), which in some respects, differ from U.S. GAAP. The effects of these differences on the Company's consolidated financial statements for the year ended December 31, 2006 are provided in the following U.S. GAAP condensed consolidated financial statements which should be read in conjunction with TCPL's 2006 audited consolidated financial statements prepared in accordance with Canadian GAAP.

Condensed Statement of Consolidated Income and Comprehensive Income in Accordance with U.S. GAAP(1)

Year ended December 31 (millions of dollars)
  2006
   2005
   2004
  
Revenues   5,997   5,333   5,014  
   
 
 
 
Plant operating costs and other   1,922   1,730   1,618  
Commodity purchases resold   1,369   904   777  
Depreciation   897   924   857  
   
 
 
 
    4,188   3,558   3,252  
   
 
 
 
    1,809   1,775   1,762  
   
 
 
 
Other (income)/expenses              
  Income from equity investments(1)   (478 ) (458 ) (402 )
  Other expenses(2)(3)   745   401   852  
  Dilution gain(3)   —   —   (40 )
  Income taxes   472   607   490  
   
 
 
 
    739   550   900  
   
 
 
 
Income from continuing operations — U.S. GAAP   1,070   1,225   862  
Net income from discontinued operations — U.S. GAAP   28   —   52  
   
 
 
 
Net Income in Accordance with U.S. GAAP   1,098   1,225   914  
Adjustments affecting comprehensive income under U.S. GAAP              
  Foreign currency translation adjustment, net of tax   (1 ) (18 ) (31 )
  Changes in minimum pension liability, net of tax(4)   63   (51 ) 72  
  Change in funding of postretirement plan liability, net of tax(4)   (78 ) —   —  
  Changes in equity investment postretirement plan liability, net of tax(4)   (154 ) —   —  
  Unrealized (loss)/gain on derivatives, net of tax(5)   (24 ) (54 ) 1  
   
 
 
 
Comprehensive Income in Accordance with U.S. GAAP   904   1,102   956  
   
 
 
 

Reconciliation of Income from Continuing Operations

Year ended December 31 (millions of dollars)
  2006
   2005
   2004
  
Net Income from Continuing Operations in Accordance with Canadian GAAP   1,071   1,230   1,000  
U.S. GAAP adjustments              
  Unrealized gain/(loss) on energy contracts(5)   (6 ) (14 ) 10  
  Tax impact of unrealized gain/(loss) on energy contracts   3   5   (3 )
  Equity investment gain/(loss)(6)(7)   1   5   (2 )
  Tax impact of equity investment gain/(loss)   —   (1 ) —  
  Unrealized gain/(loss) on foreign exchange and interest rate derivatives(5)   1   1   (12 )
  Tax impact of gain/(loss) on foreign exchange and interest rate derivatives   —   (1 ) 4  
  Amortization of deferred gains related to Power LP(3)   —   —   (3 )
  Deferred gains related to Power LP(3)   —   —   (132 )
   
 
 
 
Income from Continuing Operations in Accordance with U.S. GAAP   1,070   1,225   862  
   
 
 
 

Condensed Statement of Consolidated Cash Flows in Accordance with U.S. GAAP(1)

Year ended December 31 (millions of dollars)
  2006
   2005
   2004
  
Cash Generated from Operations(8)              
Net cash provided by operating activities   1,885   1,627   1,617  

Investing Activities
 
 
 
 
 
 
 
Net cash used in investing activities   (1,920 ) (1,169 ) (1,356 )

Financing Activities
 
 
 
 
 
 
 
Net cash provided by/(used in) financing activities   234   (514 ) (340 )
Effect of Foreign Exchange Rate Changes on Cash and Short-Term Investments   7   13   (87 )
   
 
 
 
Increase/(Decrease) in Cash and Short-Term Investments   206   (43 ) (166 )

Cash and Short-Term Investments
 
 
 
 
 
 
 
Beginning of year   83   126   292  

Cash and Short-Term Investments
 
 
 
 
 
 
 
   
 
 
 
End of year   289   83   126  
   
 
 
 

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

December 31 (millions of dollars)
  2006
   2005
Current assets(9)   1,550   1,058
Long-term investments(4)(6)(7)   2,922   2,168
Plant, property and equipment   17,430   17,348
Regulatory asset(4)(10)   2,199   2,601
Other assets(4)(6)   1,720   2,028
   
 
    25,821   25,203
   
 
Current liabilities(4)(11)   2,623   2,797
Deferred amounts(4)(5)(7)   986   1,298
Long-term debt(5)   10,913   9,675
Deferred income taxes(4)(10)   2,734   3,102
Preferred securities   536   536
Non-controlling interests   366   394
Shareholders' equity(4)   7,663   7,401
   
 
    25,821   25,203
   
 

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

(millions of dollars)
  Under-funded Postretirement Plan Liability (SFAS No. 158)
   Cumulative Translation Account
   Minimum Pension Liability (SFAS No. 87)
   Cash Flow Hedges (SFAS No. 133)
   Total
  
Balance at January 1, 2004   —   (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 )

Changes in minimum pension liability, net of tax of $27(4)
 
—
 
—
 
(51
)
—
 
(51
)
Unrealized loss on derivatives, net of tax of $28(5)   —   —   —   (54 ) (54 )
Foreign currency translation adjustment, net of tax of $(21)   —   (18 ) —   —   (18 )
   
 
 
 
 
 
Balance at December 31, 2005   —   (89 ) (77 ) (58 ) (224 )

Change in minimum pension liability, net of tax of $(35)(4)
 
—
 
—
 
63
 
—
 
63
 
Reversal of minimum pension liability, due to adoption of SFAS No 158   (14 ) —   14   —   —  
Change in funding of postretirement plan liability, net of tax of $35(4)   (78 ) —   —   —   (78 )
Change in equity investment postretirement plan liability, net of tax of $70(4)   (154 ) —   —   —   (154 )
Unrealized gain on derivatives, net of tax of $11(5)   —   —   —   (24 ) (24 )
Foreign currency translation adjustment, net of tax of $1   —   (1 ) —   —   (1 )
   
 
 
 
 
 
Balance at December 31, 2006   (246 ) (90 ) —   (82 ) (418 )
   
 
 
 
 
 
(1)
In accordance with U.S. GAAP, the Condensed Statement of Consolidated Income, Statement of Consolidated Cash Flows, Consolidated Balance Sheet and Statement of Other Comprehensive Income of TCPL are prepared using the equity method of accounting for joint ventures.

(2)
Other expenses include an allowance for funds used during construction of $9 million for the year ended December 31, 2006 (2005 — $3 million; 2004 — $3 million).

(3)
The Company recorded its investment in TransCanada Power, L.P. (Power LP) using the proportionate consolidation method for Canadian GAAP purposes and as an equity investment for U.S. GAAP purposes. During the period from 1997 to April 2004, the Company was obligated to fund the redemption of Power LP units in 2017. As a result, under Canadian GAAP, TCPL accounted for the issuance of units by Power LP to third parties as a sale of a future net revenue stream and the resulting gains were deferred and amortized to income over the period to 2017. The redemption obligation was removed in April 2004 and the unamortized gains were recognized as income. Under U.S. GAAP, any such gains in the period from 1997 to April 2004 are characterized as dilution gains and, because the Company was committed to fund the redemption of the units, the gains are recorded, on an after-tax basis, as equity transactions in shareholders' equity.


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

(4)
In September 2006, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 158 "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans" which amended FASB Statements No. 87, 88, 106 and 132(R). For the Company's U.S. GAAP financial statements, SFAS No. 158 became effective for as at December 31, 2006. Retrospective application of SFAS No. 158 is not permitted.


SFAS No. 158 requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability in its statement of financial position and to recognize changes in that funded status, through comprehensive income, in the year in which the changes occur. The amounts recognized in the Company's balance sheet as at December 31, 2006 are as follows.

December 31 (millions of dollars)
  2006
Non-current assets   10
Current liabilities   5
Non-current liabilities   220
   
    215
   

Pre-tax amounts recognized in accumulated other comprehensive income are as follows.

December 31 (millions of dollars)
  Pension Benefits 2006
   Other Benefits 2006
  
Net loss   92   14  
Prior service cost (credit)   11   (4 )
   
 
 
    103   10  
   
 
 

The funded status based on the accumulated benefit obligation for all defined benefit pension plans as at December 31, 2006 is as follows.

December 31 (millions of dollars)
  2006
   2005
  
Accumulated benefit obligation   1,167   1,123  
Fair value of plan assets   1,264   1,096  
   
 
 
Funded Status — surplus/(deficit)   97   (27 )
   
 
 

Included in the above accumulated benefit obligation and fair value of plan assets as at December 31, 2006 are the following amounts in respect of plans that are not fully funded.

December 31 (millions of dollars)
  2006
   2005
  
Accumulated benefit obligation   67   1,105  
Fair value of plan assets   65   1,075  
   
 
 
Funded Status — (deficit)   (2 ) (30 )
   
 
 

The estimated net loss and prior service cost for the defined benefit pension plans that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year are $9 million and $1 million, respectively. The estimated prior service credit for the other defined benefit postretirement plans that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year is $1 million.


Incremental Effect of Applying SFAS No. 158 on Individual Line Items in the Balance Sheet

December 31, 2006 (millions of dollars)
  Before Application of SFAS 158
   Adjustments
   After Application of SFAS 158
  
Long-term investments   3,076   (154 ) 2,922  
Regulatory asset   1,961   238   2,199  
Other assets   1,945   (225 ) 1,720  
Current liabilities   2,618   5   2,623  
Deferred amounts   865   121   986  
Deferred income taxes   2,769   (35 ) 2,734  
Accumulated other comprehensive income   (186 ) (232 ) (418 )
Total shareholders' equity   7,895   (232 ) 7,663  


Pursuant to Statement of Financial Accounting Standards (SFAS) No. 87 "Employers' Accounting for Pensions", a net loss recognized as an additional pension liability and not yet recognized as net period pension cost must be recorded as a component of comprehensive income. As a result of recording an additional pension liability, the amounts recognized in the Company's balance sheet as at December 31, 2005 are as follows. The loss for 2006 is included in the amounts in the table above.

December 31 (millions of dollars)
  2005
  
Prepaid benefit cost   6  
Regulatory asset   107  
Other assets   37  
Accounts payable   (70 )
Deferred amounts   (17 )
Accumulated other comprehensive income   118  
   
 
Net amount recognized   181  
   
 

The accumulated benefit obligation for the Company's defined benefit pension plans was $1,167 million at December 31, 2006 (2005 — $1,123 million).


The rate used to discount pension and other post-retirement benefit plan obligations was based on a yield curve from Moody's corporate AA bond yields at December 31, 2006 developed by our third party actuary. This yield curve is used to develop spot rates that vary based on the duration of the obligations. The estimated future cash flows for the pension and other post retirement obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate.

(5)
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 also recognized in earnings each period. Substantially all of the amounts recorded in 2006, 2005 and 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 2006, under the provisions of SFAS 133, net gains of $6 million (2005 — $8 million; 2004 — $10 million) from the hedges of changes in the fair value of long-term debt, and net losses of $5 million (2005 — $8 million; 2004 — $18 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 significant amounts were included in income in 2006, 2005 and 2004 with respect to ineffectiveness of cash flow hedges. For amounts included in other comprehensive income at December 31, 2006, nil (2005 — $4 million; 2004 — $(4) million) relates to the hedging of interest rate risk; $(1) million (2005 — $(1) million; 2004 — $3 million) relates to the hedging of foreign exchange rate risk; and $(23) million (2005 — $(57) million; 2004 — $2 million) relates to the hedging of energy price risk. In 2007, $(66) million is expected to be recorded in earnings.


At December 31, 2006, assets of $160 million (2005 — $175 million) and liabilities of $69 million (2005 — $110 million) were reduced for U.S. GAAP purposes to reflect the fair value of derivatives and the corresponding change in the fair value of hedged items.

(6)
Under 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. (Bruce B), an equity investment, were 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 B, under U.S. GAAP, the carrying value of development projects against which interest is capitalized is lower due to the expensing of certain pre-operating costs.

(7)
Financial Interpretation (FIN) 45 requires 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, 2006 was $17 million (2005 — $17 million) and relates to the Company's equity interest in Bruce B and Bruce Power A L.P. The net income impact with respect to the guarantees for the year ended December 31, 2006 was $1 million (2005 — $1 million; 2004 — nil).

(8)
In accordance with U.S. GAAP, all current taxes are included in cash generated from operations.

(9)
Current assets at December 31, 2006 include derivative contracts of $18 million (2005 — $49 million) and hedging deferrals of $131 million (2005 — $93 million).

(10)
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.

(11)
Current liabilities at December 31, 2006 include dividends payable of $162 million (2005 — $154 million), current taxes payable of $71 million (2005 — $251 million), derivative contracts of $133 million (2005 — $95 million) and hedging deferrals of $15 million (2005 — $44 million).

Income Taxes

        The income tax effects of differences between the accounting value and the tax value of assets and liabilities are as follows.

December 31 (millions of dollars)
  2006
   2005
Deferred Tax Liabilities        
Difference in accounting and tax bases of plant, equipment and power purchase arrangements   1,478   1,718
Taxes on future revenue requirement   606   874
Investments in subsidiaries and partnerships   683   561
Pension Benefit   25   15
Other   127   143
   
 
    2,919   3,311
   
 

Deferred Tax Assets
 
 
 
 
Deferred amounts   71   140
Other Post-employment benefits   16   13
Other   112   70
   
 
    199   223
Less: Valuation allowance   14   14
   
 
    185   209
   
 
Net deferred tax liabilities   2,734   3,102
   
 

Other

        In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123 (revised 2004) "Share-Based Payment" which requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values. The pro forma disclosures previously permitted under SFAS No. 123 will no longer be an alternative to financial statement recognition. In 2002, TCPL adopted accounting for its stock-based compensation plans using the fair value recognition provisions under Canadian GAAP. Therefore, adopting the provisions under SFAS No 123 (revised 2004) had no impact on the U.S. GAAP financial statements of the Company.

        In March 2005, FASB issued a Staff Position (FSP) on a previously issued FIN. The provisions of FSP FIN 46 (R)-5 "Implicit Variable Interests under revised FIN 46(R), Consolidation of Variable Interest Entities" require that a reporting enterprise consider consolidating implicit variable interests when applying the provisions of FIN 46(R). Adopting these provisions had no impact on the U.S. GAAP financial statements of the Company.

        In March 2005, FASB issued FIN 47 "Accounting for Conditional Asset Retirement Obligations — an interpretation of FASB No.143". FIN 47 clarifies that the term "conditional asset retirement obligation" as used in SFAS No. 143, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. It also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. Adopting the clarification under this interpretation had no impact on the U.S. GAAP financial statements of the Company.

        In May 2005, FASB issued SFAS No. 154 "Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and SFAS No. 3" which was effective for fiscal years beginning after December 15, 2005. SFAS No. 154 changes the requirements for the accounting for and reporting of a change in accounting principle and error correction. It establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to the newly adopted accounting principle. Adopting the provisions under SFAS No. 154 as of January 1, 2006 had no impact on the U.S. GAAP financial statements of the Company.

        In February 2006, FASB issued SFAS No. 155 "Accounting for Certain Hybrid Financial Instruments — an amendment of SFAS No. 133 and 140" which is effective for fiscal years beginning after September 15, 2006. SFAS No. 155 permits fair value remeasurement of any hybrid instrument that contains an embedded derivative that otherwise would require bifurcation. TCPL is in the process of assessing the impact of the application of SFAS 155 on its U.S. GAAP financial statements.

        In March 2006, FASB issued SFAS No. 156 "Accounting for Servicing of Financial Assets — an amendment of FASB Statement No. 140" which is effective for fiscal years beginning after September 15, 2006. SFAS No. 156 requires recognition of a servicing asset or liability when an entity enters into arrangements to service financial instruments in certain situations. Such servicing assets or servicing liabilities are required to be initially measured at fair value, if practicable. SFAS No. 156 also allows an entity to subsequently measure its servicing assets or servicing liabilities using either an amortization method or a fair value method. Adopting the provisions under SFAS No. 156 as of January 1, 2007 is not expected to have an impact on the U.S. GAAP financial statements of the Company.

        In July 2006, FASB issued FIN 48 "Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109" which is effective for fiscal years beginning after December 15, 2006. This Interpretation provides guidance for the financial statement recognition, measurement, presentation and disclosure of uncertain tax positions taken or expected to be taken in income tax returns. Adopting the provisions under FIN 48, as of January 1, 2007 is not expected to have a material impact on the U.S. GAAP financial statements of the Company.

        In September 2006, FASB issued SFAS No. 157 "Fair Value Measurements" which is effective for fiscal years beginning after November 15, 2007. This statement defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. TCPL is in the process of assessing the impact of the application of SFAS No. 157 on its U.S. GAAP financial statements.

        In September 2006, FASB issued SFAS No. 158 "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R)", which is effective for fiscal years ending after December 15, 2006. This statement requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability on its balance sheet and to recognize changes in the funded status in the year in which the changes occur through comprehensive income. The plan assets and benefit obligations will be measured as of the balance sheet date. The impact of adopting SFAS No. 158 is shown in the footnotes to the Statement of Other Comprehensive Income in Accordance with U.S. GAAP.

        In September 2006, the SEC staff issued SAB Topic 1N, "Financial Statements — Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements" (SAB No. 108), which addresses how to quantify the effect of an error on the financial statements. SAB No. 108 is effective for fiscal years ending December 31, 2006. Adopting these provisions did not have an 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)
  2006
   2005
   2004
  
Income              
Revenues   1,450   1,233   1,249  
Plant operating costs and other   (697 ) (508 ) (594 )
Depreciation   (175 ) (173 ) (173 )
Financial charges and other   (100 ) (94 ) (80 )
   
 
 
 
Proportionate share of income before income taxes of long-term investments   478   458   402  
   
 
 
 
 
December 31 (millions of dollars)
  2006
   2005
    
Balance Sheet            
Current assets   446   456    
Plant, property and equipment   4,177   3,365    
Other assets (net)   198   —    
Current liabilities   (445 ) (319 )  
Deferred amounts (net)   (235 ) (73 )  
Non-recourse debt   (1,266 ) (1,236 )  
Deferred income taxes   47   (25 )  
   
 
   
Proportionate share of net assets of long-term investments   2,922   2,168    
   
 
   

        The distributed earnings from long-term investments for the year ended December 31, 2006 were $494 million (2005 — $371 million; 2004 — $258 million). The undistributed earnings from long-term investments for the year ended December 31, 2006 were $836 million (2005 — $820 million; 2004 — $767 million).

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

        The management of TransCanada PipeLines Limited ("TCPL") is responsible for establishing and maintaining adequate internal control over financial reporting, and have designed such internal control over financial reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian generally accepted accounting principles (GAAP), including a reconciliation to United States GAAP.

        Management has used the Internal Control — Integrated Framework to evaluate the effectiveness of internal control over financial reporting, which is a recognized and suitable framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

        Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

        Management has evaluated the design and operation of TCPL's internal control over financial reporting as of December 31, 2006, and has concluded that such internal control over financial reporting is effective. There are no material weaknesses that have been identified by management in this regard.

        KPMG LLP, the independent auditors appointed by the shareholders of TCPL, who have audited the consolidated financial statements of TCPL, have also audited management's assessment of internal controls over financial reporting and have issued the report entitled "Audit Report of Independent Registered Public Accounting Firm".

February 22, 2007    

/s/  HAROLD N. KVISLE      
Harold N. Kvisle
President and
Chief Executive Officer
 
/s/  GREGORY A. LOHNES      
Gregory A. Lohnes
Executive Vice-President and
and Chief Financial Officer

AUDIT REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of TransCanada PipeLines Limited

        We have audited management's assessment, included in the accompanying management's report of internal control over financial reporting, that TransCanada PipeLines Limited maintained effective internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for maintaining effective internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

        We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

        A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and the receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

        Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

        In our opinion, management's assessment that the Company maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of Treadway Commission (COSO). Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of Treadway Commission (COSO).

        We also have conducted our audits on the consolidated financial statements in accordance with Canadian generally accepted auditing standards. With respect to the years ended December 31, 2006 and 2005, we also have conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our report dated February 22, 2007 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Chartered Accountants

Calgary, Canada
February 22, 2007

COMMENTS BY AUDITORS FOR UNITED STATES READERS ON CANADA-UNITED STATES REPORTING DIFFERENCES

To the Board of Directors of TransCanada PipeLines Limited

        In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) that refers to the audit report on the effectiveness of the Company's internal control over financial reporting. Our report to the shareholders dated February 22, 2007 is expressed in accordance with Canadian reporting standards, which do not require a reference to the audit report on the effectiveness of the Company's internal control over financial reporting in the financial statement auditors' report.

/s/ KPMG LLP

Chartered Accountants

Calgary, Canada
February 22, 2007



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TRANSCANADA PIPELINES LIMITED ANNUAL INFORMATION FORM FEBRUARY 22, 2007
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