40-F

QuickLinks -- Click here to rapidly navigate through this document

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, 2007        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; (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: None

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, 2007, 4,000,000 Cumulative Redeemable First Preferred Shares Series U
and 4,000,000 Cumulative Redeemable First Preferred Shares Series Y
were issued and outstanding
All of the Registrant's common shares are owned by TransCanada Corporation.

Indicate by check mark whether the Registrant by filing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934 (the "Exchange Act"). If "Yes" is marked, indicate the file number assigned to the Registrant in connection with such Rule.    Yes o            No ý

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or such shorter period that the Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.     Yes ý            No o

The following document is hereby filed with the Securities and Exchange Commission for the purpose of being and hereby is incorporated by reference into Registration Statement on Form F-9 (File No. 333-145980) of TransCanada PipeLines Limited.

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

A.    Audited Annual Financial Statements

For consolidated audited financial statements, including the report of the independent chartered accountants, see pages 72 through 126 of the TransCanada PipeLines Limited ("TCPL") 2007 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 71 of the TCPL 2007 Management's Discussion and Analysis and Audited Consolidated Financial Statements included herein.

For the purposes of this Report, only pages 2 through 71 and 72 through 126 of the TCPL 2007 Management's Discussion and Analysis and Audited Consolidated Financial Statements shall be deemed incorporated herein by reference and filed, and the balance of such 2007 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 U.S. Securities and Exchange Commission (the "Commission") as part of this Report under the Exchange Act.

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

For information on management's internal control over financial reporting, see:

i.

"Report of Management" included in TCPL's consolidated audited financial statements on page 72;



ii.

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 60 of the TCPL Management's Discussion and Analysis and Audited Consolidated Financial Statements; and



iii.

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

The effectiveness of internal control over financial reporting as of December 31, 2007 has been audited by TCPL's independent auditors, KPMG LLP, a registered public accounting firm, as stated in their audit report. KPMG LLP has issued a report on the effectiveness of internal control over financial reporting as of December 31, 2007, 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 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 60 of the TCPL 2007 Management's Discussion and Analysis and Audited Consolidated Financial Statements.

2

AUDIT COMMITTEE FINANCIAL EXPERT

The Registrant's board of directors has determined that it has at least one audit committee financial expert serving on its audit committee. Mr. Kevin E. Benson 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. Benson as an audit committee financial expert does not make Mr. Benson an "expert" for any purpose, impose any duties, obligations or liability on Mr. Benson 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 2007 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 2007 and 2006 fiscal years are shown in the table below:

Fees in millions of Canadian dollars		2007	(1)		2006	(1)
Audit Fees	$	6.27		$	6.52
Audit-Related Fees		0.07			0.07
Tax Fees		0.06			0.22
All Other Fees		0.00			0.07
Total	$	6.40		$	6.88

⁽¹⁾

The disclosure of audit fees paid has been revised to be based on aggregate fees billed during the fiscal year as opposed to aggregate fees for professional services rendered during the fiscal year. For comparison purposes, both the 2007 and the 2006 amounts have been disclosed based on the aggregate fees billed during the year.

The nature of each category of fees is described below.

Audit Fees

Aggregate fees for audit services rendered for the audit of the annual consolidated 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

Aggregate fees for assurance and related services that are reasonably related to performance of the audit or review of the consolidated financial statements and are not reported as Audit Fees. The nature of services comprising these fees is related to the audit of the financial statements of certain pension plans.

Tax Fees

Aggregate fees for primarily tax compliance and tax advice. The nature of these services consisted of: tax compliance including the review of 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.

3

All Other Fees

Aggregate fees for products and services other than those reported elsewhere in this table. The nature of these services consisted of advice related to compliance with the United States 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 24 of the Notes to the Audited Consolidated Financial Statements which are 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 48 of the TCPL 2007 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: K.E. Benson
D.H. Burney
P. Gauthier
P.L. Joskow
J.A. MacNaughton

4

FORWARD-LOOKING INFORMATION

This document, the documents incorporated by reference, and other reports and filings made with the securities regulatory authorities may contain certain information that is forward-looking and is subject to important risks and uncertainties. The words "anticipate", "expect", "believe", "may", "should", "estimate", "project", "outlook", "forecast" or other similar words are used to identify such forward looking information. All forward-looking statements reflect TCPL's beliefs and assumptions based on information available at the time the statements were made. Actual results or events may differ from those predicted in these forward-looking statements. Factors that 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 operating performance of the Company's natural gas pipeline and energy assets, the availability and price of energy commodities, regulatory processes and decisions, changes in environmental and other laws and regulations, competitive factors in the natural gas pipeline and energy industry sectors, construction and completion of capital projects, labour, equipment and material costs, access to capital markets, interest and currency exchange rates, technological developments and the current economic conditions in North America. By its nature, 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. The Company's material risks and assumptions are discussed further in TCPL's Management's Discussion and Analysis filed as document 13.2 hereto including under the headings "Pipelines — Opportunities and Developments", "Pipelines — Business Risks", "Energy — Opportunities and Developments", "Energy — Business Risks" and "Risk Management and Financial Instruments". Additional information on these and other factors is available in the reports filed by TCPL with Canadian securities regulators and with the U.S. Securities and Exchange Commission ("SEC"). 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 to not use future-oriented information or financial outlooks for anything other than their intended purpose. 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.

5

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, 2008

DOCUMENTS FILED AS PART OF THIS REPORT

13.1	Annual Information Form for the year ended December 31, 2007.
13.2	Management's Discussion and Analysis (included on pages 2 through 71 of the TCPL 2007 Management's Discussion and Analysis and Audited Consolidated Financial Statements).
13.3	2007 Audited Consolidated Financial Statements (included on pages 72 through 126 of the TCPL 2007 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 the Independent Registered Public Accounting Firm on the effectiveness of TCPL's Internal Control Over Financial Reporting as at December 31, 2007.
99.1	Comments by Auditors for United States Readers on Canada—United States Reporting Differences.

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.

TRANSCANADA PIPELINES LIMITED

ANNUAL INFORMATION FORM

February 25, 2008

TRANSCANADA PIPELINES LIMITED i

TABLE OF CONTENTS

	Page
TABLE OF CONTENTS	i
PRESENTATION OF INFORMATION	ii
FORWARD-LOOKING INFORMATION	ii
TRANSCANADA PIPELINES LIMITED	1
Corporate Structure	1
GENERAL DEVELOPMENT OF THE BUSINESS	2
Developments in the Pipelines Business	2
Developments in the Energy Business	4
BUSINESS OF TCPL	6
Pipelines Business	6
Regulation of the Pipeline Business	8
Energy Business	8
HEALTH, SAFETY AND ENVIRONMENT RISK MANAGEMENT	10
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	11
TRANSFER AGENT AND REGISTRAR	11
INTEREST OF EXPERTS	11
RISK FACTORS	12
DIVIDENDS	12
DESCRIPTION OF CAPITAL STRUCTURE	12
DEBT	13
CREDIT RATINGS	13
MARKET FOR SECURITIES	14
DIRECTORS AND OFFICERS	15
CORPORATE GOVERNANCE	18
Audit Committee	18
Other Board Committees	19
Conflicts of Interest	20
INDEBTEDNESS OF DIRECTORS AND EXECUTIVE OFFICERS	20
SECURITIES OWNED BY DIRECTORS	20
COMPENSATION OF DIRECTORS	21
MINIMUM SHARE OWNERSHIP GUIDELINES	21
BOARD AND COMMITTEE REMUNERATION	21
EXECUTIVE COMPENSATION AND OTHER INFORMATION	23
ADDITIONAL INFORMATION	23
GLOSSARY	24
SCHEDULE “A” Metric Conversion Table	25
SCHEDULE “B” Disclosure of Corporate Governance Practices	26
SCHEDULE “C” Charter of the Audit Committee	30
SCHEDULE “D” Description of Board Committees and Their Charters	37
SCHEDULE “E” Charter of the Board of Directors	40
SCHEDULE “F’ Executive Compensation and Other Information	43
Report on Executive Compensation	43
Performance Graph	52
Remuneration of Executive Officers of TCPL	52
Executive Compensation	53
Pension and Retirement Benefits for Executives	60
Executive Separation Agreements	63
Supplemental Disclosure - Total Direct Compensation Awards	64

TRANSCANADA PIPELINES LIMITED ii

PRESENTATION OF INFORMATION

Unless otherwise noted, the information contained in this Annual Information Form (“AIF”) is given at or for the year ended December 31, 2007 (“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.

Certain portions of TCPL’s Management’s Discussion and Analysis dated February 25, 2008 (“MD&A”) are incorporated by reference into this AIF as stated below. The MD&A 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 may contain certain information that is forward-looking and is subject to important risks and uncertainties. The words “anticipate”, “expect”, “believe”, “may”, “should”, “estimate”, “project”, “outlook”, “forecast” or other similar words are used to identify such forward looking information. All forward-looking statements reflect TCPL’s beliefs and assumptions based on information available at the time the statements were made. Actual results or events may differ from those predicted in these forward-looking statements. Factors that 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 operating performance of the Company’s natural gas pipeline and energy assets, the availability and price of energy commodities, regulatory processes and decisions, changes in environmental and other laws and regulations, competitive factors in the natural gas pipeline and energy industry sectors, construction and completion of capital projects, labour, equipment and material costs, access to capital markets, interest and currency exchange rates, technological developments and the current economic conditions in North America. By its nature, forward-looking information is subject to various risks and uncertainties, including those material risks discussed in this AIF under “Risk Factors”, which could cause TCPL’s actual results and experience to differ materially from the anticipated results or expectations expressed. Additional information on these and other factors is available in the reports filed by TCPL with Canadian securities regulators and with the U.S. Securities and Exchange Commission (“SEC”). Readers are cautioned to not place undue reliance on this forward-looking information, which is given as of the date it is expressed in this AIF or otherwise, and to not use future-oriented information or financial outlooks for anything other than their intended purpose. 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.

TRANSCANADA PIPELINES LIMITED 1

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 3,500 employees, substantially all of whom were employed in Canada and the United States.

TCPL’s subsidiaries whose assets exceed ten per cent of TCPL’s consolidated assets or whose sales and operating revenues exceeded ten per cent of TCPL’s consolidated sales and operating revenues at year end are noted below. Also noted is the jurisdiction under which each subsidiary was incorporated. TCPL owns, directly or indirectly, 100 per cent of the voting shares of each of these subsidiaries.

TRANSCANADA PIPELINES LIMITED 2

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 are principally comprised of the Company’s pipelines in Canada, the U.S. and Mexico and its regulated natural gas storage operations in the U.S. Energy includes the Company’s power operations, the non-regulated natural gas storage business, and liquefied natural gas (“LNG”) projects.

Developments in the Pipelines Business

TCPL’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.

Recent Pipeline Developments

·January 4 2008. The State of Alaska announced that TCPL had submitted a complete Alaska Gasline Inducement Act application for a license to construct the Alaska Pipeline Project and would be advancing to the public comment stage.

·January 2008. Gas Transmission Northwest Corporation (“GTNC”) filed a Stipulation and Agreement with the U.S. Federal Regulatory Commission (“FERC”) on October 31, 2007 comprised of an uncontested settlement of all aspects of its 2006 General Rate Case.  On January 7, 2008, the FERC issued an order approving the settlement. The settlement rates are effective retroactive to January 1, 2007.

·January 11, 2008. Keystone U.S. received, from the U.S. Department of State, the Final Environmental Impact Statement (“FEIS”) regarding the construction of the Keystone U.S. pipeline and its Cushing extension. The FEIS stated the pipeline would result in limited adverse environmental impacts. The FEIS is a requirement to proceed with the Presidential Permit process, which governs the construction and operation of facilities at the U.S. – Canada border crossing. The Presidential Permit is expected to be issued in March 2008. Construction and material supply contracts totaling approximately $3.0 billion have been awarded for pipe, tanks, pumps and related materials, and engineering and construction management services.

·February 2008. In 2005, certain subsidiaries of Calpine Corporation (“Calpine”) filed for bankruptcy protection in both Canada and the U.S. The Portland Natural Gas Transmission System (“Portland”) and GTNC reached agreement with Calpine for allowed unsecured claims in the Calpine bankruptcy of US$125 million and US$192.5 million, respectively. Creditors were to receive shares in the re-organized Calpine and these shares will be subject to market price fluctuations as the new Calpine shares begin to trade. In February 2008, Portland and GTNC received partial distributions of 6.1 million shares and 9.4 million shares, respectively. Claims for Nova Gas Transmission Limited and Foothills Pipe Lines (South B.C.) Ltd. for $31.6 million and $44.4 million, respectively, were received in cash in January 2008 and will be passed on to shippers on these systems.

2007

Pipeline Developments

·February 9, 2007. TCPL received approval from the National Energy Board (the “NEB”) to transfer a section of the Canadian Mainline (as defined below) natural gas transmission facilities to the Keystone oil pipeline project to transport crude oil from Alberta to refining centres in the U.S. Midwest and to construct and operate new oil pipeline facilities in Canada. TCPL announced in January 2007 the start of a binding open season for an expansion and extension of the proposed Keystone oil pipeline. The purpose of the open season was 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 a 468 kilometre (“km”) extension of the U.S. portion of the pipeline.

·February 22, 2007. TCPL closed its acquisitions of American Natural Resources Company and ANR Storage Company (collectively, “ANR”) and acquired an additional 3.6 per cent interest in Great Lakes Gas Transmission Partnership (“Great Lakes”) from El Paso Corporation for a total of US$3.4 billion, subject to certain post-closing adjustments, including approximately US$491 million of assumed long-term debt. Additionally, TCPL increased

TRANSCANADA PIPELINES LIMITED 3

its ownership in TC PipeLines, LP to 32.1 per cent in conjunction with the TC PipeLines, LP acquisition of a 46.4 per cent interest in the Great Lakes. TCPL subsequently became the operator of the Northern Border Pipeline Company (“NBPL”) and now operates all three TC PipeLines, LP investments.

·November 2007. Keystone Canada filed an application with the NEB to add new pumping facilities to accommodate the increase in scope and scale of the project.  An NEB oral hearing is scheduled to commence in April 2008.

·November 20, 2007. A non-routine application was filed with the Alberta Energy and Utilities Board (“EUB”) for the North Central Corridor pipeline expansion of the Alberta System (as defined below). The estimated cost of this project is $983 million with construction expected to begin late 2008, subject to regulatory approval. The project is expected to be completed in two stages with the first stage completed in April 2009 and the second in April 2010.

·December 2007. ConocoPhillips contributed $207 million to acquire a 50 per cent ownership interest in the Keystone oil pipeline project.  Affiliates of TCPL will be responsible for constructing and operating Keystone, which is expected to have a capital cost of approximately US$5.2 billion.

·TCPL continued funding of the Mackenzie Valley Aboriginal Pipeline Limited Partnership for its participation in the Mackenzie Gas Pipeline Project.

Regulatory Matters

·February 2007. TCPL received approval from the NEB to integrate the B.C. System into the Foothills System (as defined below) in southern B.C. which was effective April 1, 2007.

·May 2007. TCPL’s five-year settlement with interested stakeholders for the years 2007 to 2011 on its Canadian Mainline was approved by the NEB. The settlement reflects, among other things, a deemed common equity ratio of 40 per cent.

Further information about these developments can be found in the MD&A under the heading “TCPL’s Strategy” and “Pipelines - Opportunities and Developments”.

2006

Pipeline Developments

·April 2006. TC PipeLines, LP, an affiliate of TCPL, acquired an additional 20 per cent general partnership interest in NBPL for approximately US$307 million which brought its total general partnership interest in NBPL owned by TC Pipelines, LP to 50 per cent. TC PipeLines, LP also indirectly assumed approximately US$122 million of the debt of NBPL. TCPL is the parent company of TC PipeLines GP, Inc., the general partner of TC PipeLines, LP.

·April 2006. TCPL sold its 17.5 per cent general partner interest in Northern Border Partners, L.P. for proceeds of $35 million, net of current taxes.

·December 2006. The 130 km Tamazunchale natural gas pipeline in east-central Mexico went into commercial service.

·December 2006. TC PipeLines, LP acquired 49 per cent in Tuscarora Gas Transmission Company (“Tuscarora”). TCPL became the operator of Tuscarora.

Regulatory Matters

·February 2006. TCPL filed an application with the FERC for a certificate for a two-phase expansion of its existing natural gas pipeline in southern California, the North Baja system (“North Baja”) and the construction of a new lateral pipeline in California’s Imperial Valley.

·April 2006. The NEB approved a negotiated settlement of the 2006 Canadian Mainline tolls which included a deemed common equity ratio of 36  per cent from 33 per cent and incentives for managing cost through fixing certain components of the revenue requirement.

·June 2006. TCPL filed an application with the NEB seeking approval to transfer a portion of TCPL’s Canadian Mainline natural gas transmission facilities to the Keystone oil pipeline project which was approved by the NEB in February 2007. Additionally, in December 2006, TCPL filed an application with the NEB for approval to construct and operate the Canadian portion of the Keystone oil pipeline.

TRANSCANADA PIPELINES LIMITED 4

2005

Pipeline Developments

·February 2005. TransCanada announced the Keystone oil pipeline project. In November 2005, TransCanada announced a memorandum of understanding with ConcoPhillips which committed ConocoPhillips to ship crude oil on this pipeline and gave them the right to acquire a 50 per cent ownership interest in the oil pipeline project.

·June 2005. TCPL acquired an additional interest in the Iroquois Gas Transmission System L.P. (“Iroquois System”) for US$13.6 million. The acquisition increased TCPL’s ownership interest from 40.96 per cent to 44.48 per cent.

·June 2005. TCPL commenced construction of the Tamazunchale natural gas pipeline.

Regulatory Matters

·March 2005. TCPL reached a settlement 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 regulator.

·May 2005. TCPL received the NEB’s decision on the Canadian Mainline 2004 Tolls and Tariff Application (Phase II), approving an increase in the deemed common equity component of the Canadian Mainline’s capital structure from 33 per cent to 36 per cent effective January 1, 2004.

Developments in the Energy Business

TCPL has built a substantial energy business over the past decade and has achieved a significant presence in power generation in selected regions of Canada and U.S. More recently, TCPL has also developed a significant non-regulated natural gas storage business in Alberta. Summarized below are significant developments that have occurred in TCPL’s energy business over the last three years.

Recent Energy Developments

·January 11, 2008. The FERC issued its FEIS for the Broadwater LNG project (“Broadwater”), a proposed offshore LNG facility in Long Island Sound, New York. The FEIS confirmed project need, supported the location of the project with acknowledgement of its target market and delivery goals, and found safety and security risks to be limited and acceptable.  The FEIS concluded that with adherence to federal and state permit requirements and regulations, Broadwaters’s proposed mitigation measures and the FERC’s recommendations, the project will not result in a significant impact on the environment.

·January 2008. A milestone in the Bruce Power A L.P. (“Bruce A”) Units 1 and 2 refurbishment and restart project was completed when the sixteenth and final new steam generator was installed. With the completion of this stage of the project, the authorized funding for Units 1 and 2 was increased from $2.75 billion to approximately $3.0 billion. Bruce Power is currently preparing a comprehensive estimate of the cost to complete the Unit 1 and 2 restart. This process is expected to result in a further increase in the total project cost. Project cost increases are subject to the capital cost-risk and reward-sharing mechanism under the agreement with the Ontario Power Authority. Bruce A Units 1 and 2 are expected to produce an additional 1,500 megawatts (“MW”) when completed in 2010.

·February 2008. The potential anchor LNG supplier for the Cacouna LNG project (“Cacouna”) terminal announced it would no longer be pursuing the development of its LNG supply as originally planned. As a result of this announcement, TCPL and Petro-Canada are currently reviewing their strategy for the project.

2007

Energy Developments

·June 2007. Following public hearings in 2006, the Québec government granted a provincial decree approving the Cacouna terminal. Cacouna also received federal approvals pursuant to the Canadian Environmental Assessment Act.

·September 2007. Cacouna announced that it was delaying the planned in-service date for the regassification terminal from 2010 to 2012. This delay resulted from a need to assess impacts of permit conditions, to review the

TRANSCANADA PIPELINES LIMITED 5

facility design in light of escalating costs and to align the schedule with potential LNG supply facilities.

·August 2007. TransCanada announced the expansion of the Unit 4 refurbishment on the revised Bruce A restart project that includes installing new fuel channels in Unit 4.

·November 2007. The second phase of the Cartier Wind Energy Project, the 101 MW Anse-à-Valleau wind farm, was placed into service.  In addition, the Cartier Wind Energy Project began construction of a third project, the 110 MW Carleton wind farm.

·November 2007. TCPL entered into an agreement with Hydro-Québec to temporarily suspend all electricity generation from the Bécancour power plant during 2008. The agreement contains an option for Hydro-Québec to extend the suspension to 2009. TCPL will receive payments under the agreement similar to those that would have been received under the normal course of operation.

Further information about each of these energy developments can be found in the MD&A under the heading “TCPL’s Strategy” and “Energy - Opportunities and Developments”.

2006

Energy Developments

·TCPL continued construction of the Cartier Wind Energy Project, of which 62 per cent is owned by TCPL. The first of six proposed wind farm projects, Baie-des-Sables, went into commercial service in late 2006.

·September 2006. Portlands Energy Centre L.P., 50 per cent owned by TCPL, signed a 20-year Accelerated Clean Energy Supply contract with the Ontario Power Authority for Portlands Energy Centre.

·September 2006. Construction of the 550 MW Bécancour cogeneration plant near Trois Rivières, Québec, was completed and placed into service providing power to Hydro-Québec Distribution.

·November 2006. TCPL was awarded a 20-year Clean Energy Supply contract by the Ontario Power Authority to build, own and operate a 683 MW natural gas-fired power plant near the Town of Halton Hills, Ontario.

·December 2006. The Edson gas storage facility was placed in service.

Regulatory Matters

·January 2006. TCPL, on behalf of Broadwater, filed an application with the FERC for approval of the LNG regasification project to be located in Long Island Sound, New York. Coincident with the FERC process, Broadwater applied to the New York Department of State for a determination that the project is consistent with New York’s coastal zone policies.

·December 2006. A public hearing on Cacouna was held in May and June of 2006 and in December 2006 the Minister of the Environment for Québec and the federal Minister of the Environment, jointly released the report of the Joint Commission on Cacouna.

2005

Energy Developments

·February 2005. TCPL advanced the Cartier Wind Energy Project with the signing of long-term electricity supply contracts.

·April 2005. TCPL acquired hydroelectric power generation assets from USGen New England, Inc. for approximately US$503 million.

·September 2005. TCPL sold all of its interests in TransCanada Power, L.P. to EPCOR Utilities Inc. for net proceeds of $523 million.

·October 2005. Bruce A entered into agreements with the Ontario Power Authority to restart units 1 and 2, extend the operating life of unit 3 and replace the generators on unit 4 at Bruce A.

·December 2005. TCPL sold its approximate 11 per cent interest in P.T. Paiton Energy Company to subsidiaries of The Tokyo Electric Power Company, resulting in gross proceeds of US$103 million.

·December 2005. TCPL acquired the remaining rights and obligations of the 756 MW Sheerness Power Purchase Arrangement (“PPA”) from the Alberta Balancing Pool for $585 million.

TRANSCANADA PIPELINES LIMITED 6

·TCPL commenced construction of a natural gas storage facility located near Edson, Alberta.

·Ocean State Power successfully restructured its long-term natural gas fuel supply contracts with its suppliers.

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 73 per cent of TCPL’s total assets and the Energy business accounted for approximately 47 per cent of revenues and 23 per cent of TCPL’s total assets. The following is a description of each of TCPL’s two main areas of operation.

The following table shows TCPL’s revenues from operations by segment, classified geographically, for the years ended December 31, 2007 and 2006.

Revenues From Operations(millions of dollars)	2007	2006
Pipelines
Canada - Domestic	$2,227	$2,390
Canada - Export(1)	1,003	971
United States	1,482	629
	4,712	3,990
Energy(2)
Canada – Domestic	2,792	2,566
Canada - Export(1)	3	1
United States	1,321	963
	4,116	3,530
Total Revenues(3)	$8,828	$7,520

(1)    Exports 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.

Pipelines Business

TCPL is a leader in the responsible development and reliable operation of North American energy infrastructure including natural gas pipelines, regulated gas storage facilities and projects related to oil pipelines. TCPL’s network of wholly owned pipelines extends more than 59,000 km (36,500 miles), tapping into virtually all major gas supply basins in North America.

TCPL has substantial Canadian and U.S. natural gas pipeline and related holdings, and one oil pipeline project, including those listed below.

Canada

·TCPL’s 100 per cent owned, 14,957 km natural gas transmission system in Canada that 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. (“Canadian Mainline”).

·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 and the Foothills System as well as the natural gas pipelines of other companies. The 23,570 km system is one of the largest carriers of natural gas in North America (“Alberta System”).

·TCPL’s 100 per cent owned, 1,241 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. Effective April 1, 2007, the B.C. System was integrated into the Foothills System (“Foothills System”).

·TransCanada Pipeline Ventures LP, which is 100 per cent owned by TCPL, owns a 121 km pipeline and related facilities that supply natural gas to the oilsands region of northern Alberta as well as a 27 km pipeline that supplies natural gas to a petrochemical complex at Joffre, Alberta.

TRANSCANADA PIPELINES LIMITED 7

·Keystone is a 3,456 km oil pipeline project under construction that is expected to transport crude oil from Hardisty, Alberta to U.S. Midwest markets at Wood River and Patoka in Illinois, and to Cushing, Oklahma. Keystone is 50 per cent owned by TCPL.

·TransCanada Québec & Maritimes Pipeline Inc. (“TQM”) is 50 per cent owned by TCPL. TQM is a 572 km pipeline system that connects with the Canadian Mainline and transports natural gas from Montréal to Québec City in Québec, and connects with the Portland system. TQM is operated by TCPL.

United States

·TCPL’s ANR System (“ANR System”) is a 100 per cent owned, 17,000 km natural gas transmission system which transports natural gas from producing fields located primarily in Texas and Oklahoma on its southwest leg. Its southeast leg transports natural gas from producing fields located primarily in the Gulf of Mexico and Louisiana. The system extends to markets located mainly in Wisconsin, Michigan, Illinois, Ohio and Indiana. ANR’s natural gas pipeline also connects with other natural gas pipelines to give access to diverse sources of North American supply, including Western Canada and the Rocky Mountain supply region, and a variety of markets in the midwestern and northeastern U.S. ANR also owns and operates underground regulated natural gas storage facilities in Michigan with a total capacity of approximately 235 billion cubic feet (“Bcf”).

·The GTN System (“GTN System”) System is TCPL’s 100 per cent owned natural gas transmission system which extends 2,174 km and links the Foothills System with Pacific Gas and Electric Company’s California Gas Transmission System, with Williams Companies, Inc.’s Northwest Pipeline in Washington and Oregon, and with Tuscarora.

·North Baja is TCPL’s 100 per cent owned natural gas transmission system which extends 129 km from Ehrenberg in southwestern Arizona to a point near Ogilby, California on the California/Mexico border and connects with the Gasoducto Bajanorte natural gas pipeline system in Mexico.

·The Great Lakes Gas Transmission System (“Great Lakes System”) is owned 53.6 per cent by TCPL and 46.4 per cent by TC Pipelines, LP. The 3,404 km Great Lakes natural gas transmission system connects with the Canadian Mainline at Emerson, Manitoba, and serves markets in Central Canada and the Midwestern U.S. TCPL operates Great Lakes and effectively owns 68.5 per cent of the system through its 53.6 per cent ownership interest and its indirect ownership through its 32.1 per cent interest in TC Pipelines, LP.

·The Iroquois System 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.

·The Portland system 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 the Portland system and operates this pipeline.

·The Northern Border Pipeline System (“NBPL System”) is 50 per cent owned by TC PipeLines, LP and is a 2,250 km natural transmission pipeline system, which serves the U.S. Midwest from a connection with the Foothills System near Monchy, Saskatchewan. TCPL operates and effectively owns 16.1 per cent of NBPL through its 32.1 per cent interest in TC PipeLines, LP.

·The Tuscarora System is 100 per cent owned by TC PipeLines, LP and is a 491 km pipeline system transporting natural gas from the GTN System at Malin, Oregon to Wadsworth, Nevada with delivery points in northeastern California and northwestern Nevada. TCPL operates Tuscarora and its 32.1 per cent ownership interest in TC PipeLines, LP gives TCPL a 32.1 per cent interest in the system.

·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. TC PipeLines, LP owns a 50 per cent interest in NBPL, the remaining 46.4 per cent in the Great Lakes System and 100 per cent of Tuscarora.

International

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

·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.

TRANSCANADA PIPELINES LIMITED 8

·Gas Pacifico is a 540 km natural gas pipeline extending from Loma de la Lata, Argentina to Concepción, Chile. INNERGY is an industrial natural gas marketing company based in Concepción that markets natural gas transported on Gas Pacifico. TCPL holds a 30 per cent ownership interest both in Gas Pacifico and INNERGY.

·Tamazunchale is a 100 per cent owned, 130 km natural gas pipeline in east-central Mexico which extends from the facilities of Pemex Gas near Naranjos, Veracruz to an electricity generating station near Tamazunchale, San Luis Potosi. This pipeline went into service on December 1, 2006.

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”.

Regulation of the Pipeline Business

Canada

CANADIAN MAINLINE, TQM AND FOOTHILLS SYSTEM

Under the terms of the National Energy Board Act (Canada), the Canadian Mainline, TQM and the 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, TQM and Foothills Systems’ 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, TQM and Foothills Systems. Net earnings of the Canadian Mainline, TQM 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 was regulated in 2007 by the 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 were subject to approval by the EUB. Under the provisions of the Pipeline Act, the EUB oversaw 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.

Effective January 1, 2008, the EUB was reorganized into the Energy Resources Conservation Board and the Alberta Utilities Commission (“AUC”). The AUC will regulate all the physical and economic aspects of the Alberta System which were previously regulated by the EUB.

United States

TCPL’s wholly owned and partially owned U.S. pipelines, including the ANR System, the GTN System, the Great Lakes System, the Iroquois System, the Portland system, the NBPL System, North Baja and the 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.

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 non-regulated natural gas storage in Alberta, and LNG facilities in Canada and the U.S.

The electrical power generation plants and power supply that TCPL has an interest in, including those under development, 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 U.S. account for the balance, being approximately 15 per cent.

TRANSCANADA PIPELINES LIMITED 9

TCPL owns and operates the following facilities:

·Natural gas-fired cogeneration plants in Alberta at Carseland (80 MW), Redwater (40 MW), Bear Creek (80 MW) and MacKay River (165 MW).

·Grandview, a 90 MW natural gas-fired cogeneration power plant located in Saint John, New Brunswick. Under a 20-year operating lease for tolls, Irving Oil Limited receives 100 per cent of the plant’s heat and electricity output.

·Cancarb, a 27 MW facility at Medicine Hat, Alberta fuelled by waste heat from TCPL’s adjacent thermal carbon black facility.

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

·TC Hydro, TCPL’s hydroelectric facilities located in New Hamphire, Vermont and Massachusetts on the Connecticut and Deerfield Rivers consist of 13 stations and associated dams and reservoirs with a total generating capacity of 583 MW.

·Bécancour, a 550 MW natural gas-fired cogeneration power plant located near Trois-Rivières, Québec. The entire power output is supplied to Hydro-Québec under a 20-year power purchase contract. Steam is also sold to an industrial customer for use in commercial processes.

·Edson, an underground natural gas storage facility connected to the Alberta System near Edson, Alberta. The facility’s central processing system is capable of maximum injection and withdrawal rates of 725 million cubic feet per day (“mmcf/d”) of natural gas. Edson has a working natural gas storage capacity of approximately 50 Bcf.

·A long-term natural gas storage lease with a third party located in Alberta.

TCPL has the following long-term power purchase arrangements in place:

·The largest coal-fired electric generating facility in Western Canada, Sundance is located in south-central. Alberta, TCPL has the rights to 100 per cent of the generating capacity of the 560 MW Sundance A facility under a PPA, which expires in 2017. TCPL also has the rights to 50 per cent of the generating capacity of the 706 MW Sundance B facility under a PPA which expires in 2020 (“Sundance”).

·The Sheerness facility, which consists of two 390 MW coal-fired thermal power generating units, is located in southeastern Alberta. TCPL has the rights to 756 MW of generating capacity from the Sheerness facility PPA, which expires in 2020 (“Sheerness”).

TCPL has interest in the following:

·A 60 per cent ownership in CrossAlta, which 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 54 Bcf with a maximum deliverability capability of 480 mmcf/d.

·A 62 per cent interest in Baie-des-Sables (110 MW) and Anse á Valleau (101 MW) wind farms.

·Consisting of two generating stations, Bruce A with approximately 3,000 MW of generating capacity and Bruce Power L.P. (“Bruce B”) with approximately 3,200 MW of generating capacity. Bruce Power is located in Ontario. TCPL owns 48.7 per cent of Bruce A., which has four power generating units, two of which have been idled for refurbishing and are expected to restart in 2010. TCPL owns 31.6 per cent of Bruce B, which also has four power generating units.

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

·The third phase of the 740 MW Cartier Wind Energy Project, the Carleton wind farms, which began construction in late 2007 as well as the remaining three projects which are under planning and development.

·The Portlands Energy Centre, a 550 MW high efficiency, combined-cycle natural gas generation power plant located near downtown Toronto, Ontario 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 beginning June in 2008. It is anticipated to be fully commissioned in its combined-cycle mode, delivering 550 MW of power in the second quarter of 2009.

·A 683 MW natural gas-fired power plant near the town of Halton Hills, Ontario is under construction and is expected to be placed in service in the third quarter of 2010.

·A joint venture with Shell, Broadwater is a proposed offshore LNG project located in the New York waters of Long Island Sound, capable of receiving, storing and regasifying imported LNG with an average send-out capacity of approximately one Bcf per day of natural gas. TCPL holds a 50 per cent interest in Broadwater.

TRANSCANADA PIPELINES LIMITED 10

·A joint venture with Petro-Canada, Cacouna is a proposed LNG project in Québec at Gros Cacouna harbour on the St. Lawrence River in Québec, Cacouna would be capable of receiving, storing and regasifying imported LNG with an average send-out capacity of approximately 500 mmcf/d of natural gas. TCPL has a 50 per cent interest in Cacouna.

·The proposed Kibby wind power project is located in Kibby and Skinner Townships in northwestern Franklin County, Maine. Subject to receipt of U.S. federal and state approvals, construction of the new facilities could begin in early 2008 with an expected in-service date of 2009/2010.

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”.

HEALTH, SAFETY AND ENVIRONMENT RISK MANAGEMENT

TCPL is committed to providing a safe and healthy environment for its employees, contractors and the public, and to protecting the environment. Health, safety and environment (“HS&E”) is a priority in all of TCPL’s operations and the Company is committed to ensuring it is in conformance with its internal policies and regulated requirements, and is an industry leader. The HS&E Committee of TCPL’s Board of Directors monitors conformance with TCPL’s HS&E corporate policy through regular reporting. TCPL’s HS&E management system is modeled to the elements of the International Organization of Standardization’s (“ISO”) standard for environmental management systems, ISO 14001, and focuses resources on the areas of significant risk to the organization’s HS&E business activities. Management is regularly advised of all important HS&E operational issues and initiatives 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 requested by the HS&E Committee. The most recent assessment was conducted in November 2006. These assessments involve senior management and employee interviews, review of policies, procedures, objectives, performance measurement and reporting.

Safety

In 2007, employee and contractor health and safety performance continued to improve relative to previous years and benchmarked within the top level of industry peers.  The Company’s assets were highly reliable in 2007 and there were no incidents that were material to the Company’s operations.

Under the approved regulatory models in Canada, pipeline integrity expenditures on NEB and AUC 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 $120 million in 2008 for pipeline integrity on its wholly owned pipelines, which is slightly higher than the amount spent in 2007, reflecting the acquisition of ANR and slightly increased spending in Canada.  Spending associated with public safety on the Energy assets is focused primarily on hydro dams and associated equipment, and is consistent with previous years.

Environment

TCPL’s operations are subject to various environmental laws and regulations that establish compliance and remediation obligations.  There are no outstanding orders, material claims or lawsuits against the Company in relation to the release or discharge of any material into the environment or in connection with environmental protection.  The Company believes that it has established appropriate reserves, where required, for environmental liabilities.

Environmental risks from TCPL’s facilities typically include air emissions such as nitrogen oxides (NOx), particulate matter and greenhouse gases, potential land impacts, including land reclamation following construction, releases, chemical and hydrocarbon storage, and waste management control to minimize hazardous wastes, and water impacts such as water discharge. TCPL utilizes a risk-based environmental assessment approach.  All businesses are assessed annually and specific facilities, installations and activities are reviewed on a one- to three-year cycle, depending on the Company’s assessment risk.  Business and/or facility inspections are also completed on a monthly, quarterly or annual basis, depending on the entity and the assessment of risk. There were no materially significant environmental matters arising from these assessments conducted during 2007.

Climate change policy continues to evolve at regional, national and international levels.  Under the Specified Gas Emitters Regulation, as of July 1, 2007, industrial facilities in Alberta are required to reduce their greenhouse gas emissions intensities by 12 per cent.  TCPL’s Alberta-based facilities are subject to this regulation which also extends to the Sundance and Sheerness facilities with which the Company has PPAs.  Plans have been developed to manage the costs of compliance incurred by these assets.  The regulation is not expected to have a material impact on the Company’s results.  Compliance

TRANSCANADA PIPELINES LIMITED 11

costs related to the Alberta System are expected to be recovered through tolls paid by customers.  Recovery of compliance costs related to the Company’s power generation facilities in Alberta is dependent ultimately on market prices for electricity.  The Company recorded in 2007 a charge of $14 million for the period from July 1, 2007 to December 31, 2007 related to the new Alberta environmental regulation.

A hydrocarbon royalty tax took effect in Québec on October 1, 2007 and is expected to affect mainly the Bécancour power generation facility.  A regulatory proceeding is under way to determine the method of collecting the tax.  The Company recorded a charge of $2 million for the period October 1, 2007 to December 31, 2007 for Québec royalties.

British Columbia recently announced a carbon tax, with an effective date of July 2008, which is expected to be applied to fuel usage at the Company's pipeline compressor facilities in that province.  The specifics of the application of the tax are still being assessed.  Compliance costs related to this tax are anticipated to be recovered through tolls paid by customers. 

The Government of Canada released in April 2007 the Regulatory Framework for Air Emissions ("Framework").  The Framework outlines short-, medium- and long-term objectives for managing both greenhouse gas emissions and air pollutants in Canada.  The Company expects a number of its facilities will be affected by pending Federal climate change regulations that will be put in place to meet the Framework’s objectives.  It is unknown at this time whether the impacts from the pending regulations will be material as the final form of compliance options is still evolving.

Climate change legislation is evolving at both the federal and state levels in the U.S.  The Company expects a number of its facilities could be affected by these legislative initiatives, but timing and specific policy objectives remain uncertain.

The Company continues to be involved in discussions with governments in jurisdictions where TCPL has operations and where climate change policy is under development. TCPL is also continuing its programs to manage greenhouse gas emissions from its facilities and to evaluate new processes and technologies that result in improved efficiencies and lower greenhouse gas emission rates.

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 a pipeline pursuant to Section 112 of the National Energy Board Act. On November 20, 2006, TCPL and Enbridge Inc. were granted a dismissal of the case but CAPLA has appealed that decision. The appeal was heard on December 18, 2007 and the Ontario Court of Appeal reserved their 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. Liabilities, if any, would be dealt with through the NEB.

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 12

RISK FACTORS

A discussion of the Company’s risk factors can be found in the MD&A for the year ended December 31, 2007, which is incorporated by reference herein, under the headings “Pipelines - Opportunities and Developments”, “Pipelines - Business Risks”, “Energy - Opportunities and Developments”, “Energy - Business Risks” and “Risk Management and Financial Instruments”.

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 share during the past three completed financial years are set forth in the following table.

	2007	2006	2005
Dividends declared on common shares(1)	$1.39	$1.28	$1.23
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⁾  TCPL dividends on its common shares are declared in an amount equal to the aggregate cash dividend paid by TransCanada to its public shareholders. 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 533,008,044 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.

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.

TRANSCANADA PIPELINES LIMITED 13

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 and junior subordinated notes with terms to maturity in excess of one year, during the 12 months ended December 31, 2007.

Date Issued	Issue Price per $1,000 Principal Amount of Notes	Aggregate Issue Price
May 3, 2007	US$998.21	US$998,210,000
October 5, 2007	US$995.65	US$995,650,000

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.

CREDIT RATINGS

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

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

⁽¹⁾Issued May 3, 2007.

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.

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 rating assigned to TCPL's Senior Unsecured Debt is 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 securities. 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 BBB (high) rating assigned to Junior Subordinated Notes is the fourth highest of the ten categories for Long-Term Debt.  Long-Term Debt rated BBB is of adequate credit quality.  Protection of interest and principal is considered acceptable but there may be other

TRANSCANADA PIPELINES LIMITED 14

adverse conditions present which reduce the strength of the entity and its rated securities. The Pfd-2 (low) rating assigned to TCPL's preferred shares is the second highest of six rating categories for preferred shares. Preferred shares rated Pfd-2 are of satisfactory credit quality. Protection of dividends and principal is still substantial; however, earnings, the balance sheet and coverage ratios are not as strong as Pfd-1 rated companies.

Moody’s Investor Services (Moody’s)

Moody’s has different rating scales for short and long-term obligations. Numerical modifiers 1, 2 and 3 are applied to each rating classification, with 1 being the highest and 3 being the lowest. The P-1 rating assigned to 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 rating assigned to TCPL’s senior secured and Senior Unsecured Debt and the A3 rating assigned to its junior subordinated debt is 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- rating assigned to TCPL’s senior unsecured debt is 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 ratings assigned to TCPL’s Junior Subordinated Notes 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 of 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 trading 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 2007	40.73	38.95	17,822,199
November 2007	40.69	38.10	28,532,491
October 2007	40.24	36.47	30,876,596
September 2007	37.19	35.80	28,163,823
August 2007	38.62	35.43	29,811,560
July 2007	39.83	36.17	33,442,298
June 2007	39.36	35.77	30,897,359
May 2007	40.29	38.77	25,520,203
April 2007	40.26	37.75	22,302,817
March 2007	39.80	36.75	30,461,884
February 2007	39.28	37.17	28,769,671
January 2007	41.35	38.28	29,422,031

TRANSCANADA PIPELINES LIMITED 15

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 2007	50.75	49.80	36,215	51.65	50.11	37,319
November 2007	50.50	49.96	60,707	50.75	50.05	55,112
October 2007	50.44	49.25	39,635	50.44	49.51	47,627
September 2007	51.80	49.00	30,091	51.95	49.61	32,310
August 2007	51.80	50.50	37,226	51.25	50.50	28,572
July 2007	51.98	50.50	27,358	51.80	50.01	32,150
June 2007	52.88	51.50	56,999	52.80	51.50	50,316
May 2007	54.33	51.85	271,282	54.15	51.60	157,425
April 2007	54.69	54.00	29,521	54.60	53.75	44,051
March 2007	54.99	53.80	33,430	54.80	54.25	42,213
February 2007	54.98	53.95	35,035	54.96	54.01	24,557
January 2007	54.65	53.60	37,913	54.58	53.85	28,836

DIRECTORS AND OFFICERS

As of February 25, 2008, the directors and officers of TransCanada as a group beneficially owned, directly or indirectly, or exercised control or direction over an aggregate of 312,558 common shares of TransCanada. This 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. In additions, officers held exercisable options to acquire an aggregate of 2,296,740 additional common shares. 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 the Board at Year End, together with their jurisdictions of residence, all positions and offices held by them with TCPL 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 TCPL. Positions and offices held with TransCanada are also held by such person at TCPL.

Name and Place of Residence	Principal Occupation During the Five Preceding Years	Director Since
Kevin E. Benson(1) Wheaton, Illinois United States	President and Chief Executive Officer, Laidlaw International, Inc. (transportation services) from June 2003 to October 2007, and Laidlaw, Inc. from September 2002 to June 2003.	2005
Derek H. Burney, O.C. Ottawa, Ontario Canada	Senior strategic advisor at Ogilvy Renault LLP (law firm) and Chairman, CanWest Global Communications Corp. (communications). Lead director at Shell Canada Limited (oil and gas) from April 2001 to May 2007. President and Chief Executive Officer, CAE Inc. (technology) from October 1999 to August 2004.	2005
Wendy K. Dobson Uxbridge, Ontario Canada	Professor, Rotman School of Management and Director, Institute for International Business, University of Toronto. Vice Chair, Canadian Public Accountability Board. Director, Toronto-Dominion Bank.	1992
E. Linn Draper Lampasas, Texas United States	Director, Alliance Data Systems Corporation (data processing and sevices), Alpha Natural Resources, Inc. (mining), NorthWestern Corporation (conducting business as NorthWestern Energy) (oil and gas) Lead Director of and Temple-Inland Inc. (materials), Chairman, President and Chief Executive Officer of Columbus, Ohio-based American Electric Power Co., Inc. from April 1993 to April 2004.	2005

TRANSCANADA PIPELINES LIMITED 16

Name and Place of Residence	Principal Occupation During the Five Preceding Years	Director Since
The Hon. Paule Gauthier, P.C., O.C., O.Q., Q.C. Québec, Québec Canada	Senior Partner, Stein Monast 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
Kerry L. Hawkins Winnipeg, Manitoba Canada	Director, NOVA Chemicals Corporation. President, Cargill Limited (agricultural) from September 1982 to December 2005.	1996
S. Barry Jackson Calgary, Alberta Canada	Chair of the Board, TCPL since April 2005. Director, Cordero Energy Inc. (oil and gas) and Nexen Inc. (oil and gas), 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.	2002
Paul L. Joskow New York, New York United States	Economist and President of the Alfred P. Sloan Foundation. On leave from his position as Professor of Economics and Management, Massachusetts Institute of Technology (“MIT”) where he has been on the faculty since 1972. Director of the MIT Center for Energy and Environmental Policy Research from 1999 to 2007. Director of Exelon Corporation (energy) since July 2007. Trustee of Putnam Mutual Funds. President of the Yale University Council until July 1, 2006 and was on the Board of Directors of the Whitehead Institute of Biological Research until February 2005.	2004
Harold N. Kvisle Calgary,Alberta Canada	President and Chief Executive Officer of TCPL since May 2003 and TCPL since May 2001. Director, Bank of Montreal.	2001
John A. MacNaughton, C.M. Toronto, Ontario Canada	Chairman of the Business Development Bank of Canada and of the Canadian Trading and Quotation System Inc. (stock exchange). Director, Nortel Networks Corporation and Nortel Networks Limited (the principal operating subsidiary of Nortel Networks Corporation) (technology). Founding President and Chief Executive Officer of the Canadian Pension Plan Investment Board from 1999 to 2005.	2006
David P. O’Brien(2) Calgary, Alberta Canada	Chair, EnCana Corporation (oil and gas) since April 2002 and Chair, Royal Bank of Canada since February 2004. Director, Molson Coors Brewing Company, and C.D. Howe Institute. Chancellor, Concordia University and a member of the Science, Technology and Innovation Council of Canada.	2001
W. Thomas Stephens Greenwood Village, Colorado United States	Chairman and Chief Executive Officer of Boise Cascade, LLC (paper, forest products and timberland assets) since November 2005. Trustee of Putnam Mutual Funds.	2007(3)
D. Michael G. Stewart Calgary, Alberta Canada	Principal of the privately held Ballinacurra Group of Investment Companies since March 2002. Director, Canadian Energy Services Inc. and Pengrowth Corporation. Director of Esprit Exploration Ltd. (oil and gas) from May 2002 to September 2004; a director of Canada Southern Petroleum Ltd. from June 2003 to August 2004; a trustee of Esprit Energy Trust (oil and gas) from August 2004 to October 2006; and a director of Creststreet Power & Income General Partner Limited, the General Partner of Creststreet Power & Income Fund L.P. (wind power) from December 2003 to February 2006.	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 U.S. on March 24, 2000.

⁽²⁾      Mr. O’Brien was a director of Air Canada in April 2003 when Air Canada filed for protection under the Companies’ Creditors Arrangement Act (Canada) and applicable bankruptcy protection statutes in the U.S.

⁽³⁾      Mr. Stephens previously served on the Board from 2000 to 2005.

TRANSCANADA PIPELINES LIMITED 17

TransCanada will hold its annual meeting of common shareholders on Friday, April 25, 2008, and subject to the election of the thirteen nominees proposed for election to TransCanada’s board, these directors will be elected by the sole 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.

Officers

All of the executive officers and corporate officers of TCPL reside in Calgary, Alberta, Canada. Current positions and offices held with TCPL are also held by such person at TransCanda. As of the date hereof, the officers of TCPL, their present positions within TCPL 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	Executive Vice-President, Corporate and General Counsel and Chief Compliance Officer	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, L.P. from June 2003 to August 2005. Prior to June 2003, Vice-President, TransCanada 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.

Corporate Officers

Name	Present Position Held	Principal Occupation During the Five Preceding Years
Ronald L. Cook	Vice-President, Taxation	Vice-President, 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.

TRANSCANADA PIPELINES LIMITED 18

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 U.S. 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. Further information about TCPL’s corporate governance can be found on TransCanada’s website at www.transcanada.com 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 Kevin E. Benson (Chair), Derek H. Burney, Paule Gauthier, Paul L. Joskow and John A. MacNaughton.

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. Benson is an “Audit Committee Financial Expert” as that term is defined under U.S. securities laws. The Board has made these determinations based on the education and breadth and depth of experience of each member of the Audit Committee. The following is a description of the education and experience, apart from their respective roles as directors of 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. 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 was the President and Chief Executive Officer of Laidlaw International, Inc. until October, 2007. 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 was the lead director at Shell Canada Limited until May 2007 and is 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 the President of the Alfred P. Sloan Foundation and on leave from his position as a Professor of Economics and Management, MIT. 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 the Business Development Bank of Canada and 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.

TRANSCANADA PIPELINES LIMITED 19

The Charter of the Audit Committee can be found in Schedule “C” of this AIF and on TCPL’s website under the Corporate Governance - Board Committees page, at www.transcanada.com.

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.

External Auditor Service Fees

The aggregate fees for external auditor services rendered by, KPMG LLP, the External Auditor for the TransCanada group of companies for the 2007 and 2006 fiscal years, are shown in the table below:

Fee Category	2007	2006	Description of Fee Category
	(millions of dollars)
Audit Fees(1)	$6.27	$6.52	Aggregate fees for audit services rendered for the audit of the annual consolidated 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	0.07	Aggregate fees for assurance and related services that are reasonably related to performance of the audit or review of the consolidated 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 certain pension plans.
Tax Fees	0.06	0.22	Aggregate fees rendered for primarily tax compliance and tax advice. The nature of these services consisted of: tax compliance including the review of 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	0.00	0.07	Aggregate fees for products and services other than those reported elsewhere in this table. The nature of these services consisted of advice related to compliance with SOX.
Total	$6.40	$6.88

⁽¹⁾The disclosure of audit fees paid has been revised to be based on aggregate fees billed during the fiscal year as opposed to aggregate fees for professional services rendered during the fiscal year. For comparison purposes, both the 2007 and the 2006 amounts have been disclosed based on the aggregate fees billed during the year.

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, is a non-voting member of the Human Resources Committee and the Governance Committee. 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
	J.A. MacNaughton		W.T. Stephens		D.P. O’Brien
	D.P. O’Brien		D.M.G. Stewart		W.T. Stephens

TRANSCANADA PIPELINES LIMITED 20

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 located at www.transcanada.com.

Further information about the Board committees and the text of the Charter of the Board of Directors can be found in Schedule “D” and “E”, respectively, attached to this AIF and on TransCanada’s website at www.transcanada.com.

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 for election 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 TCPL 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 25, 2008.

Director	TransCanada Common Shares(2)	Deferred Share Units(1)
K. Benson	3,000	13,377
D. Burney	1,070	12,479
W. Dobson	3,000	33,631
E.L. Draper	0	13,299
P. Gauthier	1,000	25,876
K. Hawkins(3)	4,932	39,346
S.B. Jackson	39,000	24,366
P.L. Joskow	5,000	13,809
H. Kvisle(4)(5)	869,297	N/A
J. MacNaughton	30,000	8,610
D. O’Brien	19,164	25,876
W. T. Stephens	1,470	3,236
D.M.G. Stewart(6)	7,500	6,156

⁽¹⁾The information as to shares beneficially owned or over which control or direction is exercised, not being within the knowledge of TCPL, 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 TCPL, its subsidiaries and affiliates, the percentage of outstanding shares beneficially owned by any one director or nominee or by all directors and officers of TCPL 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.

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

TRANSCANADA PIPELINES LIMITED 21

⁽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 TCPL, has the right to acquire 814,981 common shares under vested stock options, which amount is included in this column.

⁽⁵⁾Mr. Kvisle is an employee of TCPL and participates is the ESU program; he does not participate in the DSU program.

⁽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 25, 2008.

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, TCPL 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 of TransCanada, 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 all or a portion of their retainer fees, attendance fees and travel fees into, or otherwise acquiring Deferred Share Units under, the Share Unit Plan for Non-Employee Directors (1998) (the “Deferred Share Unit Plan”), described under the heading “Share Unit Plan for Non-Employee Directors” below.

All of the directors have achieved the minimum share ownership.

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 common shares. The market competitiveness of director compensation is assessed against the Comparator Group (as defined in Schedule “F”)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, 2007, 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 $330,000 per annum in respect of his duties as Chair, $3,000 per chaired Board meeting, and was reimbursed for certain office and other expenses. Approximately half of Mr. Jackson’s retainer fee for acting as Chair was paid in Deferred Share Units, which was represented by a grant of 5,000 Deferred Share Units. Mr. Jackson also elected to direct the remaining portion of his retainer fee to be paid in Deferred Share Units. 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 Deferred Share Unit 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.

TRANSCANADA PIPELINES LIMITED 22

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 2007

The following table sets out the total fees paid in cash and the value of the Deferred Share Units awarded or credited for each non-employee director in 2007 as at the date of the grant, unless otherwise stated. Mr. Kvisle, as an employee of TCPL, receives no cash fees or Deferred Share Units as a director.

Directors may direct their retainer fees, attendance fees and travel fees to be paid in Deferred Share Units until the minimum share ownership guideline is reached, and are always entitled to direct all or a portion of their retainer fees, attendance fees and travel fees to be paid in Deferred Share Units. In 2007, Mr. Benson, Mr. Burney, Dr. Draper, Mr. Hawkins, Mr. MacNaughton and Mr. Stephens directed all of their retainer fees, attendance fees and travel fees to the Deferred Share Unit Plan. Ms. Gauthier and Mr. O’Brien directed their Board retainer fees to the Deferred Share Unit Plan. In addition, Mr. Jackson directed the cash portion of his Chair retainer fee as well as his Board attendance fee and travel fees to the Deferred Share Unit Plan. For further information on the Deferred Share Unit 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 Planning Sessions	Total Fees Paid in Cash	Total Value of DSUs Credited(2)	Total Cash & Value of DSUs Credited(1)
K.E. Benson(3)(4)	$30,000	$3,000	$2,703	$13,500	$16,500	$12,000	$1,500	$0	$188,523	$188,523
D.H. Burney	30,000	6,000	N/A	12,000	13,500	7,500	1,500	0	179,820	179,820
W.K. Dobson(3)	30,000	6,000	4,000	15,000	13,500	6,000	1,500	76,000	109,320	185,320
E.L. Draper(3)(4)	30,000	6,000	4,000	15,000	16,500	10,500	1,500	0	192,820	192,820
P. Gauthier	30,000	6,000	N/A	15,000	16,500	7,500	1,500	46,500	139,320	185,820
K.L. Hawkins(3)	30,000	6,000	4,000	15,000	19,500	10,500	1,500	0	195,820	195,820
S.B. Jackson(5)	330,000	N/A	N/A	30,000	0	1,500	3,000	0	364,500	364,500
P.L. Joskow(4)	30,000	6,000	N/A	15,000	15,000	10,500	1,500	78,000	109,320	187,320
J.A. MacNaughton	30,000	6,000	N/A	15,000	16,500	7,500	0	0	184,320	184,320
D.P. O’Brien	30,000	6,000	N/A	13,500	10,500	1,500	1,500	33,000	139,320	172,320
H.G. Schaefer(3)(6)	12,725	1,945	1,296	7,500	16,500	0	0	39,967	0	39,967
W.T. Stephens(4)(7)	20,275	4,055	N/A	7,500	6,000	6,000	1,500	0	118,210	118,210
D.M.G. Stewart	30,000	3,000	N/A	15,000	9,000	1,500	1,500	60,000	109,320	169,320

⁽¹⁾Total Deferred Share Units credited includes the amount of the retainer fees, attendance fees and travel fees elected to be received in Deferred Share Units and the grant of 3,000 Deferred Share Units made in September 2007 to all directors except Mr. Stephens who received 2,000 Deferred Share Units (prorated from April 27, 2007), which had an initial cash value of approximately $36.44 per Deferred Share Unit.

⁽²⁾Fees are aggregate amounts respecting duties performed on both TransCanada and TCPL Boards.

⁽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.

⁽⁴⁾U.S. directors are paid or credited these amounts, including Deferred Share Unit equivalents, based on U.S. dollars.

⁽⁵⁾Mr. Jackson’s Board attendance fee includes the fee of $3,000 in respect of each Board meeting chaired. Approximately half of Mr. Jackson’s retainer fee for acting as Chair was paid in Deferred Share Units, which was represented by a grant of 5,000 Deferred Share Units in September 2007. These Deferred Share Units had an initial cash value of approximately $36.44 per Deferred Share Unit.

⁽⁶⁾Mr. Schaefer’s retainer fee amount includes the fee of $3,000 in respect of duties performed as Vice-Chair from January 1, 2007 to April 27, 2007. Mr. Schaefer retired from the Board on April 27, 2007.

⁽⁷⁾Mr. Stephens was elected to the Board on April 27, 2007. Mr. Stephens previously served on the Board from 2000 to 2005.

Share Unit Plan for Non-Employee Directors

The Share Unit Plan for Non-Employee Directors (1998) was established in 1998 and was amended and restated effective January 1, 2007. Prior to the January 1, 2007 amendment, the Deferred Share Unit 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 (including travel fees) in Deferred Share Units. The Deferred Share Unit Plan also allows the Governance Committee to grant units as additional directors’

TRANSCANADA PIPELINES LIMITED 23

compensation. In September 2007, a grant of 3,000 Deferred Share Units was made to each director other than the Chair, the CEO and Mr. Stephens. As the Chair of the Board, Mr. Jackson received 5,000 Deferred Share Units and Mr. Stephens received 2,000 Deferred Share Units as he joined the Board on April 27, 2007.

Initially the value of a Deferred Share Unit 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 Deferred Share Units in September 2007 had an initial cash value of approximately $109,320. Mr. Stephen’s grant of 2,000 units had an initial cash value of approximately $72,880 and Mr. Jackson’s grant of 5,000 units had an initial cash value of approximately $182,200. The value of a Deferred Share Unit, 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 Deferred Share Unit accrues an amount equal to such dividends, which amount is then reinvested in additional Deferred Share Units at a price equal to the then market value of a common share. Deferred Share Units 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

Information relating to TCPL’s executive compensation and other information is provided in Schedule “F” to this AIF. The information is excerpts from TransCanada’s Proxy Circular. Board and committee meetings of TransCanada and TCPL run concurrently. TCPL is the principal operating subsidiary of TransCanada.

ADDITIONAL INFORMATION

1.Additional information in relation to TCPL may be found under TCPL’s profile on SEDAR at www.sedar.com.

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

TRANSCANADA PIPELINES LIMITED 24

GLOSSARY

AIF	Annual Information Form of TransCanada PipeLines Limited dated February 25, 2008	HS&E	Health, Safety and Environment
Alberta System	A natural gas transmission system throughout the province of Alberta	Iroquois System	A natural gas pipeline system in New York and Connecticut
ANR	American Natural Resources Company and ANR Storage Company	LNG	Liquefied Natural Gas
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	MD&A	TCPL’S Management’s Discussion and Analysis dated February 25, 2008
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	mmcf/d	Million cubic feet per day
AUC	Alberta Utilities Commission	MW	Megawatts
Bcf	Billion cubic feet	NBPL	Northern Border Pipeline Company
Bécancour	A power plant near Trois-Rivieères, Québec	NBPL System	A natural gas transmission system located in the upper midwestern portion of the U.S.
Board	TCPL’s Board of Directors	NEB	National Energy Board
Broadwater	A proposed offshore LNG facility in Long Island Sound, New York	Noarth Baja	A natural gas pipeline in southern California
Bruce A	Bruce Power A L.P.	NOVA	NOVA Corporation
Bruce B	Bruce Power L.P.	NYSE	New York Stock Exchange
Cacouna	The Cacouna Energy LNG facility in Cacouna, Québec	Portland	A natural gas pipeline that runs through Maine and New Hampshire into Massachusetts
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	PPA	Power Purchase Arrangement
CAPLA	Canadian Alliance of Pipeline Landowner’s Association	Proxy Circular	TransCanda’s Management Proxy Circular dated February 25, 2008
Cartier Wind Energy Project	Six wind energy projects contracted by Hydro-Québec Distribution representing a total of 740 MW in the Gaspé region of Québec	Sheerness	A power plant consisting of two 390 MW coal-fired thermal powered generating units
CSA	Canadian Securities Administrators	Shell	Shell US Gas & Power LLC
EUB	Alberta Energy and Utilities Board	SOX	U.S. Sarbanes-Oxley Act of 2002
External Auditors	KPMG LLP	Sundance	Two coal fired electrical generating facilities which produce 560 MW and 706 MW, respectively.
FEIS	Final Environment Impact Statement	TCPL or the Company	TransCanada PipeLines Limited
FERC	Federal Energy Regulatory Commission (USA)	TQM	Trans Québec & Maritimes Pipeline Inc.
Framework	The Regulatory Framework for Air Emissions	TransCanada	TransCanda Corporation
Foothills System	A natural gas pipeline system in southeastern B.C., southern Alberta and southwestern Saskatchewan	TSX	Toronto Stock Exchange
GTNC	Gas Transmission Northwest Corporation	Tuscarora	Tuscarora Gas Transmission Company
GTN System	A natural gas transmission system running from northwestern Idaho, through Washington and Oregon to the California border	Tuscarora System.	A natural gas pipeline that runs from Oregon through northeast California to Reno, Nevada
Great Lakes	Great Lakes Gas Transmission Limited Partnership	U.S.	United States
Great Lakes System	A natural gas pipeline system in the north central U.S., roughly parallel to the Canada-U.S. Border	Year End	December 31, 2007
GUA	Gas Utilities Act (Alberta)

TRANSCANADA PIPELINES LIMITED 25

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 (km)	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 26

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 2007 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 conforms 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 President and CEO of TCPL, is not independent. Mr. Stewart was determined not to be independent as the company of which he is the sole shareholder 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 shipper community; 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.

All reporting issuers of which the nominees are presently directors of are set out in the table in TransCanada’s Proxy Circular under the heading “Business to be Transacted at the Meeting - Election of Directors – Other Public Entity Directorships and Committee Memberships”.

In 2007, independent directors of the Board met separately after every regularly scheduled meeting. There were seven such meetings during 2007.

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).

TRANSCANADA PIPELINES LIMITED 27

The attendance record of each director for all Board and committee meetings held for the 12-month period ending December 31, 2007 is set out with each director’s biography in TransCanada’s 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 2007. Unscheduled meetings are held from time to time as required; there were three unscheduled meetings of the Board in 2007. There was also four strategic issue sessions and one full-day strategic planning session of the Board held in 2007.

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 this TCPL’s AIF under Schedule “E”.

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 his performance against the previous year’s objectives. The Human Resources Committee’s report on executive compensation can be found in TCPL’s AIF under Schedule “F” 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 TransCanada, copies of governance 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 TransCanada’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 TransCanada operating facilities and project sites on an annual basis. TransCanada encourages continuing education for its directors, periodically suggests programs which may be relevant to the directors and provides funding for director education where appropriate. All Canadian directors are members of the Canadian Institute of Corporate Directors which provides another source of director education.

TRANSCANADA PIPELINES LIMITED 28

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. TransCanada’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. Any waiver of the codes of business ethics by executive officers or directors must be approved by the Board or appropriate committee and disclosed.  There have been no material departures from these codes in 2007. 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 TCPL. 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 TCPL, 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 a list of potential candidates for its future consideration.

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”, under the heading “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 annual retainer, committee and/or chair fees in the form of cash and/or 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 from the time they join the Board to reach this level of share ownership. The value of ownership levels is recalibrated when the annual cash retainer is increased.

The Human Resources Committee, which is composed entirely of independent directors, is accountable, on behalf of the Board to determine the compensation for the executive officers of TCPL and to recommend to the Board the remuneration package for the CEO. The Human Resources Committee reviews the executive compensation disclosure prior to publicly disclosing this information. The process the Human Resources Committee uses for these determinations can be found in TCPL’s AIF under Schedule “F” under the heading “Executive Compensation and Other Information - Report on Executive Compensation”.

TRANSCANADA PIPELINES LIMITED 29

Further information relating to the Human Resources Committee can be found in TCPL’s AIF under Schedule “D” under the heading “Description of Board Committees and Their Charters - Human Resources Committee”.

Information relating to compensation consulting services provided by Towers Perrin during the 2007 financial year can be found in TCPL’s AIF under Schedule “F” 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” under the heading “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 solicits input on areas of potential vulnerability or areas that the members believe could be improved or enhanced to ensure the continued effectiveness of the Board and its committees. The questionnaire also includes questions regarding personal and peer individual performance. 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.

The annual questionnaire and 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. The Chair of the Governance Committee also interviews each director annually on his or her assessment of the Chair’s performance. Each of these assessments are reported annually to the full Board. One outcome of this process in the past year was a streamlining of the meeting schedule to make more effective use of directors’ time.

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 97% overall attendance rate at Board meetings and an average 99% attendance.

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

TransCanada 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 TransCanada’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 TransCanada’s Corporate Governance Guidelines which are published on its website at www.transcanada.com.

TRANSCANADA PIPELINES LIMITED 30

SCHEDULE “C”

CHARTER OF THE AUDIT COMMITTEE

1.Purpose

The Audit Committee shall assist the Board of Directors (the ”Board”) in overseeing and monitoring, among other things, the:

·Company’s financial accounting and reporting process;

·integrity of the financial statements;

·Company’s internal control over financial reporting;

·external financial audit process;

·compliance by the Company with legal and regulatory requirements; and

·independence and performance of the Company’s internal and external auditors.

To fulfill its purpose, the Audit Committee has been delegated certain authorities by the Board of Directors that it may exercise on behalf of the Board.

2.Roles and Responsibilities

I.Appointment of the Company’s External Auditors

Subject to confirmation by the external auditors of their compliance with Canadian and U.S. regulatory registration requirements, the Audit Committee shall recommend to the Board the appointment of the external auditors, such appointment to be confirmed by the Company’s shareholders at each annual meeting. The Audit Committee shall also recommend to the Board the compensation to be paid to the external auditors for audit services and shall pre-approve the retention of the external auditors for any permitted non-audit service and the fees for such service. The Audit Committee shall also be directly responsible for the oversight of the work of the external auditor (including resolution of disagreements between management and the external auditor regarding financial reporting) for the purpose of preparing or issuing an audit report or related work. The external auditor shall report directly to the Audit Committee.

The Audit Committee shall also receive periodic reports from the external auditors regarding the auditors’ independence, discuss such reports with the auditors, consider whether the provision of non-audit services is compatible with maintaining the auditors’ independence and the Audit Committee shall take appropriate action to satisfy itself of the independence of the external auditors.

II.Oversight in Respect of Financial Disclosure

The Audit Committee, to the extent it deems it necessary or appropriate, shall:

(a)          review, discuss with management and the external auditors and recommend to the Board for approval, the Company’s audited annual financial statements, annual information form including management discussion and analysis, all financial statements in prospectuses and other offering memoranda, financial statements required by regulatory authorities, all prospectuses and all documents which may be incorporated by reference into a prospectus, including without limitation, the annual proxy circular, but excluding any pricing supplements issued under a medium term note prospectus supplement of the Company;

(b)review, discuss with management and the external auditors and recommend to the Board for approval the release to the public of the Company’s interim reports, including the financial statements, management discussion and analysis and press releases on quarterly financial results;

TRANSCANADA PIPELINES LIMITED 31

(c)          review and discuss with management and external auditors the use of “pro forma” or “adjusted” non-GAAP information and the applicable reconciliation;

(d)review and discuss with management and external auditors financial information and earnings guidance provided to analysts and rating agencies; provided, however, that such discussion may be done generally (consisting of discussing the types of information to be disclosed and the types of presentations to be made). The Audit Committee need not discuss in advance each instance in which the Company may provide earnings guidance or presentations to rating agencies;

(e)review with management and the external auditors major issues regarding accounting and auditing principles and practices, including any significant changes in the Company’s selection or application of accounting principles, as well as major issues as to the adequacy of the Company’s internal controls and any special audit steps adopted in light of material control deficiencies that could significantly affect the Company’s financial statements;

(f)review and discuss quarterly reports from the external auditors on:

(i)all critical accounting policies and practices to be used;

(ii)         all alternative treatments of financial information within generally accepted accounting principles that have been discussed with management, ramifications of the use of such alternative disclosures and treatments, and the treatment preferred by the external auditor;

(iii)        other material written communications between the external auditor and management, such as any management letter or schedule of unadjusted differences;

(g)review with management and the external auditors the effect of regulatory and accounting initiatives as well as off-balance sheet structures on the Company’s financial statements;

(h)review with management, the external auditors and, if necessary, legal counsel, any litigation, claim or contingency, including tax assessments, that could have a material effect upon the financial position of the Company, and the manner in which these matters have been disclosed in the financial statements;

(i)review disclosures made to the Audit Committee by the Company’s CEO and CFO during their certification process for the periodic reports filed with securities regulators about any significant deficiencies in the design or operation of internal controls or material weaknesses therein and any fraud involving management or other employees who have a significant role in the Company’s internal controls;

(j)discuss with management the Company’s material financial risk exposures and the steps management has taken to monitor and control such exposures, including the Company’s risk assessment and risk management policies.

III.Oversight in Respect of Legal and Regulatory Matters

(a)          review with the Company’s General Counsel legal matters that may have a material impact on the financial statements, the Company’s compliance policies and any material reports or inquiries received from regulators or governmental agencies.

IV.Oversight in Respect of Internal Audit

(a)          review the audit plans of the internal auditors of the Company including the degree of coordination between such plan and that of the external auditors and the extent to which the planned audit scope can be relied upon to detect weaknesses in internal control, fraud or other illegal acts;

(b)review the significant findings prepared by the internal auditing department and recommendations issued by the Company or by any external party relating to internal audit issues, together with management’s response thereto;

(c)review compliance with the Company’s policies and avoidance of conflicts of interest;

TRANSCANADA PIPELINES LIMITED 32

(d)          review the adequacy of the resources of the internal auditor to ensure the objectivity and independence of the internal audit function, including reports from the internal audit department on its audit process with associates and affiliates;

(e)          ensure the internal auditor has access to the Chair of the Audit Committee and of the Board and to the Chief Executive Officer and meet separately with the internal auditor to review with him any problems or difficulties he may have encountered and specifically:

(i)any difficulties which were encountered in the course of the audit work, including restrictions on the scope of activities or access to required information, and any disagreements with management;

(ii)any changes required in the planned scope of the internal audit; and

(iii)the internal audit department responsibilities, budget and staffing;

and to report to the Board on such meetings;

(f)bi-annually review officers’ expenses and aircraft usage reports.

V.Insight in Respect of the External Auditors

(a)review the annual post-audit or management letter from the external auditors and management’s response and follow-up in respect of any identified weakness, inquire regularly of management and the external auditors of any significant issues between them and how they have been resolved, and intervene in the resolution if required;

(b)review the quarterly unaudited financial statements with the external auditors and receive and review the review engagement reports of external auditors on unaudited financial statements of the Company;

(c)          receive and review annually the external auditors’ formal written statement of independence delineating all relationships between itself and the Company;

(d)meet separately with the external auditors to review with them any problems or difficulties the external auditors may have encountered and specifically:

(i)any difficulties which were encountered in the course of the audit work, including any restrictions on the scope of activities or access to required information, and any disagreements with management; and

(ii)any changes required in the planned scope of the audit;

and to report to the Board on such meetings;

(e)review with the external auditors the adequacy and appropriateness of the accounting policies used in preparation of the financial statements;

(f)meet with the external auditors prior to the audit to review the planning and staffing of the audit;

(g)receive and review annually the external auditors’ written report on their own internal quality control procedures; any material issues raised by the most recent internal quality control review, or peer review, of the external auditors, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, and any steps taken to deal with such issues;

(h)review and evaluate the external auditors, including the lead partner of the external auditor team;

(i)          ensure the rotation of the lead (or coordinating) audit partner having primary responsibility for the audit and the audit partner responsible for reviewing the audit as required by law.

TRANSCANADA PIPELINES LIMITED 33

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

(a)          pre-approve all audit services (which may entail providing comfort letters in connection with securities underwritings) and all permitted non-audit services, other than non-audit services where:

(i)the aggregate amount of all such non-audit services provided to the Company constitutes not more than 5% of the total fees paid by the Company and its subsidiaries to the external auditor during the fiscal year in which the non-audit services are provided;

(ii)         such services were not recognized by the Company at the time of the engagement to be non-audit services; and

(iii)        such services are promptly brought to the attention of the Audit Committee and approved prior to the completion of the audit by the Audit Committee or by one or more members of the Audit Committee to whom authority to grant such approvals has been delegated by the Audit Committee;

(b)approval by the Audit Committee of a non-audit service to be performed by the external auditor shall be disclosed as required under securities laws and regulations;

(c)the Audit Committee may delegate to one or more designated members of the Audit Committee the authority to grant pre-approvals required by this subsection. The decisions of any member to whom authority is delegated to pre-approve an activity shall be presented to the Audit Committee at its first scheduled meeting following such pre-approval;

(d)if the Audit Committee approves an audit service within the scope of the engagement of the external auditor, such audit service shall be deemed to have been pre-approved for purposes of this subsection.

VII.Oversight in Respect of Certain Policies

(a)review and recommend to the Board for approval policy changes and program initiatives deemed advisable by management or the Audit Committee with respect to the Company’s codes of business conduct and ethics;

(b)         obtain reports from management, the Company’s senior internal auditing executive and the external auditors and report to the Board on the status and adequacy of the Company’s efforts to ensure its businesses are conducted and its facilities are operated in an ethical, legally compliant and socially responsible manner, in accordance with the Company’s codes of business conduct and ethics;

(c)establish a non-traceable, confidential and anonymous system by which callers may ask for advice or report any ethical or financial concern, ensure that procedures for the receipt, retention and treatment of complaints in respect of accounting, internal controls and auditing matters are in place, and receive reports on such matters as necessary;

(d)annually review and assess the adequacy of the Company’s public disclosure policy;

(e)review and approve the Company’s hiring policies for employees or former employees of the external auditors (recognizing the Sarbanes-Oxley Act of 2002 does not permit the CEO, controller, CFO or chief accounting officer to have participated in the Company’s audit as an employee of the external auditors’ during the preceding one-year period) and monitor the Company’s adherence to the policy.

VIII.Oversight in Respect of Financial Aspects of the Company’s Pension Plans, specifically:

(a)provide advice to the Human Resources Committee on any proposed changes in the Company’s pension plans in respect of any significant effect such changes may have on pension financial matters;

(b)review and consider financial and investment reports and the funded status relating to the Company’s pension plans and recommend to the Board on pension contributions;

(c)          receive, review and report to the Board on the actuarial valuation and funding requirements for the Company’s pension plans;

TRANSCANADA PIPELINES LIMITED 34

(d)review and approve annually the Statement of Investment Policies and Procedures (“SIP&P”);

(e)approve the appointment or termination of auditors and investment managers.

IX.Oversight in Respect of Internal Administration

(a)review annually the reports of the Company’s representatives on certain audit committees of subsidiaries and affiliates of the Company and any significant issues and auditor recommendations concerning such subsidiaries and affiliates;

(b)review the succession plans in respect of the Chief Financial Officer, the Vice President, Risk Management and the Director, Internal Audit;

(c)review and approve guidelines for the Company’s hiring of employees or former employees of the external auditors who were engaged on the Company’s account.

X.Oversight Function

While the Audit Committee has the responsibilities and powers set forth in this Charter, it is not the duty of the Audit Committee to plan or conduct audits or to determine that the Company’s financial statements and disclosures are complete and accurate or are in accordance with generally accepted accounting principles and applicable rules and regulations. These are the responsibilities of management and the external auditors. The Audit Committee, its Chair and any of its members who have accounting or related financial management experience or expertise, are members of the Board, appointed to the Audit Committee to provide broad oversight of the financial disclosure, financial risk and control related activities of the Company, and are specifically not accountable nor responsible for the day to day operation of such activities. Although designation of a member or members as an “audit committee financial expert” is based on that individual’s education and experience, which that individual will bring to bear in carrying out his or her duties on the Audit Committee, designation as an “audit committee financial expert” does not impose on such person any duties, obligations or liability that are greater than the duties, obligations and liability imposed on such person as a member of the Audit Committee and Board in the absence of such designation. Rather, the role of any audit committee financial expert, like the role of all Audit Committee members, is to oversee the process and not to certify or guarantee the internal or external audit of the Company’s financial information or public disclosure.

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 U.S. 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).

4.Appointment of Audit Committee Members

The members of the Audit Committee shall be appointed by the Board from time to time, on the recommendation of the Governance Committee and shall hold office until the next annual meeting of shareholders or until their successors are earlier appointed or until they cease to be Directors of the Company.

TRANSCANADA PIPELINES LIMITED 35

5.Vacancies

Where a vacancy occurs at any time in the membership of the Audit Committee, it may be filled by the Board on the recommendation of the Governance Committee.

6.Audit Committee Chair

The Board shall appoint a Chair of the Audit Committee who shall:

(a)review and approve the agenda for each meeting of the Audit Committee and as appropriate, consult with members of management;

(b)preside over meetings of the Audit Committee;

(c)report to the Board on the activities of the Audit Committee relative to its recommendations, resolutions, actions and concerns; and

(d)meet as necessary with the internal and external auditors.

7.Absence of Audit Committee Chair

If the Chair of the Audit Committee is not present at any meeting of the Audit Committee, one of the other members of the Audit Committee present at the meeting shall be chosen by the Audit Committee to preside at the meeting.

8.Secretary of Audit Committee

The Corporate Secretary shall act as Secretary to the Audit Committee.

9.Meetings

The Chair, or any two members of the Audit Committee, or the internal auditor, or the external auditors, may call a meeting of the Audit Committee. The Audit Committee shall meet at least quarterly. The Audit Committee shall meet periodically with management, the internal auditors and the external auditors in separate executive sessions.

10.Quorum

A majority of the members of the Audit Committee, present in person or by telephone or other telecommunication device that permit all persons participating in the meeting to speak to each other, shall constitute a quorum.

11.Notice of Meetings

Notice of the time and place of every meeting shall be given in writing or facsimile communication to each member of the Audit Committee at least 24 hours prior to the time fixed for such meeting; provided, however, that a member may in any manner waive a notice of a meeting. Attendance of a member at a meeting is a waiver of notice of the meeting, except where a member attends a meeting for the express purpose of objecting to the transaction of any business on the grounds that the meeting is not lawfully called.

12.Attendance of Company Officers and Employees at Meeting

At the invitation of the Chair of the Audit Committee, one or more officers or employees of the Company may attend any meeting of the Audit Committee.

TRANSCANADA PIPELINES LIMITED 36

13.Procedure, Records and Reporting

The Audit Committee shall fix its own procedure at meetings, keep records of its proceedings and report to the Board when the Audit Committee may deem appropriate but not later than the next meeting of the Board.

14.Review of Charter and Evaluation of Audit Committee

The Audit Committee shall review its Charter annually or otherwise, as it deems appropriate, and if necessary propose changes to the Governance Committee and the Board. The Audit Committee shall annually review the Audit Committee’s own performance.

15.Outside Experts and Advisors

The Audit Committee is authorized, when deemed necessary or desirable, to retain independent counsel, outside experts and other advisors, at the Company’s expense, to advise the Audit Committee or its members independently on any matter.

16.Reliance

Absent actual knowledge to the contrary (which shall be promptly reported to the Board), each member of the Audit Committee shall be entitled to rely on (i) the integrity of those persons or organizations within and outside the Company from which it receives information, (ii) the accuracy of the financial and other information provided to the Audit Committee by such persons or organizations and (iii) representations made by Management and the external auditors, as to any information technology, internal audit and other non-audit services provided by the external auditors to the Company and its subsidiaries.

TRANSCANADA PIPELINES LIMITED 37

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 in the discharge of its respective responsibilities. Each of the committees reviews its respective charter at least annually and, as required, recommends changes to the Governance Committee and to the Board. Each of the committees also reviews its 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:  K.E. Benson

Members:  D.H. Burney, P. Gauthier, P.L. Joskow, J.A. MacNaughton

This committee is comprised of five 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 financial statements in prospectuses and other offering memoranda, any financial statements required by regulatory authorities and all prospectuses and documents which maybe incorporated by reference into a prospectus, 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 (as defined in Schedule "B" of TCPL’s AIF) is contained in TCPL’s Annual Information Form for the year ending December 31, 2007 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 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 eight meetings of the Audit Committee in 2007 (six regularly scheduled and two special).

TRANSCANADA PIPELINES LIMITED 38

GOVERNANCE COMMITTEE

Chair:  W.K. Dobson

Members:  D.H. Burney, P.L. Joskow, J.A. MacNaughton, D.P. O’Brien

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 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 ensures the Company has a best practice orientation package and monitors continuing education for all directors. In addition, the Committee has responsibility for oversight of the Company’s Strategic Planning process.

There were two meetings of the Governance Committee in 2007.

HUMAN RESOURCES COMMITTEE

Chair:  K.L. Hawkins

Members:  W.K. Dobson, E.L. Draper, D.P. O’Brien, W.T. Stephens

This committee is comprised of five 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 performance 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. The Committee is also responsible for the review of the executive share ownership levels.

There were five meetings of the Human Resources Committee in 2007 (four regularly scheduled and one special).

HEALTH, SAFETY AND ENVIRONMENT COMMITTEE

Chair:  E.L. Draper

Members:  P. Gauthier, K.L. Hawkins, W.T. Stephens, 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, security 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, security and environmental matters are effective, including policies and practices to prevent loss or injury to TCPL’s employees and its assets, networks or infrastructure from malicious acts, natural disasters or other crisis situations. The committee reviews reports and, when appropriate, makes recommendations to the Board on TCPL’s policies and procedures related to health, safety, security 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 2007.

TRANSCANADA PIPELINES LIMITED 39

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 was a non-voting member of all committees of the Board up until October 29, 2007. Subsequent to that date, the Board adopted the practice of holding simultaneous meetings of certain committees and as a result, the Chair remained a non-voting member of the Governance and Human Resources Committees. The simultaneous sitting of certain committees allows more time to be available for each committee to focus on its respective responsibilities.

TRANSCANADA PIPELINES LIMITED 40

SCHEDULE “E”

CHARTER OF THE BOARD OF DIRECTORS

I. INTRODUCTION

A.The Board’s primary responsibility is to foster the long-term success of the Company consistent with the Board’s fiduciary responsibility to the shareholders to maximize shareholder value.

B.The Board of Directors has plenary power. Any responsibility not delegated to management or a committee of the Board remains with the Board. This Charter is prepared to assist the Board and management in clarifying responsibilities and ensuring effective communication between the Board and management.

II. COMPOSITION AND BOARD ORGANIZATION

A.Nominees for directors are initially considered and recommended by the Governance Committee of the Board, approved by the entire Board and elected annually by the shareholders of the Company.

B.The Board must be comprised of a majority of members who have been determined by the Board to be independent. A member is independent if the member has no direct or indirect relationship which could, in the view of the Board, reasonably interfere with the exercise of a member’s independent judgment.

C.Directors who are not members of management will meet on a periodic basis to discuss matters of interest independent of any influence from management.

D.Certain of the responsibilities of the Board referred to herein may be delegated to committees of the Board. The responsibilities of those committees will be as set forth in their Charter, as amended from time to time.

III. DUTIES AND RESPONSIBILITIES

A. Managing the Affairs of the Board

The Board operates by delegating certain of its authorities, including spending authorizations, to management and by reserving certain powers to itself. Certain of the legal obligations of the Board are described in detail in Section IV. Subject to these legal obligations and to the Articles and By-laws of the Company, the Board retains the responsibility for managing its own affairs, including:

(i)planning its composition and size;

(ii)selecting its Chair;

(iii)nominating candidates for election to the Board;

(iv)determining independence of Board members;

(v)approving committees of the Board and membership of directors thereon;

(vi)determining director compensation; and

(vii)assessing the effectiveness of the Board, committees and directors in fulfilling their responsibilities.

B. Management and Human Resources

The Board has the responsibility for:

(i)the appointment and succession of the Chief Executive Officer (CEO) and monitoring CEO performance, approving CEO compensation and providing advice and counsel to the CEO in the execution of the CEO’s duties;(ii)approving a position description for the CEO;

(iii)reviewing CEO performance at least annually, against agreed-upon written objectives;

(iv)approving decisions relating to senior management, including the:

(a)appointment and discharge of officers of the Company and members of the senior leadership team;

(b)compensation and benefits for members of the senior leadership team;

(c)acceptance of outside directorships on public companies by executive officers (other than not-for-profit organizations);

(d)annual corporate and business unit performance objectives utilized in determining incentive compensation or other awards to officers; and

TRANSCANADA PIPELINES LIMITED 41

(e)employment contracts, termination and other special arrangements with executive officers, or other employee groups if such action is likely to have a subsequent material(1) impact on the Company or its basic human resource and compensation policies.

(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

The Board has the responsibility to:

(i)participate in strategic planning sessions to ensure that management develops, and ultimately approve, major corporate strategies and objectives;

(ii)approve capital commitment and expenditure budgets and related operating plans;

(iii)approve financial and operating objectives used in determining compensation;

(iv)approve the entering into, or withdrawing from, lines of business that are, or are likely to be, material to the Company;

(v)approve material divestitures and acquisitions; and

(vi)monitor management’s achievements in implementing major corporate strategies and objectives, in light of changing circumstances.

D. Financial and Corporate Issues

The Board has the responsibility to:

(i)take reasonable steps to ensure the implementation and integrity of the Company’s internal control and management information systems;

(ii)monitor operational and financial results;

(iii)approve annual financial statements and related Management’s Discussion and Analysis, review quarterly financial results and approve the release thereof by management;

(iv)approve the Management Proxy Circular, Annual Information Form and documents incorporated by reference therein;

(v)declare dividends;

(vi)approve financings, changes in authorized capital, issue and repurchase of shares, issue and redemption of debt securities, listing of shares and other securities, issue of commercial paper, and related prospectuses and trust indentures;

(vii)recommend appointment of external auditors and approve auditors’ fees;

(viii)approve banking resolutions and significant changes in banking relationships;

(ix)approve appointments, or material changes in relationships with corporate trustees;

(x)approve contracts, leases and other arrangements or commitments that may have a material impact on the Company;

(xi)approve spending authority guidelines; and

(xii)approve the commencement or settlement of litigation that may have a material impact on the Company.

⁽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.

TRANSCANADA PIPELINES LIMITED 42

E. Business and Risk Management

The Board has the responsibility to:

(i)take all reasonable steps to ensure that management has identified the principal risks of the Company’s business and implemented appropriate strategies to manage these risks, understands the principal risks and achieves a proper balance between risks and benefits;

(ii)review reports on capital commitments and expenditures relative to approved budgets;

(iii)review operating and financial performance relative to budgets or objectives;

(iv)receive, on a regular basis, reports from management on matters relating to, among others, ethical conduct, environmental management, employee health and safety, human rights, and related party transactions; and

(v)assess and monitor management control systems by evaluating and assessing information provided by management and others (e.g. internal and external auditors) about the effectiveness of management control systems.

F. Policies and Procedures

The Board has responsibility to:

(i)monitor compliance with all significant policies and procedures by which the Company is operated;

(ii)direct management to ensure the Company operates at all times within applicable laws and regulations and to the highest ethical and moral standards;

(iii)provide policy direction to management while respecting its responsibility for day-to-day management of the Company’s businesses; and

(iv)review significant new corporate policies or material amendments to existing policies (including, for example, policies regarding business conduct, conflict of interest and the environment).

G. Compliance Reporting and Corporate Communications

The Board has the responsibility to:

(i)take all reasonable steps to ensure the Company has in place effective disclosure and communication processes with shareholders and other stakeholders and financial, regulatory and other recipients;

(ii)approve interaction with shareholders on all items requiring shareholder response or approval;

(iii)take all reasonable steps to ensure that the financial performance of the Company is adequately reported to shareholders, other security holders and regulators on a timely and regular basis;

(iv)take all reasonable steps to ensure that financial results are reported fairly and in accordance with generally accepted accounting principles;

(v)take all reasonable steps to ensure the timely reporting of any other developments that have significant and material impact on the Company; and

(vi)report annually to shareholders on the Board’s stewardship for the preceding year (the Annual Report).

IV. GENERAL LEGAL OBLIGATIONS OF THE BOARD OF DIRECTORS

The Board is responsible for:

(i)directing management to ensure legal requirements have been met and documents and records have been properly prepared, approved and maintained;

(ii)approving changes in the By-laws and Articles of Incorporation, matters requiring shareholder approval, and agendas for shareholder meetings;

(iii)approving the Company’s legal structure, name, logo, mission statement and vision statement; and

(iv)performing such functions as it reserves to itself or which cannot, by law, be delegated to Committees of the Board or to management.

TRANSCANADA PIPELINES LIMITED 43

SCHEDULE “F”

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 the compensation of TransCanada’s CEO, Presidents, and Executive Vice-Presidents (collectively, the “Executives”).

COMMITTEE INFORMATION

Composition of the Committee

The Committee is composed of five directors, K.L. Hawkins (Chair), W.K. Dobson, E.L. Draper, D.P. O’Brien, and W.T. Stephens 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 TransCanada’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 "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" of TCPL's AIF - 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:

•holding in-camera sessions without Company management present prior to and following every regularly scheduled Committee meeting;

•hiring external consultants and advisors and requiring their attendance at specified Committee meetings;

•annually approving a Committee checklist that sets out the timetable of all regularly occurring accountabilities and that provides context for the discussion of related items;

•using a two-step review process where most recurring items are provided for the Committee’s initial review at a meeting prior to the approval meeting;

•conducting annual reviews of detailed compensation tally sheets and modeled compensation outcomes for the Executives;

•granting stock options once per year during the concurrent annual deliberation of Total Direct Compensation for the Executives, and granting outside of that process only under extenuating circumstances.

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 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.

External Advice

The Committee engages its own consultants and, from time-to-time legal advisors, 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 2007. The mandate of the Consultant was to provide an assessment of management’s proposals relating to the compensation of the Executives. In 2007, the Consultant provided services to the Committee in accordance with this mandate and attended portions of all Committee meetings, as requested by the Chair of the Committee. The fees paid to Towers Perrin in 2007 for the Consultant’s services to the Committee were approximately $107,000. The performance of the Consultant is reviewed and their engagement is approved by the Committee on an annual basis.

TRANSCANADA PIPELINES LIMITED 44

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 TransCanada in 2007. In 2007, other, separate consultants from Towers Perrin did provide the Company with executive and non-executive compensation analysis, Board compensation analysis, benefit and pension actuarial consulting services for both U.S. and Canadian operations and the fees paid for these services were approximately $2.4 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 TransCanada’s Executive Compensation Program is based on a compensation philosophy that:

•supports employee attraction, engagement and retention;

•is competitive with the external compensation market;

•aligns executive interests with shareholders and customers; and

•rewards accomplishments through “pay-for-performance”.

The Executive Compensation Program specifically provides for Total Direct Compensation 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.

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 TransCanada, and represent the market in which TransCanada may compete for talent (the ”Comparator Group”).

The composition of the Comparator Group is reviewed annually by the Committee for its on-going business relevance to TransCanada. An overview of the 2006 characteristics of the Comparator Group, as compared to TransCanada, is provided in the following table:

	TransCanada	Comparator Group
INDUSTRY	North. American Pipelines, Power	Canadian Oil and Gas, Pipelines, Power, Utilities
LOCATION	Calgary	Principally Alberta
		MEDIAN	75th PERCENTILE
REVENUE(1)	$7.5 billion	$5.8 billion	$13.2 billion
MARKET CAPITALIZATION(2)	$21.6 billion	$21.0 billion	$44.7 billion
ASSETS(1)	$25.9 billion	$15.3 billion	$18.4 billion
EMPLOYEES(1)	Approximately 2,350	3,010	4,802

⁽¹⁾  Revenue, assets and number of employees reflect 2006 information.

⁽²⁾ Market Capitalization value noted is calculated as at October 31, 2007 by multiplying the monthly
closing price by the quarterly common shares outstanding for the most recently available quarter.

TRANSCANADA PIPELINES LIMITED 45

Pay For Performance

PERFORMANCE OBJECTIVES

TransCanada’s Board sets annual corporate objectives directed at achieving the results required to deliver on TransCanada’s key longer-term strategies for growth and value creation. The Committee then approves annual individual performance objectives for the Executives that align with these corporate objectives. The objectives for both corporate and individual Executive performance reflect a combination of quantitative and qualitative measures with no pre-determined weightings assigned.

At the end of the fiscal year, the Board looks at the corporate results achieved and, following discussion with management, assesses the relative outcomes against these objectives. To make this assessment, where appropriate, the Board looks at both absolute and relative performance against specific peer companies in order to give a balanced perspective of achievement against the pre-established objectives.

The Committee considers the Board’s assessment of corporate performance as general context for their review of individual Executive performance which, in turn, is then used to determine the Total Direct Compensation for the Executives.

AWARDING COMPENSATION

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

If actual performance		Total Direct Compensation will be
meets objectives (satisfactory)	à	comparable to median compensation from the Comparator Group Total Direct Compensation data
exceeds objectives (above satisfactory)	à	comparable to above-median compensation(1)
falls short of objectives (below satisfactory)	à	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 assessed 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.

2007 CORPORATE PERFORMANCE

The following is a summary of the performance categories, examples of some of the performance measures used in each respective category and highlights of results achieved in 2007.

PERFORMANCE CATEGORY	EXAMPLES OF PERFORMANCE MEASURES	HIGHLIGHTS OF RESULTS ACHIEVED IN 2007
Financial Performance	•Earnings per share	•Strong financial performance in 2007 including:
	•Revenue •Funds generated from operations •Total Shareholder Return	•Net earnings of $1.22 billion ($2.31 per share) increased from $1.08 billion ($2.21 per share) in 2006 – an increase of approximately five per cent on a per share basis. •Comparable earnings for the year of $1.107 billion ($2.09 per share) - an increase of approximately 10 per cent on a per share basis compared to 2006. •Funds generated from operations for the year of $2.621 billion - an increase of approximately 10 per cent from 2006. •Annual dividend of $1.36 per share – an increase of six per cent from an annual dividend of $1.28 per share in 2006.

TRANSCANADA PIPELINES LIMITED 46

PERFORMANCE CATEGORY	EXAMPLES OF PERFORMANCE MEASURES	HIGHLIGHTS OF RESULTS ACHIEVED IN 2007
Operational Excellence	•Costs •Safety •Environment	•Met departmental and common cost objectives while achieving overall productivity gains in pipe and power operations. •Top level safety performance compared with industry peers. •Named again to the Dow Jones Sustainability World Index and the Dow Jones Sustainability North American Index in 2007.
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 outstanding performance on pipeline customer satisfaction and service, as reflected in external customer satisfaction surveys. •Recognized for corporate governance practices in external rankings and excellence in compensation disclosure by the Canadian Coalition for Good Governance. •Significant progress toward becoming a higher performing organization through implementation of comprehensive leadership development and performance management processes. •Maintained strong financial capacity and credit ratings in Canada and the U.S. which has allowed the Company to complete large transactions.
Grow and maximize longer-term value of Pipeline and Energy businesses	•Progress on longer-term value adding initiatives •Greenfield projects •Completed acquisitions	•Achieved negotiated settlements on Canadian Mainline and GTN System. •Submitted a complete application for a license to construct the Alaska Pipeline project under the Alaska Gasline Inducement Act. •Regulatory approvals received and commercial arrangements progressed related to a number of core infrastructure initiatives, including the Keystone oil pipeline project. •Continuing notable progress on longer-term initiatives including liquefied natural gas opportunities, northern gas pipeline development, Bruce A refurbishment and restart, wind power projects. •Successful integration of newly acquired U.S. pipeline businesses or operations (ANR, Great Lakes, Northern Border, Tuscarora).

The Committee and the Board were of the opinion that TransCanada’s 2007 performance delivered results that exceeded objectives in the areas of financial performance and growth and were above satisfactory on other notable objectives. Based on this corporate performance achievement and the assessment of individual performance, the Committee, in aggregate, awarded above-median Total Direct Compensation 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 Total Direct Compensation awards is linked to, and dependent upon, TransCanada’s ability to replicate and sustain annual performance over the longer term.

To ensure that the Company’s longer-term compensation programs are effective in delivering on this intent, in 2007 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 corporate performance was appropriate for all of the Executives and that, in aggregate, the resulting compensation modeled under various corporate performance scenarios was reasonable, not excessive, and delivered the intended differentiation of compensation value.

TRANSCANADA PIPELINES LIMITED 47

Components of Total Direct Compensation

TransCanada’s Total Direct Compensation 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 Total Direct Compensation 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 2007 financial year (collectively, the “Named Executive Officers”) is noted under the heading, “Executive Compensation Program - Elements of the Executive Compensation Program” below.

Elements of the Executive Compensation Program

In 2007, 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 Total Direct Compensation	Type of Compensation	Average 2007 Pay Mix(1)	Element	Form	Plan	Performance Period
FIXED	Annual	22%	Base Salary	Cash	“Base Pay Program”	1 year
VARIABLE	Annual	29%	Short-term Incentive	Cash	“Incentive Compensation Program”	1 year
	Longer-term	37%	Medium-term Incentive	Performance Share Units	“Executive Share Unit Plan”	Up to 3 years with vesting at end of term
		12%	Long-term Incentive	Stock Options	“Stock Option Plan”	Vesting 33 1¤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 Total Direct Compensation. It is expressed as an aggregate average percentage of Total Direct Compensation for the Named Executive Officers. The relative value of Total Direct Compensation 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.

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 TransCanada’s market-based compensation practices, all Executive roles are individually matched to similar roles in the Comparator Group. Base pay rates are typically targeted at the median of the market and are reviewed annually. Variance from the median could occur on the basis of sustained individual performance or material differences in an Executive’s responsibilities versus the market comparator role. Changes in base pay are typically made 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 TransCanada’s performance-based annual variable compensation program. The Committee’s comprehensive assessment of the overall business performance of TransCanada, 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 Incentive Compensation Program provides 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 Incentive Compensation Program are made in the first quarter following the completion of the financial year.

TRANSCANADA PIPELINES LIMITED 48

Variable Compensation – Longer-Term

The total value of longer-term incentive compensation (“Total Long Term Incentive Value”) granted each year is established as part of an Executive’s overall performance-based Total Direct Compensation. Total Long Term Incentive Value is derived from the established Total Direct Compensation value minus Total Cash (the sum of Base Pay and actual awards from the Incentive Compensation program).

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

·business strategy objectives;

·consideration of the funding requirements for awards from both plans;

·the individual plan designs and each Executive’s ability to impact medium and longer-term performance outcomes; and

·the valuation of grants.

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

EXECUTIVE SHARE UNIT PLAN

Medium-term incentives are granted through the Executive Share Unit Plan. The purpose of this plan is to align a 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 TransCanada.

Under the Executive Share Unit Plan, Executives receive a provisional grant of notional units that is based on the allocated award value from Total Long Term Incentive Value 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 provisionally 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 2007, participants received a grant of units that was valued based on the volume-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	à	zero units vest; no payment is made
At threshold	à	50% of units vest for payment
At target	à	100% of units vest for payment
At or above maximum	à	150% of units vest for payment

The performance measures that will be used by the Committee to determine the vesting of the 2007 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 (known as the “ESU Peer Group”); and

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

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 criteria nor are there formulaic calculations used to create the final performance achievement for the grant. The Committee uses its judgment and discretion to assess overall performance in light of the stated criteria and business circumstances surrounding the performance achieved.

TRANSCANADA PIPELINES LIMITED 49

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 volume-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 Executive Share Unit Plan are reported as long term incentives.

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 2007.

For 2007, the exercise price of a stock option granted to Canadian executives was set as the volume-weighted average trading price for the five trading days preceding the date of the grant. Changes recently made to this price determination methodology are noted under “Changes Made to the Executive Compensation Program - Stock Option Plan Exercise Price Determination”, below.

Stock options granted in 2007 vest 33 1¤3% on each anniversary of the grant date for a period of three years and expire 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. 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 rate.

The level of ownership required under the Share Ownership Guidelines (the “Guidelines”) can be achieved by direct purchase of common shares, by participation in the TransCanada Dividend Reinvestment Plan or through unvested units granted under the Executive Share Unit Plan. In June 2006, the Committee approved an amendment to the current Guidelines to require that at least 50% of the ownership level be TransCanada common shares or units of any TransCanada sponsored limited partnership. Unvested units from the Executive Share Unit Plan count to a maximum of 50% of the ownership level. Executives and other employees generally have five years to meet the ownership requirements based on either the date they are initially included under the Guidelines or when there is a material amendment made to the Guidelines.

The Committee receives regular updates on Executive ownership levels and conformity 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, 2007 and the 20-day volume-weighted average closing price of TransCanada’s common shares at year end which was $39.77.

			ACTUAL GUIDELINE OWNERSHIP VALUE AS AT DECEMBER 31, 2007
Named Executive Officer	Minimum Ownership Requirement(1)	Minimum Guideline Ownership Value ($)	Value from Outstanding Executive Share Unit Plan Grants ($)(2)	Value from Common Shares  or LP Units ($)	Total Value ($)	Multiple of Base Salary Rate (3)
H.N. Kvisle	3 times base salary	3,600,000	1,800,000	2,145,631(4)	3,945,631	3.29
G.A. Lohnes	2 times base salary	740,000	370,000	351,249	721,249	1.95
R.K. Girling	2 times base salary	1,260,000	630,000	537,770	1,167,770	1.85
A.J. Pourbaix	2 times base salary	1,260,000	630,000	277,475	907,475	1.44
D.M. Wishart	2 times base salary	1,000,000	500,000	1,275,503	1,775,503	3.55

⁽¹⁾Other senior employees of TransCanada have a minimum ownership requirement of one times base salary.

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

⁽³⁾The Named Executive Officers have until the end of 2010 to meet the requirements outlined in the most recent amendment to the Guidelines, with the exception of Mr. Lohnes who has until the end of 2011.

⁽⁴⁾Mr. Kvisle, Director, President and Chief Executive Officer, held 53,951 common shares as of TransCanada as of December 31, 2007.

TRANSCANADA PIPELINES LIMITED 50

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 TransCanada’s Executive Compensation program. These changes impact compensation values disclosed as compensation for the Named Executive Officers in the tables contained under the heading “Executive Compensation” below.

Stock Option Plan Granting Practice

In 2007, the Committee used a modified process to grant stock options to better support the Total Direct Compensation deliberation process. This process involved having the Committee determine the dollar values to be granted via the Stock Option Plan.

During their deliberation of Total Direct Compensation for Executives, the Committee was provided with the estimated number of stock options that would be granted to reflect proposed dollar values. The dollar values were converted to the number of stock options that were approved based on an economic value per stock option. An analysis of the economic value per option was provided by an external consulting firm.

Prior to 2007, a set number of stock options per participant were approved by the Committee and were generally rounded to the nearest 500 stock options.  Under the current practice there is no longer a rounding of the number of stock options granted.  This difference may be apparent when comparing the reported number of stock options granted for various years in the Summary Compensation Table and the Equity Compensation Plan Tables below.

Stock Option Plan Exercise Price Determination

For grants made prior to 2007, the exercise price for stock options was determined based on the greater of the closing price of TransCanada’s common shares on the grant date and the volume-weighted average trading price for the five days preceding the grant date. In February 2007, TransCanada revised the exercise price determination process in its Stock Option Plan to be the volume-weighted average trading price for the five days preceding the date of the grant. In November 2007, TransCanada further revised the exercise price of a stock option to be the closing market price of TransCanada common shares on the TSX for the last trading day immediately preceding the award date of the option. For more information, please refer to the section, “Equity Compensation Plan Information – Stock Option Plan”.

GRANDFATHERED EXECUTIVE COMPENSATION PLAN

The following section provides information pertaining to an executive compensation plan under which grants 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 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 Performance Unit Plan but accruals on existing grants would continue until the last grants expire in 2012, if not redeemed prior to this date. Until 2003, one unit from the Performance Unit Plan was granted in tandem with each stock option granted under the Stock Option Plan.

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

In 2006, the Committee approved a few operational modifications to the Performance Unit Plan effective for 2007 onward, in order to maintain the alignment of this plan with the active plans. The most notable of these modifications are:

·the calculation of the maximum dividend accrual will be based on the dividends declared versus paid in a given year; and

·the performance outcome determined by the Committee for the Executive Share Unit grant that vests during the financial year in question will directly determine the awarding of the annual Performance Unit Plan accrual for that same year.

TRANSCANADA PIPELINES LIMITED 51

COMPENSATION OF THE PRESIDENT AND CHIEF EXECUTIVE OFFICER

The components of Total Direct Compensation 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 criteria as for the other Executives.

Overview of Performance

The Committee assesses the performance of the CEO on the basis of achievement against his personal performance objectives that were approved by the Board at the beginning of the year, as well as his overall contribution to the performance of the Company.  As with all other Executives, there are no pre-determined weightings assigned to the performance objectives.

In 2007, Mr. Kvisle’s personal objectives were focused on the areas of Value Creation, Creating a Strong Management Team, Building Relationships, Operational Excellence, Investor Confidence and Corporate Governance and Reputation. The following provides a summary of the Committee’s assessment of Mr. Kvisle’s performance in these performance areas:

Value Creation

Mr. Kvisle played a key role in several major strategic initiatives during 2007. The Company welcomed over 1,100 new employees through the completion of several U.S. asset acquisitions, including the acquisition of ANR Pipeline and ANR Gas Storage. These assets were successfully integrated into the TransCanada organization and have generated accretive earnings in 2007. Under Mr. Kvisle’s leadership, the Company successfully negotiated tolling settlements for the Canadian Mainline and the GTN System. Significant progress was made on gaining the necessary approvals for the Keystone oil pipeline project and construction activities are set to begin in early 2008.

Mr. Kvisle also played a pivotal role in the continuing progress on longer-term initiatives including liquefied natural gas opportunities, northern gas pipeline development including the Alaska Pipeline, the Bruce A refurbishment and restart and various wind power projects.

Creating A Strong Management Team

Mr. Kvisle continued to lead the organization in its pursuit of high performance by championing the implementation of comprehensive leadership development and performance management processes.

Building Relationships

Mr. Kvisle provided leadership for the organization in continuing to develop strong relationships with key stakeholders including shareholders, customers, governments, regulators and First Nations. The Company’s annual customer satisfaction survey in 2007 reflected a very high regard customers have for the service provided by TransCanada.

Operational Excellence

The Company achieved success in effectively managing several major projects to budget despite significant market cost pressures. Mr. Kvisle continued to demonstrate his commitment to managing costs, providing outstanding customer service, and meeting or exceeding health, safety and environmental standards.

Investor Confidence

The corporate strategy developed under Mr. Kvisle’s leadership continued to deliver strong financial results allowing the Board to increase the dividend declared in 2007 from $1.28 per share to 1.36 per share. In April, Standard & Poor’s changed its outlook on TransCanada from A- with a ‘negative’ outlook to A- ‘stable’.

Corporate Governance and Reputation

Mr. Kvisle sets a high standard and encourages excellence in corporate governance for the Company. TransCanada gives consideration to following best practices in corporate governance and the Company has an excellent reputation in this regard as evidenced, for example, by the recognition TransCanada received from the Canadian Coalition for Good Governance in 2007 for excellence in compensation disclosure. The Company was again recognized externally in 2007 for its social responsibility and community investment practices.

Summary of Performance

The Committee assessed Mr. Kvisle’s results and concluded that his performance exceeded his individual objectives in 2007 and presented this conclusion to the Board.

The Board was also of the view that Mr. Kvisle’s overall achievements and performance exceeded his individual objectives in 2007, resulting in his Total Direct Compensation being positioned above median Total Direct Compensation 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, industry and market circumstances that influenced the performance of TransCanada.

TRANSCANADA PIPELINES LIMITED 52

COMMITTEE SUMMARY

The Committee is satisfied that TransCanada’s current Executive Compensation Program reflects competitive market practices and the levels of compensation delivered under this program are relative to 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 TransCanada’s Executive Compensation Program, if required, to ensure it remains competitive and aligned with TransCanada’s compensation philosophy.

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

Chair:	K.L. Hawkins
Members:	W.K. Dobson, E.L. Draper, D.P O’Brien, W.T. Stephens

PERFORMANCE GRAPH

The following chart compares TransCanada’s five-year cumulative total shareholder return to the S&P/TSX composite index (assuming reinvestment of dividends and considering a $100 investment on December 31, 2002 in TransCanada’s common shares).

	Dec. 31, 2002	Dec. 31, 2003	Dec. 31, 2004	Dec. 31, 2005	Dec. 31, 2006	Dec. 31, 2007	Compound Annual Growth
TransCanada	100.0	127.0	141.6	180.8	207.7	214.5	16.5%
TSX	100.0	126.7	145.1	180.1	211.2	231.9	18.3%

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 material assets directly other than the common shares of TCPL and receivables from certain of TransCanada’s subsidiaries, all executive employee costs are assumed by TCPL according to a management services agreement between the two companies.

TRANSCANADA PIPELINES LIMITED 53

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" elsewhere in this Schedule “F”.

SUMMARY COMPENSATION TABLE

The following table outlines the summary of compensation earned in the 2007, 2006 and 2005 financial years by the Named Executive Officers.

	ANNUAL COMPENSATION				LONG-TERM COMPENSATION
					Awards		Payouts
Name and Principal Position of the Named Executive Officers	Year	Salary(5) ($)	Bonus(6) ($)	Other Annual Compensation(7) ($)	Securities Under Options Granted(8) (#)	Shares or Units Subject to Resale Restriction ($)		LTIP Payouts(9) ($)	All Other Compensation(10) ($)
H.N. Kvisle	2007	1,175,001	1,550,000	-	202,442	-		3,624,707	11,708
President &	2006	1,100,004	1,500,000	-	250,000	-		2,980,971	11,000
Chief Executive Officer	2005	1,050,003	1,300,000	-	160,000	-		1,852,433	10,417
G.A. Lohnes	2007	362,508	490,000	106,557	35,990	-		471,509	3,613
Executive Vice-President	2006(1)	331,973	320,000	266,013	64,000	-		345,000	11,786
& Chief Financial Officer	2005(2)	318,914	208,240	62,077	20,000	-		254,562	9,167
R.K. Girling	2007	602,502	900,000	-	107,326	-		1,263,779	5,979
President, Pipelines	2006(3)	498,346	700,000	-	190,000	-		1,192,429	28,192
	2005	460,032	500,000	-	60,000	-		740,973	25,600
A.J. Pourbaix	2007	602,502	900,000	-	107,326	-		868,810	61,479
President, Energy	2006(4)	494,172	700,000	-	190,000	-		1,064,734	71,065
	2005	440,001	500,000	-	60,000	-		740,973	49,691
D.M. Wishart	2007	475,005	550,000	-	64,267	-		936,860	46,708
Executive Vice-President,	2006	395,007	500,000	-	55,000	-		877,367	24,942
Operations & Engineering	2005	372,504	400,000	-	40,000	-		370,487	3,713

⁽¹⁾      Mr. Lohnes was appointed Executive Vice-President and Chief Financial Officer for TransCanada in June 2006 and continued in his role as President of Great Lakes 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. The values Mr. Lohnes received during his tenure as President and Chief Executive Officer of Great Lakes were provided 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 2006 of 1.2116 with the exception of the LTIP Payout which has been converted at 1.1340 based on the exchange rate as at the payment date of the grant.

⁽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 Chief Executive Officer in August 2000 and during his term, Great Lakes was a pipeline joint venture owned equally 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 2005 of 1.3015 with the exception of the LTIP Payout which has been converted at 1.560 based on the exchange rate as at the date of grant.

⁽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 for TransCanada.

⁽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 Incentive Compensation Program and are attributable to the noted financial year. Payments from the Incentive Compensation 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 USD$124,842 for 2006, and USD$47,697 for 2005. 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, and 1.3015 for 2005. As part of his repatriation to Canada, Mr. Lohnes also received a one-time special tax-protected bonus payment of $200,000. This value is being paid to Mr. Lohnes in annual installments of $70,000 in 2006, $65,000 in 2007 and $65,000 in 2008. The installments disclosed include tax reimbursements of $44,754 for 2006 and $41,557 for 2007.

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 in this column. For information, the average annual value for perquisites provided to the Named Executive Officers in 2007 was $32,882 and included such things as a 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

TRANSCANADA PIPELINES LIMITED 54

to those granted during the annual determination of Total Direct Compensation in February. Specifically, Mr. Lohnes received an additional 50,000 options, Mr. Girling and Mr. Pourbaix each received an additional 100,000 options.

⁽⁹⁾      LTIP Payouts include the value of the payments made or to be made for the grants of Executive Share Units that vested and became eligible for payout in the noted financial year, namely:

Name	2007	2006	2005
H.N. Kvisle	$3,624,707	$2,980,971	$1,852,433
G.A. Lohnes	$256,655	$345,000	$254,562
R.K. Girling	$1,018,223	$1,192,429	$740,973
A.J. Pourbaix	$868,810	$1,064,734	$740,973
D.M. Wishart	$691,304	$877,367	$370,487

A portion of the value denoted for 2007 was provided to Mr. Lohnes in U.S. dollars (or equivalent value) and has been disclosed here in Canadian dollars based on the Bank of Canada’s average annual exchange rate of 1.0748. In 2007 certain Named Executive Officers redeemed units from the Performance Unit Plan and received payments of accrued value, specifically Mr. Lohnes received $214,854, Messrs. Girling and Wishart each received $245,556. There were no Performance Unit Plan redemptions made by the Named Executive Officers in 2006 or 2005.

⁽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 2005; Mr. Pourbaix - $55,500 for 2007, $59,250 for 2006 and $39,000 for 2005; Mr. Wishart - $42,000 for 2007 and $21,000 for 2006.

This column includes TransCanada’s contributions under the 401K pension plan for Mr. Lohnes in the amounts of 10,653 for 2006 and $9,167 for 2005. 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, and 1,3015 for 2005.

Also included in this column is the value of TransCanada’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

Executive Share Unit Plan Grants

The following tables outline various outstanding grants made under the Executive Share Unit Plan.  General operation and performance criteria relating to this plan are described in the section, “Overview of Executive Compensation Elements; Variable Compensation – Longer-Term; Executive Share Unit Plan” in the Report on Executive Compensation, above.

2007 Executive Share Unit Plan Grants

The following table outlines the Executive Share Unit Plan grants that were approved in February 2007. These grants are still unvested and outstanding as at December 31, 2007 and have therefore not yet been recorded as LTIP Payouts in the Summary Compensation Table, above.

	Securities,	Performance or	ESTIMATED FUTURE PAYOUTS UNDER NON-SECURITIES-PRICE-BASED PLANS (units)(2)
Name	Units or Other Rights(1) (#)	Other Period Until Maturation or Payout	Below Threshold (#)	Threshold (#)	Target (#)	Maximum (#)
H.N. Kvisle	58,806	Dec. 31, 2009	0	29,403	58,806	88,209
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 Executive Share Unit Plan. (2) Does not include the units related to reinvested dividend value.

TRANSCANADA PIPELINES LIMITED 55

2006 Executive Share Unit Plan Grants

The following table outlines the Executive Share Unit Plan grants that were approved in February 2006. These grants are still unvested and outstanding as at December 31, 2007 and have therefore not yet been recorded as LTIP Payouts in the Summary Compensation Table, above.

	Securities,	Performance or	ESTIMATED FUTURE PAYOUTS UNDER NON-SECURITIES-PRICE-BASED PLANS (units)(2)
Name	Units or Other Rights(1) (#)	Other Period Until Maturation or Payout	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 Executive Share Unit Plan. (2) Does not include the units related to reinvested dividend value.

2005 Executive Share Unit Plan Grants

The following table outlines the Executive Share Unit Plan grants that were made in 2005 and vested in 2007. The table reconciles the value that was paid to the Named Executive Officers which is disclosed under LTIP Payouts in the Summary Compensation Table, 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)(6 ($)
H.N. Kvisle	65,320	Dec. 31, 2007	81,650	3,255,386	369,321	3,624,707
G.A Lohnes	4,441	Dec. 31, 2007	5,551	221,318	35,337	256,655
R.K. Girling	18,349	Dec. 31, 2007	22,936	914,458	103,765	1,018,223
A.J. Pourbaix	15,657	Dec. 31, 2007	19,571	780,296	88,514	868,810
D.M. Wishart	12,458	Dec. 31, 2007	15,572	620,856	70,448	691,304
(1) This is the grant of units under the Executive Share Unit Plan that is used to determine vesting. The range of units that are eligible to vest under this grant are between 50% and 150%, based on performance between Threshold and Maximum, or 0% if Threshold performance is not met. (2) Based on the Committee’s assessment of the performance achieved against objectives, 125% of the granted units vested for settlement. This number does not include units related to reinvested dividends. (3) Vested units noted were valued at $39.87 per unit based on the five day volume-weighted closing price of common shares on the TSX at December 31, 2007. (4) The additional value related to the accrued value from dividends and paid relative to the vested unit total. (5) Includes both the Vested Value from Grants and Vested Value from Dividends. This settlement value is reported as an LTIP Payout in the Summary Compensation Table, above. (6) A portion of the Total Settlement value denoted here was provided to Mr. Lohnes in U.S. dollars (or equivalent value) and has been expressed here in Canadian dollars based on the Bank of Canada’s average annual exchange rate as at the payment date of the grant, namely 1.0748.

TRANSCANADA PIPELINES LIMITED 56

Supplemental Disclosure – 2008 Executive Share Unit Plan Grants

Decisions regarding Executive Share Unit Plan grants are made annually by the Committee in February prior to the publication of TransCanada’s Proxy Circular. Although not a requirement, TransCanada discloses these compensation grants for the Named Executive Officers. The following table outlines the grants under the Executive Share Unit Plan made in 2008.

Name	Securities, Units or	Performance or	ESTIMATED FUTURE PAYOUTS UNDER NON-SECURITIES PRICE-BASED PLANS (units)(2 )
	Other Rights(1)  (#)	Other Period Until Maturation or Payout	Below Threshold (#)	Threshold (#)	Target (#)	Maximum (#)
H.N. Kvisle	75,245	Dec. 31, 2010	0	37,622	75,245	112,867
G.A. Lohnes	13,732	Dec. 31, 2010	0	6,866	13,732	20,598
R.K. Girling	37,622	Dec. 31, 2010	0	18,811	37,622	56,433
A.J. Pourbaix	37,622	Dec. 31, 2010	0	18,811	37,622	56,433
D.M. Wishart	22,573	Dec. 31, 2010	0	11,287	22,573	33,860
(1) This is the grant of units under the Executive Share Unit Plan. (2) Does not include the units related to reinvested dividend value.

PERFORMANCE UNIT PLAN GRANTS OUTSTANDING

The following table outlines Performance Unit Plan 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 completed financial year. For further information on the material terms and general operation of the Performance Unit Plan, see the “Report on Executive Compensation - Grandfathered Executive Compensation Plan – Performance Unit Plan”.

	Securities, Units or Other Rights(1) (#)	Performance or Other Period Until Maturation or Payout(2)	ESTIMATED FUTURE PAYOUTS UNDER NON-SECURITIES-PRICE-BASED PLANS(3)
Name			Below Threshold(4) ($)	Maximum(4) ($)	Settlement Value for 2007(5) ($)
H.N. Kvisle	150,000	25-Feb-12	0	1,015,350	-
	100,000	20-Mar-11	0	766,900	-
	42,500	27-Feb-11	0	325,933	-
	55,000	28-Feb-10	0	470,195	-
	50,000	01-Feb-10	0	427,450	-
	90,000	01-Sep-09	0	769,410	-
G.A. Lohnes	20,000	25-Feb-12	0	135,380	-
	17,500	27-Feb-11	0	134,208	-
	17,500	28-Feb-10	0	149,608	-
	0	9-Dec-07	0	214,854	214,854
R.K. Girling	65,000	25-Feb-12	0	439,985	-
	45,000	27-Feb-11	0	345,105	-
	45,000	28-Feb-10	0	384,705	-
	50,000	01-Feb-10	0	427,450	-
	20,000	29-Jul-09	0	170,980	-
	25,000	01-Mar-09	0	213,725	-
	25,000	03-Dec-08	0	213,725	-
	0	09-Dec-07	0	245,556	245,556

TRANSCANADA PIPELINES LIMITED 57

	Securities, Units or Other Rights(1) (#)	Performance or Other Period Until Maturation or Payout(2)	ESTIMATED FUTURE PAYOUTS UNDER NON-SECURITIES-PRICE-BASED PLANS(3)
Name			Below Threshold(4) ($)	Maximum(4) ($)	Settlement Value for 2007(5) ($)
A.J. Pourbaix	65,000	25-Feb-12	0	439,985	-
	35,000	27-Feb-11	0	268,415	-
	20,000	28-Feb-10	0	170,980	-
	20,000	01-Feb-10	0	170,980	-
	20,000	01-Mar-09	0	170,980	-
	17,500	03-Dec-08	0	149,608	-
D.M. Wishart	30,000	25-Feb-12	0	203,070	-
	35,000	27-Feb-11	0	268,415	-
	20,000	28-Feb-10	0	170,980	-
	20,000	01-Feb-10	0	170,980	-
	20,000	01-Mar-09	0	170,980	-
	0	09-Dec-07	0	245,556	245,556

(1)As no further awards will be made under the Performance Unit Plan, it will be phased out over the remaining life of the outstanding units.

(2)The exercise period for all Performance Unit Plan 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 Performance Unit Plan 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 2008 that $1.36 per outstanding Performance Unit Plan unit would accrue for 2007 in respect of the grants made from December 9, 1997 to February 25, 2002.

(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 Performance Unit Plan 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 Performance Unit Plan units. A blank (“- “) denotes that there were no units exercised from the grant. A zero value denotes that all Performance Unit Plan units from the grant were forfeited. When applicable, settlement values are also reported as LTIP Payouts in the Summary Compensation Table, above.

Equity Compensation Plan Tables

2007 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 2007 financial year.

Name	Date of Grant	Number of Common Shares Under Options Granted (1)	% of Total Options Granted to Employees in 2007 (2)	Exercise Price ($/common share)(3)	Market Value of Common Shares Underlying Options on the Date of Grant ($/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 options vest and are exercisable.

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

(3)  The exercise price is 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.

TRANSCANADA PIPELINES LIMITED 58

Aggregate Stock Option Exercises During 2007 and 2007 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, 2007 for each of the Named Executive Officers.

Name	Common Shares Acquired on Exercise (#)	Aggregate Value Realized ($)	UNEXERCISED OPTIONS AT DECEMBER 31, 2007 (#)		VALUE OF UNEXERCISED IN-THE-MONEY OPTIONS AT DECEMBER 31, 2007(1) ($)
			Exercisable	Unexercisable	Exercisable	Unexercisable
H.N. Kvisle	0	0	747,500	422,442	11,282,043	1,936,290
G.A. Lohnes	11,000	115,740	25,167	85,323	189,157	455,708
R.K. Girling	0	0	308,333	253,993	4,346,314	1,286,811
A.J. Pourbaix	0	0	200,833	253,993	2,356,139	1,286,811
D.M. Wishart	25,162	358,594	210,000	114,267	3,413,068	490,843

(1)   The value of unexercised “in-the-money” stock options at December 31, 2007 is the difference between the exercise price and the closing price of $40.54 per share of a common share on the TSX on December 31, 2007. 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.

Supplemental Disclosure – 2008 Stock Option Plan Grants

Decisions regarding stock option grants are made annually by the Human Resources Committee in February prior to the publication of TransCanada’s Proxy Circular. Although not a requirement, TransCanada discloses these compensation grants for the Named Executive Officers. The following table outlines the stock option grants under the Stock Option Plan made in 2008.

Name	Date of Grant	Number of Common Shares Under Options Granted(1)	% of Total Options Granted to Employees in 2008(2)	Exercise Price(3) ($/common share)	Market Value of Common Shares Underlying Options on the Date of Grant(3) ($/common share)	Expiration Date
H.N. Kvisle	25-Feb-08	167,715	19.24%	39.75	39.75	25-Feb-15
G.A. Lohnes	25-Feb-08	30,608	3.51%	39.75	39.75	25-Feb-15
R.K. Girling	25-Feb-08	83,857	9.62%	39.75	39.75	25-Feb-15
A.J. Pourbaix	25-Feb-08	83,857	9.62%	39.75	39.75	25-Feb-15
D.M. Wishart	25-Feb-08	50,314	5.77%	39.75	39.75	25-Feb-15

⁽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 in February 25, 2008.

⁽³⁾    Equal to the closing market price of common shares on the TSX for the last trading day immediately preceding the award date of the option.

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 TransCanada as the Human Resources Committee may from time to time determine. Starting in 2005, the Human Resources Committee determined that only executive-level employees will participate in the plan. The following provides key information regarding the Stock Option Plan provisions:

·The plan was first approved by shareholders in 1995;

·As at February 25, 2008, there were approximately:

·	9,217,941 common shares issuable upon the exercise of outstanding stock options; this represents
	1.7% of issued and outstanding common shares;
·	4,133,117 common shares remaining available for issuance; this represents 0.8% of issued and outstanding common shares;
·	17,148,942 common shares have been issued upon the exercise of stock options, representing 3.2% of issued and outstanding common shares of the Company; and

·The exercise price for unexercised issued stock options ranges from $10.03 to $39.75, with expiry dates ranging from December 3, 2008 to February 25, 2015.

TRANSCANADA PIPELINES LIMITED 59

In addition to the amendments which were disclosed in TransCanada’s February 22, 2007 Management Proxy Circular and approved by its shareholders, where applicable, there were two additional amendments to the Stock Option Plan that occurred during 2007 that did not require shareholder approval was not required for the following amendments. First definition of “retirement” was revised to ensure that the interpretation is consistent with the plan’s intent. Second, in order to maintain compliance with U.S. tax law, the definition of “exercise price” was amended to provide that the exercise price of a stock option be the closing market price of common shares on the TSX for the last trading day immediately preceding the award date of the option. This amendment was approved by the TSX. Related to the amendment of the definition of “exercise price”, the exercise price of stock options that were granted to United States tax filers on February 22, 2007 was increased retroactively from $38.10 (the exercise price based on the plan provisions at the time of the grant) to $38.14 (the closing price of TransCanada’s common shares the day of the grant). None of the named Executive Officers are United States tax filers, and as such were not impacted by this exercise price increase.

An amending provision was approved by shareholders at the April 27, 2007 Annual and Special meeting of Shareholders whereby the Human Resources Committee is permitted to amend certain items of the Stock Option Plan without shareholder approval and certain amendments require shareholder approval. Among other things, shareholder approval is required for an increase in the number of shares available for issuance under the plan, lowering the exercise price of a previously granted option, the cancellation and reissue of an option and to extend the expiry date of an option beyond its original expiry date.

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 manage 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 following table outlines the action currently 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
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.
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.
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.

TRANSCANADA PIPELINES LIMITED 60

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, 2007.

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	8,609,320	$27.32	5,004,850
Equity compensation plans not approved by security holders	Nil	Nil	Nil
TOTAL	8,609,320	$27.32	5,004,850

PENSION AND RETIREMENT BENEFITS FOR EXECUTIVES

PENSION AND RETIREMENT BENEFITS

Effective January 1, 2008, TransCanada’s Pension Plans have been amended to allow existing and new employees with less than 10 years of service with TransCanada the choice of either participating in the Pension Plans or receiving an annual 7% contribution to a new TransCanada Savings Plan.  Participation in the Pension Plans is mandatory at 10 years of service.

Base Pension Plan

All TransCanada Canadian employees participate in the TransCanada 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 (3) plus 1.75% of an employee’s
Highest Average Earnings
above the Final Average  YMPE(3) 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 payments from the Incentive Compensation Program up to a pre-established maximum amount 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 year’s maximum pensionable earnings 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 $2,333 for each year of Credited Pensionable Service, with the result that benefits cannot be earned in the Registered Pension Plan on compensation above approximately $146,000 per annum.

Supplemental Pension Plan

All TransCanada employees with pensionable earnings over the Income Tax Act (Canada) ceiling of approximately $146,000, including the Named Executive Officers, participate in the Company’s non-contributory defined benefit Supplemental Pension Plan. Approximately 525 TransCanada 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

TRANSCANADA PIPELINES LIMITED 61

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.

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, TransCanada employees, including the Named Executive Officers, will receive the following normal form of pension:

(a)in respect of credited service prior to January 1, 1990, upon retirement, a monthly pension payable for life with 60% continuing thereafter to the participant’s designated joint annuitant; and

(b)in respect of credited service on and after January 1, 1990, upon retirement, a monthly pension as described in (a) above and, for unmarried participants, a monthly pension payable for life with payments to the participant’s estate guaranteed for the balance of 10 years if the participant dies within 10 years of retirement.

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	$203,000	$237,000
600,000	103,000	154,000	206,000	257,000	308,000	360,000
800,000	138,000	207,000	276,000	345,000	413,000	482,000
1,000,000	173,000	259,000	346,000	432,000	518,000	605,000
1,200,000	208,000	312,000	416,000	520,000	623,000	727,000
1,400,000	243,000	364,000	486,000	607,000	728,000	850,000
1,600,000	278,000	417,000	556,000	695,000	833,000	972,000
1,800,000	313,000	469,000	626,000	782,000	938,000	1,095,000
2,000,000	348,000	522,000	696,000	870,000	1,043,000	1,217,000
2,200,000	383,000	574,000	766,000	957,000	1,148,000	1,340,000
2,400,000	418,000	627,000	836,000	1,045,000	1,253,000	1,462,000
2,600,000	453,000	679,000	906,000	1,132,000	1,358,000	1,585,000
2,800,000	488,000	732,000	976,000	1,220,000	1,463,000	1,707,000
3,000,000	523,000	784,000	1,046,000	1,307,000	1,568,000	1,830,000

TRANSCANADA PIPELINES LIMITED 62

Based on their current Highest Average Earnings and assuming the Named Executive Officers remain employed by TransCanada until age 60 and that the Registered Pension Plan and Supplemental Pension Plan remain in force substantially in their 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, 2007	16.33	14.33	12.00	12.00	10.59
Accrued Pension at December 31, 2007 and Payable at age 60	$584,000	$100,000	$160,000	$155,000	$115,000
Years of Credited Service to age 60	23.16	22.92	26.50	29.58	17.50
Annual Benefit Payable at age 60	$832,000	$160,000	$361,000	$392,000	$191,000

(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 United States 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 actual payments from the Incentive Compensation Program up to a pre-established maximum amount as provided in the plan.
(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 received 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 2007 Pension Expense Related to Service and Compensation

Amounts reported in the table below represent the pension expense related to services provided in the 2007 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 2007 and the actuarial assumptions used for the year.

Name	Fiscal 2007 pension expense related to service and compensation
H.N. Kvisle	$1,324,000
G.A. Lohnes	$181,000
R.K. Girling	$594,000
A.J. Pourbaix	$575,000
D.M. Wishart	$467,000

Accrued Pension Obligations

As at December 31, 2007, TransCanada’s accrued obligation for the Supplemental Pension Plan was approximately $208.0 million. The 2007 current service costs and interest costs of the Supplemental Pension Plan were approximately $5.7 and $10.0 million, respectively, for a total of $15.7 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 21 (Employee Future Benefits) of the Notes to TransCanada’s 2007 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 2007 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.

TRANSCANADA PIPELINES LIMITED 63

Name	Accrued obligation at December 31, 2006(1) (A)	Change in accrued obligation for 2007(1),(2) (B)	Accrued obligation at December 31, 2007(1) (C) = (A) + (B)
H.N. Kvisle	$7,537,000	$1,510,000	$9,047,000
G.A. Lohnes	$1,640,000	$266,000	$1,906,000
R.K. Girling	$1,751,000	$696,000	$2,447,000
A.J. Pourbaix	$1,679,000	$664,000	$2,343,000
D.M. Wishart	$1,487,000	$519,000	$2,006,000

(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 2006 and 2007 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 2007 is the impact of investment returns on the Company’s pension plan assets.

Savings Plan

New or eligible employees that opt out of the Pension Plan and participate in the TransCanada Savings Plan will receive a Company contribution equal to 7% of base salary plus 7% of annual incentive compensation paid up to a set percentage. The Savings Plan offers a selection of mutual funds (RRSP or taxable accounts). Vesting in the plan is immediate and withdrawals from the plan are allowed at any time. Participants in the Savings Plan have the opportunity to re-enter the Pension Plan on an annual basis, but must re-enter the Pension Plan at 10 years of service.  Currently no Named Executive Officers with less than ten years of service have elected this option.

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 TransCanada 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.

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 Executive Share Unit Plan shall be deemed vested and shall be paid out in cash to the Executive. Otherwise, the Executive is provided with a pro-rated 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 President and CEO, the notice period is three years. In the case of the other Executives, the notice period is two years.
(2)	For Mr. Kvisle, the President and CEO, Mr. Girling, President Pipelines and Mr. Pourbaix, President Energy, 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

TRANSCANADA PIPELINES LIMITED 64

following the one year anniversary after a change of control, Mr. Kvisle may provide notice of his intention to leave TransCanada and receive all of the entitlements of a resignation for good reason.

The following table summarizes the material terms and provisions provided for all Executives under 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 Executive Share Unit 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.

The agreements provide that TransCanada 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 DIRECT COMPENSATION AWARDS

Annually, the Committee approves compensation awards that deliver market competitive and performance-relevant Total Direct Compensation, which is a combination of base salary and variable incentives, to the Executives. TransCanada also considers the annual value of the Base and Supplemental Pension Plans to be an integral part of the Company’s Executive Compensation Program and, as such, the values are provided for reference.

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 Incentive Compensation Program for performance attributable to the noted financial year, and paid in the first quarter following the completion of the financial year.
“ESUs”	The value granted under the Executive Share Unit 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 Executive Share Unit Plan Grant tables in the section “Long-Term Incentive Plan 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. A valuation of the economic value of each stock option grant is provided 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.

TRANSCANADA PIPELINES LIMITED 65

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

H.N. Kvisle	2007 ($)	2006 ($)	2005 ($)
FIXED
Annual Base Salary	1,200,000	1,100,000	1,100,000
VARIABLE
Cash Bonus	1,550,000	1,500,000	1,300,000
ESUs	2,378,696	1,917,500	1,940,004
Stock Options	771,304	782,500	360,000
Total Direct Compensation	5,900,000	5,300,000	4,700,004
Annual Pension Expense	1,324,000	713,000	1,604,000

G.A. Lohnes	2007 ($)	2006(1) ($)	2005(2) ($)
FIXED
Annual Base Salary	370,000	340,000	272,664
VARIABLE
Cash Bonus	490,000	320,000	208,240
ESUs	420,000	124,477	131,898
Stock Options	137,122	186,320	45,000
Total Direct Compensation	1,417,122	970,797	657,802
Annual Pension Expense	181,000	626,000	71,583

(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 TransCanada. 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 equally by TransCanada 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 of 1.3015 for 2005.

R.K. Girling	2007 ($)	2006(1) ($)	2005 ($)
FIXED
Annual Base Salary	630,000	520,000	460,000
VARIABLE
Cash Bonus	900,000	700,000	500,000
ESUs	1,252,500	618,300	544,965
Stock Options	408,912	566,700	135,000
Total Direct Compensation	3,191,412	2,405,000	1,639,965
Annual Pension Expense	594,000	384,000	158,000

⁽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 66

A.J. Pourbaix	2007 ($)	2006(1) ($)	2005 ($)
FIXED
Annual Base Salary	630,000	520,000	450,000
VARIABLE
Cash Bonus	900,000	700,000	500,000
ESUs	1,252,500	618,300	465,103
Stock Options	408,912	566,700	135,000
Total Direct Compensation	3,191,412	2,405,000	1,550,013
Annual Pension Expense	575,000	393,000	218,000

(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	2007 ($)	2006 ($)	2005 ($)
FIXED
Annual Base Salary	500,000	400,000	380,000
VARIABLE
Cash Bonus	550,000	500,000	400,000
ESUs	750,000	327,850	370,003
Stock Options	244,857	172,150	90,000
Total Direct Compensation	2,044,857	1,400,000	1,240,003
Annual Pension Expense	467,000	154,000	155,000

Financial
Highlights

Year ended December 31 (millions of dollars)	2007	2006		2005		2004	2003
Income
Net income applicable to common shares
Continuing operations	1,210	1,049		1,208		978	801
Discontinued operations	–	28		–		52	50
Net income applicable to common shares	1,210	1,077		1,208		1,030	851
Cash Flow
Funds generated from operations	2,603	2,374		1,950		1,701	1,822
Decrease/(increase) in operating working capital	215	(300	)	(48	)	28	93
Net cash provided by operations	2,818	2,074		1,902		1,729	1,915
Capital expenditures and acquisitions	5,874	2,042		2,071		2,046	965
Balance Sheet
Total assets	31,165	26,386		24,113		22,421	20,884
Long-term debt	12,377	10,887		9,640		9,749	9,516
Junior subordinated notes	975	–		–		–	–
Common shareholder's equity	9,664	7,618		7,164		6,484	6,044

TRANSCANADA PIPELINES LIMITED 1

TABLE OF CONTENTS

TCPL OVERVIEW		4
TCPL's STRATEGY		6
CONSOLIDATED FINANCIAL REVIEW
	Selected Three-Year Consolidated Financial Data	7
	Highlights	8
	Results of Operations	9
FORWARD-LOOKING INFORMATION		9
NON-GAAP MEASURES		10
OUTLOOK		10
SEGMENT RESULTS-AT-A-GLANCE		11
PIPELINES
	Highlights	14
	Results-at-a-Glance	15
	Financial Analysis	16
	Opportunities and Developments	19
	Business Risks	21
	Outlook	23
	Natural Gas Throughput Volumes	25
ENERGY
	Highlights	28
	Results-at-a-Glance	28
	Power Plants – Nominal Generating Capacity and Fuel Type	29
	Financial Analysis	30
	Opportunities and Developments	39
	Business Risks	41
	Outlook	42
CORPORATE
	Results-at-a-Glance	42
	Financial Results	43
	Outlook	43
DISCONTINUED OPERATIONS		43
LIQUIDITY AND CAPITAL RESOURCES
	Summarized Cash Flow	43
	Highlights	44
CONTRACTUAL OBLIGATIONS
	Contractual Obligations	48
	Principal Repayments	49
	Interest Payments	49
	Purchase Obligations	50

2 MANAGEMENT'S DISCUSSION AND ANALYSIS

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
	Financial Risks	52
	Other Risks	58
CONTROLS AND PROCEDURES		60
SIGNIFICANT ACCOUNTING POLICIES AND CRITICAL ACCOUNTING ESTIMATES		61
ACCOUNTING CHANGES		61
SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA		66
FOURTH-QUARTER 2007 HIGHLIGHTS		68
SHARE INFORMATION		70
OTHER INFORMATION		70
GLOSSARY OF TERMS		71

MANAGEMENT'S DISCUSSION AND ANALYSIS 3

The Management's Discussion and Analysis (MD&A) dated February 25, 2008 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, 2007. This MD&A covers TCPL's financial position and operations as at and for the year ended December 31, 2007. Amounts are stated in Canadian dollars unless otherwise indicated. Abbreviations and acronyms used in this MD&A are identified in the Glossary of Terms in the Company's 2007 Annual Report.

TCPL OVERVIEW

With more than 50 years experience, TCPL is a leader in the responsible development and reliable operation of North American energy infrastructure, including natural gas pipelines, power generation, natural gas storage facilities and projects related to oil pipelines and liquefied natural gas (LNG) facilities. TCPL's network of wholly owned natural gas pipelines extends more than 59,000 kilometres (km), tapping into virtually all major gas supply basins in North America. TCPL is one of the continent's largest providers of natural gas storage and related services with approximately 355 billion cubic feet (Bcf) of natural gas storage capacity. A growing independent power producer, TCPL owns, or has interests in, approximately 7,700 megawatts (MW) of power generation in Canada and the United States (U.S.).

In addition to having total assets in excess of $30 billion, TCPL plans to invest approximately $10 billion in a number of energy infrastructure projects in North America, with the expectation that a majority of these projects will be completed by 2010. Over the longer-term, TCPL has a significant portfolio of large-scale infrastructure opportunities that will continue to be pursued and developed.

North America's demand for natural gas, oil and electricity is expected to continue to grow. By 2020, it is expected that demand for natural gas will grow by 15 billion cubic feet per day (Bcf/d), demand for crude oil will increase by 3 million barrels per day (Bbl/d) and demand for power will grow by 155 gigawatts.

Demand for natural gas in North America is expected to increase due primarily to a growing demand for electricity. The long lead times required to complete new coal and nuclear projects could slow the development and completion of new coal or nuclear generation facilities 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 a large portion of its growing electricity needs. 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. This outlook for traditional sources of natural gas means that northern gas and offshore LNG could be required to fill the shortfall between supply and demand for natural gas. TCPL is well positioned to capture related opportunities in natural gas transmission, LNG infrastructure and power generation.

TCPL is also expanding into the crude oil transmission business with the development of a 590,000 Bbl/d crude oil pipeline from Hardisty, Alberta to refineries in U.S. midwest markets. TCPL has partnered with ConocoPhillips, a global, integrated oil and gas producer and refiner to construct the Keystone oil pipeline to transport crude oil from Alberta to refineries in Illinois and Oklahoma. The partnership provides TCPL with a platform for developing future crude oil pipeline opportunities. Significant oilsands development in Alberta is providing opportunities for new crude oil transmission infrastructure.

TCPL has the financial strength and flexibility to build new infrastructure to support increased energy demand, to respond to shifting energy supply-demand dynamics and to replace aging North American infrastructure.

Pipelines Assets

TCPL's natural gas pipeline assets link gas supplies from basins in Western Canada, the U.S. mid-continent and Gulf of Mexico to premium North American markets. These assets are well-positioned to connect emerging natural gas supplies, including northern gas and offshore LNG imports, to growing markets. With increasing production from the oilsands in Alberta and growing demand for secure, reliable sources of energy, TCPL has identified opportunities to develop oil pipeline capacity.

4 MANAGEMENT'S DISCUSSION AND ANALYSIS

TCPL's Alberta System gathered 68 per cent of the natural gas produced in Western Canada or 16 per cent of total North American production in 2007. TCPL exports natural gas from the Western Canada Sedimentary Basin (WCSB) to Eastern Canada and the U.S. West, Midwest and Northeast through three wholly owned pipeline systems: the Canadian Mainline, the GTN System and Foothills Pipe Lines Ltd. (Foothills).

American Natural Resources Company and ANR Storage Company (collectively, ANR) were acquired in February 2007. ANR Pipeline Company (ANR Pipeline), a subsidiary of American Natural Resources Company, transports natural gas from producing fields located primarily in Oklahoma, Texas, Louisiana and the Gulf of Mexico to markets located primarily in Wisconsin, Michigan, Illinois, Ohio and Indiana. ANR Pipeline also connects with numerous other natural gas pipelines, providing customers with access to diverse sources of North American supply, including Western Canada and the Rocky Mountain region, and access to a variety of end-user markets in the midwestern and northeastern U.S.

As a result of the ANR acquisition, TCPL owns and operates approximately 235 Bcf of regulated natural gas storage capacity in Michigan, making it one of North America's largest gas storage operators.

TCPL also exports natural gas from the WCSB to Eastern Canada and to the U.S. West, Midwest and Northeast through six partially owned natural gas pipeline systems: Great Lakes Transmission Limited Partnership (Great Lakes), Iroquois Gas Transmission System, L.P. (Iroquois), Portland Natural Gas Transmission System (Portland), Trans Québec & Maritimes System (TQM), Northern Border Pipeline Company (Northern Border) and Tuscarora Gas Transmission Company (Tuscarora). Certain of these pipeline systems are held through the Company's 32.1 per cent interest in TC PipeLines, LP (PipeLines LP).

The Company also transports natural gas through the wholly owned TransCanada Pipeline Ventures Limited Partnership (Ventures LP) pipeline in Alberta, North Baja pipeline in the U.S. and Tamazunchale pipeline in Mexico, as well as the partially owned TransGas de Occidente S.A. (TransGas) pipeline in Columbia and Gasoducto del Pacifico S.A. (Gas Pacifico) pipeline in Argentina.

In addition, the Company has a 50 per cent ownership interest in each of TransCanada Keystone Pipeline Limited Partnership (Keystone Canada) and TransCanada Keystone Pipeline LP (Keystone U.S.), (collectively Keystone). Currently beginning its construction phase, Keystone will transport crude oil from Hardisty, Alberta, to U.S. Midwest markets at Wood River and Patoka in Illinois, and to Cushing, Oklahoma.

Energy Assets

TCPL has built a substantial energy business over the past decade and has achieved a significant presence in power generation in selected regions of Canada and the U.S. TCPL owns, or has rights or interests in, approximately 7,700 MW of power generation in Canada and the U.S. These assets are primarily low-cost, base-load generation and/or are assets backed by secure, long-term power sales agreements. More recently, TCPL has also developed a significant non-regulated natural gas storage business in Alberta.

The Company's power assets are concentrated in two main regions: Western Power in Alberta and Eastern Power in the Eastern Canada and New England markets. TCPL's portfolio of power supply is shown in the accompanying chart.

All of TCPL's non-regulated natural gas storage assets are located in Alberta. TCPL owns or has rights to 120 Bcf or approximately one-third of the natural gas storage capacity in the province.

Opportunities and developments in the Company's Pipelines and Energy businesses are discussed further in the "Pipelines" and "Energy" sections of this MD&A.

MANAGEMENT'S DISCUSSION AND ANALYSIS 5

TCPL'S STRATEGY

TCPL's vision is to be the leading energy infrastructure company in North America, with a strong focus on pipelines and power generation opportunities located in regions where the Company enjoys significant competitive advantages. Since 2000, TCPL's key strategies have evolved with the Company's progression and the changing business environment. Today, TCPL's corporate strategy consists of the following six components:

•

Maximize the long-term value of the Company's natural gas transmission business;



•

Grow the North American pipeline and related infrastructure business;



•

Maximize the long-term value of existing power generation and power marketing and related businesses;



•

Grow North American power and energy businesses;



•

Drive for operational excellence; and



•

Maximize TCPL's competitive strength and enduring value.

Maximize the long-term value of the Company's natural gas transmission business

TCPL continues to place a priority on maximizing the long-term value of its natural gas transmission business. There is a strong focus on connecting supply with markets through expansions, extensions, acquisitions and strategic relationships. The Company also aims to offer competitive rates and services to meet stakeholder needs and enhance the value of its natural gas pipeline assets.

Grow the North American pipeline and related infrastructure business

TCPL is pursuing the development of greenfield and brownfield pipeline projects to grow its North American pipeline and related infrastructure business. These include frontier natural gas pipeline projects such as the Mackenzie Gas Pipeline (MGP) and the Alaska Pipeline as well as crude oil pipeline projects to meet the growing demand for transportation of Alberta oilsands production.

Other possible avenues of growth include:

•

Acquiring synergistic natural gas transmission assets that complement TCPL's existing core regions;



•

Acquiring partners' interests in associated pipelines to enhance strategic control, profitability and value; and



•

Acquiring stand-alone gas transmission enterprises in new regions of North America where critical mass and solid competitive advantage can be established.

The Company is also pursuing the development of natural gas pipeline infrastructure and associated LNG regasification terminals in Mexico and aims to grow pipeline earnings from PipeLines LP through acquisitions and organic growth.

Maximize the long-term value of existing power generation and power marketing and related businesses

TCPL aims to maximize the long-term value of existing power generation and power marketing and related businesses, such as unregulated natural gas storage. The Company's approach involves engaging in marketing activities – guided by strategic criteria and defined risk boundaries – that optimize the value of owned assets, as well as exercising disciplined asset management and being actively involved in regulatory and market developments.

Grow North American power and energy businesses

The Company is focusing primarily on the core western and eastern regions to grow its North American power and energy businesses. Consideration will be given to new markets with attractive fundamentals where TCPL can take advantage of its competencies to enhance its competitive strengths. There is a continued focus on low-cost, base-load power assets or assets backed by firm long-term contracts with reputable counterparties. The Company is also pursuing the development of LNG regasification terminals and associated natural gas pipeline infrastructure terminals to feed TCPL's gas transmission grids in Eastern Canada and the U.S. Northeast, Pacific Northwest, and Gulf of Mexico. Greenfield development and acquisition of power generation, transmission and natural gas storage will be considered if they meet the Company's rigorous strategic and value creation criteria.

6 MANAGEMENT'S DISCUSSION AND ANALYSIS

Drive for operational excellence

TCPL maintains a commitment to provide safe, low-cost, reliable and responsible service to customers under its operational excellence business model. The Company will continue to focus efforts in this critical area on efficiencies, operational reliability, the environment and safety.

Maximize TCPL's competitive strength and enduring value

In addition to the strategies discussed above, a number of other initiatives are being pursued in order to maximize TCPL's competitive strength and enduring value. These include:

•

Managing relationships with key stakeholder groups;



•

Managing counterparty and commodity exposures within the Company's limits;



•

Maintaining high standards in corporate governance practices;



•

Enhancing strategic thinking, analysis and constructive debate that lead to astute investment decision-making;



•

Attracting, retaining and engaging employees to maximize performance; and



•

Maintaining access to abundant, low-cost capital in all market environments.

CONSOLIDATED FINANCIAL REVIEW

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

		2007	2006		2005
Income Statement
Revenues		8,828	7,520		6,124
Net income applicable to common shares
	Continuing operations	1,210	1,049		1,208
	Discontinued operations	–	28		–
		1,210	1,077		1,208
Comparable earnings(2)		1,094	923		838
Per Common Share Data
Net income – basic and diluted
	Continuing operations	$2.28	$2.17		$2.50
	Discontinued operations	–	0.06		–
		$2.28	$2.23		$2.50
Summarized Cash Flow
Funds generated from operations(2)		2,603	2,374		1,950
Decrease/(increase) in operating working capital		215	(300	)	(48	)
Net cash provided by operations		2,818	2,074		1,902
Balance Sheet
Total assets		31,165	26,386		24,113
Total long-term liabilities		17,832	15,014		13,012

⁽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).

⁽²⁾

Refer to the "Non-GAAP Measures" section of this MD&A for further discussion of comparable earnings and funds generated from operations.

MANAGEMENT'S DISCUSSION AND ANALYSIS 7

HIGHLIGHTS

Net Income

•

Net income applicable to common shares and net income applicable to common shares from continuing operations (net earnings) was $1,210 million in 2007 compared to net income applicable to common shares of $1,077 million and net earnings of $1,049 million in 2006.

Comparable Earnings

•

TCPL's comparable earnings in 2007 excluded favourable income tax adjustments of $102 million and a gain of $14 million on sale of land. Comparable earnings increased $171 million to $1,094 million in 2007 compared to $923 million in 2006.

Cash from Operations

•

Net cash provided by operations was $2,818 million in 2007, an increase of $744 million from 2006.



•

Funds generated from operations were $2,603 million in 2007, an increase of $229 million from 2006, due primarily to increased earnings.

Investing Activities

•

TCPL invested approximately $5.9 billion in its Pipelines and Energy businesses in 2007, comprised primarily of the following:



•

The Company completed the acquisition, in February 2007, of ANR and acquired an additional 3.6 per cent interest in Great Lakes for a total of US$3.4 billion, subject to certain post-closing adjustments, including US$491 million of assumed long-term debt. The additional interest in Great Lakes increased TCPL's direct ownership to 53.6 per cent.



•

PipeLines LP completed its acquisition in February 2007 of a 46.4 per cent interest in Great Lakes for US$942 million, subject to certain post-closing adjustments, including US$209 million of assumed long-term debt.

Financing Activities

•

TCPL issued approximately $2.6 billion of Long-Term Debt, US$1.0 billion of Junior Subordinated Notes and approximately $1.8 billion of Common Shares in 2007, comprised primarily of:



•

TCPL issued US$1.0 billion of Senior Unsecured Notes in October 2007.



•

The Company entered into an agreement in February 2007 for a US$1.0-billion committed five-year term and revolving credit facility.



•

PipeLines LP increased the size of its revolving credit and term loan to US$950 million from US$410 million in February 2007.



•

TCPL issued US$1.0 billion of Junior Subordinated Notes in April 2007.



•

The issue of 48.2 million common shares to TransCanada Corporation (TransCanada) in first-quarter 2007, resulted in gross proceeds of approximately $1.8 billion.



•

PipeLines LP completed a private placement offering in February 2007 of 17.4 million common units at a price of US$34.57 per unit for gross proceeds of US$600 million. TCPL acquired 50 per cent of the units for US$300 million and made an additional investment of approximately US$12 million to maintain its general partner interest, increasing its total ownership to 32.1 per cent from 13.4 per cent.



•

The Company redeemed US$460 million of preferred securities in July 2007.

Balance Sheet

•

Total assets increased by $4.8 billion to $31.2 billion in 2007 compared with 2006, due primarily to the ANR and Great Lakes acquisitions.



•

TCPL's Shareholder's Equity increased by $2.0 billion to $10.1 billion in 2007 compared with the previous year.

8 MANAGEMENT'S DISCUSSION AND ANALYSIS

Dividend

•

On January 28, 2008, TCPL's Board of Directors declared a quarterly dividend for the quarter ending March 31, 2008 in an aggregate amount equal to the quarterly dividend to be paid on TransCanada's issued and outstanding common shares at the close of business on March 31, 2008. The Board also declared regular dividends on TCPL's preferred shares.

Refer to "Results of Operations" below and to the "Liquidity and Capital Resources" section of this MD&A for further discussion of these highlights.

RESULTS OF OPERATIONS

Net income applicable to common shares was $1,210 million in 2007 compared to $1,077 million in 2006 and $1,208 million in 2005. Results in 2006 included net income from discontinued operations of $28 million, reflecting bankruptcy settlements with Mirant Corporation and certain of its subsidiaries (Mirant) related to their transactions with TCPL's Gas Marketing business. TCPL divested its Gas Marketing business in 2001.

Net earnings were $1,210 million in 2007 compared to $1,049 million in 2006 and $1,208 million in 2005. Net earnings in 2007 included $102 million of favourable income tax adjustments and an after-tax gain of $14 million on the sale of land. Net earnings in 2006 included $95 million of favourable income tax adjustments, an $18-million after-tax bankruptcy settlement with Mirant and an after-tax gain of $13 million from the sale of TCPL's general partner interest in Northern Border Partners, L.P. Net earnings of $1,208 million in 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), $49 million on the sale of PipeLines LP units, and $13 million arising from a Canadian Mainline tolls settlement adjustment related to 2004 earnings.

Excluding the above-noted items, comparable earnings for the years 2007, 2006 and 2005 were $1,094 million, $923 million and $838 million, respectively. Comparable earnings in 2007 increased $171 million compared to 2006 due primarily to additional earnings from the acquisition of ANR in February 2007 and the first full year of earnings from the Bécancour cogeneration plant and the Edson gas storage facility as well as positive impacts from rate case settlements for the GTN System and the Canadian Mainline. These increases were partially offset by a lower contribution by Bruce Power A L.P. (Bruce A) and Bruce Power L.P. (Bruce B) (collectively, Bruce Power) in 2007.

Comparable earnings increased $85 million in 2006 compared to 2005. The increase was due primarily to significantly higher operating income from Western Power, Eastern Power and the Company's investment in Bruce Power. The higher operating income was partially offset by decreased Pipelines results as net earnings from the Canadian Mainline and the Alberta System declined due to lower approved rates of return on common equity (ROE) and lower average investment bases in 2006. In addition, the Company's Other Pipelines businesses and the GTN System and North Baja (collectively, GTN) experienced lower earnings in 2006.

Results from each business segment are discussed further in the "Pipelines", "Energy" and "Corporate" sections of this MD&A.

FORWARD-LOOKING INFORMATION

This MD&A may contain certain information that is forward-looking and is subject to important risks and uncertainties. The words "anticipate", "expect", "believe", "may", "should", "estimate", "project", "outlook", "forecast" or other similar words are used to identify such forward looking information. All forward-looking statements reflect TCPL's beliefs and assumptions based on information available at the time the statements were made. Actual results or events may differ from those predicted in these forward-looking statements. Factors that 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 operating performance of

MANAGEMENT'S DISCUSSION AND ANALYSIS 9

the Company's pipeline and energy assets, the availability and price of energy commodities, regulatory processes and decisions, changes in environmental and other laws and regulations, competitive factors in the pipeline and energy industry sectors, construction and completion of capital projects, labour, equipment and material costs, access to capital markets, interest and currency exchange rates, technological developments and the current economic conditions in North America. By its nature, 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 expectations expressed. Additional information on these and other factors is available in the reports filed by TCPL with Canadian securities regulators and with the U.S. Securities and Exchange Commission (SEC). Readers are cautioned to not place undue reliance on this forward-looking information, which is given as of the date it is expressed in this MD&A or otherwise, and to not use future-oriented information or financial outlooks for anything other than their intended purpose. 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

TCPL uses the measures "comparable earnings", "funds generated from operations" and "operating income" in this MD&A. These measures do not have any standardized meaning prescribed by GAAP. They are, therefore, considered to be non-GAAP measures and are unlikely to be comparable to similar measures presented by other entities. Management of TCPL uses non-GAAP measures to increase its ability to compare financial results between reporting periods and to enhance its understanding of operating performance, liquidity and ability to generate funds to finance operations. Non-GAAP measures are also provided to readers as additional information on TCPL's operating performance, liquidity and ability to generate funds to finance operations.

Comparable earnings comprise net earnings adjusted for specific items that are significant but not typical of the Company's operations. Specific items are subjective, however, management uses its best judgement and informed decision-making when identifying items to be excluded in calculating comparable earnings. Specific items may include but are not limited to certain income tax refunds and adjustments, gains or losses on sales of assets, legal settlements, and bankruptcy settlements with former customers. The table in the "Segment Results-at-a-Glance" section of this MD&A presents a reconciliation of comparable earnings to net income.

Funds Generated from Operations comprises 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 "Liquidity and Capital Resources" section of this MD&A.

Operating Income is reported in the Company's Energy business segment and comprises revenues less operating expenses as shown on the consolidated income statement. A reconciliation of operating income to net earnings is presented in the Energy section of this MD&A.

OUTLOOK

The Company's net earnings and cash flow, combined with a strong balance sheet, are expected to continue to provide the financial flexibility TCPL will need in 2008 and beyond to complete its current capital expenditure program and continue to pursue opportunities and create additional long-term value for its shareholder.

TCPL views diligence and discipline as important elements of its strategy for long-term growth in its Pipelines and Energy businesses. In 2008, the Company will continue to implement its strategy and grow its Pipelines and Energy businesses as discussed in the "TCPL's Strategy" section of this MD&A.

The Company's results in 2008 may be affected positively or negatively by a number of factors and developments as discussed throughout this MD&A, including in the "Forward-Looking Information" section. Refer to the "Pipelines – Outlook", "Energy – Outlook" and "Corporate – Outlook" sections of this MD&A for further discussion regarding outlook.

10 MANAGEMENT'S DISCUSSION AND ANALYSIS

SEGMENT RESULTS-AT-A-GLANCE
Reconciliation of Comparable Earnings to Net Income
Applicable to Common Shares
Year ended December 31
(millions of dollars except per share amounts)

			2007		2006		2005
Pipelines
	Comparable earnings		686		529		617
	Specific items:
		Bankruptcy settlement with Mirant	–		18		–
		Gain on sale of Northern Border Partners, L.P. interest	–		13		–
		Gain on sale of PipeLines LP units	–		–		49
		Canadian Mainline NEB decision related to 2004	–		–		13
	Net earnings		686		560		679
Energy
	Comparable earnings		466		429		258
	Specific items:
		Income tax reassessments and adjustments	34		23		–
		Gain on sale of land	14		–		–
		Gain on sale of Power LP units	–		–		193
		Gain on sale of Paiton Energy	–		–		115
	Net earnings		514		452		566
Corporate
	Comparable expenses		(58	)	(35	)	(37	)
	Specific item:
		Income tax reassessments and adjustments	68		72		–
	Net earnings		10		37		(37	)
Net Income Applicable to Common Shares
	Continuing operations(1)		1,210		1,049		1,208
	Discontinued operations		–		28		–
Net Income Applicable to Common Shares			1,210		1,077		1,208
Comparable Earnings(1)			1,094		923		838
Net Income per Common Share
	Continuing operations		$2.28		$2.17		$2.50
	Discontinued operations		–		0.06		–
	Basic		$2.28		$2.23		$2.50

(1) Comparable Earnings		1,094	923	838
	Specific items (net of tax, where applicable):
	Income tax reassessments and adjustments	102	95	–
	Gain on sale of land	14	–	–
	Bankruptcy settlement with Mirant	–	18	–
	Gain on sale of Northern Border Partners, L.P. interest	–	13	–
	Gain on sale of Power LP units	–	–	193
	Gain on sale of Paiton Energy	–	–	115
	Gain on sale of PipeLines LP units	–	–	49
	Canadian Mainline NEB decision related to 2004	–	–	13
	Net Income from Continuing Operations	1,210	1,049	1,208

MANAGEMENT'S DISCUSSION AND ANALYSIS 11

CANADIAN MAINLINE   Owned 100 per cent by TCPL, the Canadian Mainline is a 14,957-km natural gas transmission system in Canada that 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   Owned 100 per cent by TCPL, the Alberta System is a 23,570-km natural gas transmission system in Alberta. One of the largest transmission systems in North America, it gathers natural gas for use within the province and delivers it to provincial boundary points for connection with the Company's Canadian Mainline and Foothills natural gas pipelines as well as the natural gas pipelines of other companies.

12 MANAGEMENT'S DISCUSSION AND ANALYSIS

ANR   Owned 100 per cent by TCPL, the 17,000-km ANR transmission system transports natural gas from producing fields located primarily in Texas and Oklahoma on its southwest leg and in the Gulf of Mexico and Louisiana on its southeast leg. The system extends to markets located mainly in Wisconsin, Michigan, Illinois, Ohio and Indiana. ANR's natural gas pipeline also connects with other natural gas pipelines to give access to diverse sources of North American supply including Western Canada and the Rocky Mountain supply basin, and a variety of markets in the midwestern and northeastern U.S. ANR also owns and operates regulated underground natural gas storage facilities in Michigan with a total capacity of approximately 235 Bcf.

GTN SYSTEM   Owned 100 per cent by TCPL, the GTN System is a 2,174-km natural gas transmission system that links Foothills with Pacific Gas and Electric Company's California Gas Transmission System, with Williams Companies Inc.'s Northwest Pipeline in Washington and Oregon, and with Tuscarora.

FOOTHILLS   Owned 100 per cent by TCPL, the 1,241 km Foothills 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. TCPL's BC System was integrated into Foothills effective April 1, 2007.

NORTH BAJA   Owned 100 per cent by TCPL, the North Baja natural gas transmission system extends 129 km from Ehrenberg in southwestern Arizona to a point near Ogilby, California on the California/Mexico border and connects with the Gasoducto Bajanorte natural gas pipeline system in Mexico.

GREAT LAKES   Owned 53.6 per cent by TCPL and 46.4 per cent by PipeLines LP, the 3,404-km Great Lakes natural gas transmission system connects with the Canadian Mainline at Emerson, Manitoba, and serves markets in Central Canada and the midwestern U.S. TCPL operates Great Lakes and effectively owns 68.5 per cent of the system through its 53.6 per cent direct ownership interest and its indirect ownership through its 32.1 per cent interest in PipeLines LP.

NORTHERN BORDER   Owned 50 per cent by PipeLines LP, the 2,250-km Northern Border natural gas transmission system serves the U.S. Midwest from a connection with Foothills near Monchy, Saskatchewan. TCPL operates Northern Border and effectively owns 16.1 per cent of the system through its 32.1 per cent interest in PipeLines LP.

TUSCARORA   Owned 100 per cent by PipeLines LP, Tuscarora is a 491-km pipeline system transporting natural gas from the GTN System at Malin, Oregon, to Wadsworth, Nevada, with delivery points in northeastern California and northwestern Nevada. TCPL operates Tuscarora and its 32.1 per cent interest in PipeLines LP gives TCPL a 32.1 per cent ownership interest in the system.

IROQUOIS   Owned 44.5 per cent by TCPL, the 666-km Iroquois pipeline system connects with the Canadian Mainline near Waddington, New York, and delivers natural gas to customers in the northeastern U.S.

TRANSGAS   Owned 46.5 per cent by TCPL, TransGas is a 344-km natural gas pipeline system extending from Mariquita in the central region of Colombia to Cali in southwestern Colombia.

PORTLAND   Owned 61.7 per cent by TCPL, 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. Portland is operated by TCPL.

VENTURES LP   Owned 100 per cent by TCPL, Ventures LP has a 121-km pipeline and related facilities that supply natural gas to the oilsands region of northern Alberta as well as a 27-km pipeline that supplies natural gas to a petrochemical complex at Joffre, Alberta.

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

TQM   Owned 50 per cent by TCPL, TQM is a 572-km pipeline system that connects with the Canadian Mainline and transports natural gas from Montréal to Québec City in Québec, and connects with the Portland system. TQM is operated by TCPL.

GAS PACIFICO/INNERGY   Owned 30 per cent by TCPL, Gas Pacifico is a 540-km natural gas pipeline extending from Loma de la Lata, Argentina to Concepción, Chile. TCPL also has a 30 per cent ownership interest in INNERGY, an industrial natural gas marketing company based in Concepción that markets natural gas transported on Gas Pacifico.

KEYSTONE   Owned 50 per cent by TCPL, Keystone is a 3,456-km oil pipeline project under construction that is expected to transport crude oil from Hardisty, Alberta to U.S. midwest markets at Wood River and Patoka in Illinois, and to Cushing, Oklahoma.

MANAGEMENT'S DISCUSSION AND ANALYSIS 13

PIPELINES – HIGHLIGHTS

Net Earnings

•

Net earnings from Pipelines were $686 million in 2007, an increase of $126 million from $560 million in 2006. The growth was due primarily to the acquisitions of ANR and additional interest in Great Lakes, higher earnings as a result of the Canadian Mainline and GTN System rate settlements, and an increased ownership interest in PipeLines LP.

Expanding Asset Base

•

TCPL expanded its North American natural gas pipeline and storage operations through its US$3.4-billion acquisitions of ANR and additional interest in Great Lakes in 2007.

•

At December 31, 2007, TCPL has secured sufficient long-term contracts to underpin construction of the US$5.2-billion Keystone oil pipeline, including an extension to Cushing, Oklahoma, in which the Company holds a 50 per cent ownership interest.

•

TCPL applied to the Alberta Energy and Utilities Board (EUB) in late 2007 for approval to further expand its Alberta System by adding 300 km of natural gas pipeline at an estimated total capital cost of $983 million.

•

TCPL received approval from the EUB in 2007 to construct four new natural gas transmission facilities to serve the firm intra-Alberta delivery contract requirements of oilsands developers in the Fort McMurray, Alberta area. The capital cost of the four pipeline facilities, which total 150 km, together with a 15-MW compression facility, is expected to be $367 million.

Canadian Mainline

•

The National Energy Board (NEB) approved a negotiated five-year settlement of Canadian Mainline tolls, which included a deemed common equity ratio of 40 per cent and certain performance-based and operating, maintenance and administration (OM&A) cost-saving incentive arrangements.

Alberta System

•

The Alberta System operated under the terms of the 2005-2007 Revenue Requirement Settlement in 2007 and is currently negotiating a settlement with stakeholders for 2008.

GTN System

•

The Federal Energy Regulatory Commission (FERC) approved in January 2008 the GTN System's uncontested rate case settlement. Under the settlement, the GTN System's rates increased by approximately 27 per cent, effective January 1, 2007.

Foothills

•

After receiving NEB approval, the BC System was integrated into Foothills effective April 1, 2007.

Other Pipelines

•

TCPL acquired approximately eight million units of PipeLines LP in February 2007, increasing the Company's ownership interest to 32.1 per cent. Through its increased ownership interest in PipeLines LP, TCPL increased its effective ownership in Great Lakes to 68.5 per cent.

14 MANAGEMENT'S DISCUSSION AND ANALYSIS

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

		2007		2006		2005
Wholly Owned Pipelines
	Canadian Mainline	273		239		270
	Alberta System	138		136		150
	ANR(1)	104
	GTN	58		46		71
	Foothills(2)	26		27		27
		599		448		518
Other Pipelines
	Great Lakes(3)	47		44		46
	PipeLines LP(4)	18		4		9
	Iroquois	15		15		17
	TransGas	15		11		11
	Portland	11		13		11
	Ventures LP	11		12		12
	Tamazunchale(5)	10		2
	TQM	6		7		7
	Gas Pacifico/INNERGY(6)	3		8		6
	Northern Development	(7	)	(5	)	(4	)
	General, administrative, support costs and other	(42	)	(30	)	(16	)
		87		81		99
Comparable earnings(7)		686		529		617
Bankruptcy settlement with Mirant		–		18		–
Gain on sale of Northern Border Partners, L.P. interest		–		13		–
Gain on sale of PipeLines LP units		–		–		49
Canadian Mainline NEB decision related to 2004		–		–		13
Net earnings		686		560		679

⁽¹⁾

ANR was acquired February 22, 2007.

⁽²⁾

Foothills' results reflect the combined operations of Foothills and the BC System.

⁽³⁾

Great Lakes' results reflect TCPL's 53.6 per cent ownership in Great Lakes since February 22, 2007, and 50 per cent ownership prior to this date.

⁽⁴⁾

PipeLines LP's results include a 46.4 per cent ownership interest in Great Lakes since February 22, 2007, as well as an additional 20 per cent ownership of Northern Border since April 6, 2006, and an additional 49 per cent ownership of Tuscarora since December 19, 2006. PipeLines LP's results also reflect TCPL's 32.1 per cent ownership since February 22, 2007.

⁽⁵⁾

Tamazunchale's results include operations since December 1, 2006.

⁽⁶⁾

INNERGY Holdings S.A.

⁽⁷⁾

Refer to the "Non-GAAP Measures" section of this MD&A for further discussion of comparable earnings.

MANAGEMENT'S DISCUSSION AND ANALYSIS 15

Net earnings from the Pipelines business were $686 million in 2007 compared to $560 million in 2006 and $679 million in 2005. Net earnings in 2006 included the $18-million bankruptcy settlement with Mirant and the $13-million gain on sale of TCPL's general partner interest in Northern Border Partners, L.P. Net earnings in 2005 included the $49-million gain on sale of PipeLines LP units. Net earnings in 2005 also included a $13-million positive adjustment related to 2004 as a result of the NEB's decision in 2005 to increase the deemed common equity ratio to 36 per cent from 33 per cent under the Canadian Mainline's 2004 Tolls and Tariff Application (Phase II).

Comparable earnings from the Pipelines business were $686 million in 2007, an increase of $157 million compared to $529 million in 2006. The increase was due primarily to the acquisitions of ANR and additional interest in Great Lakes, higher earnings as a result of the Canadian Mainline and GTN System rate settlements and an increased ownership in PipeLines LP.

Comparable earnings decreased $88 million to $529 million in 2006 compared to $617 million in 2005. The decline was due primarily to lower net earnings from the Canadian Mainline, the Alberta System, GTN and Other Pipelines.

PIPELINES – FINANCIAL ANALYSIS

Canadian Mainline

The Canadian Mainline is regulated by the NEB. The NEB sets tolls that 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. The NEB also approves new facilities before their 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 February 2007, TCPL reached a five-year tolls settlement effective January 1, 2007 to December 31, 2011 on the Canadian Mainline. In May 2007, the NEB approved TCPL's application of the settlement as filed, including TCPL's request that interim tolls be made final for 2007.

As part of the settlement, it was agreed that the cost of capital reflect an ROE on a deemed common equity ratio of 40 per cent, an increase from 36 per cent, as determined under the NEB's ROE formula. The remaining capital structure will consist of short- and long-term debt, following the agreed upon redemption of the US$460 million 8.25 per cent Preferred Securities that were included in the Canadian Mainline's capital structure.

The settlement also established certain elements of the Canadian Mainline's fixed OM&A costs for each year of the settlement. The variance between actual and agreed upon OM&A costs will accrue to TCPL from 2007 to 2009, and will be shared equally between TCPL and its customers in 2010 and 2011. The settlement also allows for performance-based incentive arrangements that will provide mutual benefits to both TCPL and its customers.

Net earnings of $273 million in 2007 were $34 million higher than 2006 net earnings of $239 million. The increase primarily reflected the positive impact of the increase in deemed common equity ratio in the Canadian Mainline tolls settlement, performance-based incentive arrangements and OM&A cost savings, partially offset by a lower allowed ROE of 8.46 per cent in 2007 (8.88 per cent in 2006), as determined under the NEB's formula, and a lower average investment base.

Canadian Mainline generated comparable earnings of $239 million in 2006, a decrease of $31 million from 2005. The decrease was due primarily to a combination of a lower allowed ROE and a lower average investment base in 2006 compared to 2005. Comparable earnings in 2005 excluded the $13-million positive adjustment from the NEB decision related to 2004. TCPL reached a tolls settlement with its Canadian Mainline customers and other interested parties that included an NEB-allowed ROE of 8.88 per cent for 2006, which was determined under the NEB's return adjustment formula on a deemed common equity ratio of 36 per cent. The NEB-allowed ROE for 2005 was 9.46 per cent.

16 MANAGEMENT'S DISCUSSION AND ANALYSIS

Alberta System

The EUB was reorganized into the Energy Resources Conservation Board and the Alberta Utilities Commission (AUC) effective January 1, 2008. The AUC regulates construction and operation of facilities and the terms and conditions of services, including rates, for the Alberta System, primarily under the provisions of the Gas Utilities Act and the Pipeline Act.

The Alberta System has been operating for the past three years under the 2005-2007 Revenue Requirement Settlement. The settlement addresses all elements of the Alberta System including OM&A costs, ROE, depreciation and income and municipal taxes. The settlement fixed OM&A costs at $207 million for 2007, $201 million for 2006, and $193 million for 2005. In each year, any variance between actual OM&A and other fixed costs and those agreed to in the settlement accrued to TCPL. The majority of other cost elements of the 2005, 2006 and 2007 revenue requirements are treated on a flow-through basis.

Alberta System net earnings of $138 million in 2007 were $2 million higher than in 2006. The increase was due primarily to OM&A cost savings, partially offset by a lower allowed ROE and a lower investment base in 2007. The allowed ROE prescribed by the EUB was 8.51 per cent in 2007 compared with 8.93 per cent in 2006 on deemed common equity of 35 per cent.

Net earnings of $136 million in 2006 were $14 million lower than in 2005. The decrease was due primarily to a lower investment base and a lower allowed ROE in 2006. The allowed ROE prescribed by the EUB was 9.50 per cent in 2005 on deemed common equity of 35 per cent.

ANR

TCPL completed the acquisition of ANR on February 22, 2007 and included its net earnings from this date. The operations of ANR are regulated primarily by the FERC. ANR provides natural gas transportation, storage and various capacity-related services to a variety of customers in both the U.S. and Canada. The transmission system has a peak-day capacity of 6.8 Bcf/d. ANR also owns and operates numerous underground natural gas storage facilities in Michigan. ANR's FERC-regulated natural gas storage and transportation services operate under current FERC-approved tariff rates. These tariffs include maximum and minimum rate levels for services and permit ANR to discount or negotiate rates on a

MANAGEMENT'S DISCUSSION AND ANALYSIS 17

non-discriminatory basis. ANR Pipeline's rates were established pursuant to a settlement approved by a FERC order issued in February 1998 and the settlement rates became effective November 1, 1997. ANR Storage Company's rates were established pursuant to a settlement approved by the FERC in April 1990 and these settlement rates became effective June 1, 1990. None of ANR's FERC-regulated operations are required to file for new rates at any time in the future, nor are any of the operations prohibited from filing a rate case. ANR's revenues are derived primarily from its interstate natural gas transmission and storage, gathering and related services. Due to the seasonal nature of the business, ANR's volumes, revenues and net earnings are generally expected to be higher in the winter months. ANR's net earnings were $104 million from the date of its acquisition by TCPL on February 22, 2007, to December 31, 2007 and were in line with the Company's expectations.

GTN

The FERC regulates GTN. Both of GTN's systems, the GTN System and North Baja, are subject to FERC-approved tariffs that establish maximum and minimum rates for various services. The systems are permitted to discount or negotiate these rates on a non-discriminatory basis. On October 31, 2007, the GTN System filed a Stipulation and Agreement with the FERC that comprises an uncontested settlement of all aspects of its 2006 General Rate Case. The settlement rates went into effect on an interim basis on November 1, 2007, in accordance with the FERC's Order dated November 16, 2007. The FERC approved the settlement on January 7, 2008, with settlement rates effective January 1, 2007. GTN's financial results in 2007 reflect the terms of the settlement. The net earnings of GTN are affected by variations in contracted volume 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.

GTN's comparable earnings increased $12 million in 2007, compared to 2006 due primarily to the positive impact of the rate case settlement, partially offset by lower long-term firm contracted volumes and a weaker U.S. dollar in 2007. In addition, comparable earnings in 2007 were negatively affected by a higher provision taken in 2007 for non-payment of contract revenues from a subsidiary of Calpine Corporation (Calpine) that filed for bankruptcy protection.

Net earnings were $46 million in 2006, a $25-million decrease from 2005. This decrease was due primarily to lower transportation revenues, higher operating costs, the impact of the weaker U.S. dollar and the provision for non-payment of contract revenues from the Calpine subsidiary.

Other Pipelines

TCPL's direct and indirect investments in various natural gas pipelines and its project development activities relating to natural gas and oil transmission opportunities throughout North America are included in Other Pipelines.

TCPL's comparable earnings from Other Pipelines were $87 million in 2007 compared to $81 million in 2006. The increase was due primarily to higher earnings in PipeLines LP, which were affected positively by TCPL's increased ownership interests in PipeLines LP and Great Lakes, and Tamazunchale, which completed its first full year of operations in 2007. These increases were partially offset by higher project development and support costs associated with growing the Pipelines business, the effects of the weaker U.S. dollar in 2007, and proceeds of a bankruptcy settlement received by Portland in 2006.

Comparable earnings from Other Pipelines were $81 million in 2006, $18 million lower than in 2005. The decrease was due primarily to higher project development and support costs associated with growing the Pipelines business, reduced ownership in PipeLines LP, the effects of the weaker U.S. dollar, and proceeds of bankruptcy settlements received by Iroquois in 2005. These decreases were partially offset by higher net earnings from Portland due to the proceeds it received in 2006 from the bankruptcy settlement.

18 MANAGEMENT'S DISCUSSION AND ANALYSIS

PIPELINES – OPPORTUNITIES AND DEVELOPMENTS

Keystone

Keystone is expected to extend 3,456 km and is designed to deliver 590,000 Bbl/d of crude oil from Hardisty, Alberta, to U.S. Midwest markets at Wood River and Patoka in Illinois, and to Cushing, Oklahoma. The Company has currently secured long-term contracts for a total of 495,000 Bbl/d with an average duration of 18 years. Deliveries to Patoka are expected to begin in late 2009.

TCPL and Keystone Canada received regulatory approval from the NEB in 2007 to transfer a portion of TCPL's Canadian Mainline natural gas transmission facilities to Keystone Canada, and to construct and operate new oil pipeline facilities in Canada. Keystone Canada filed an application with the NEB in November 2007 to add new pumping facilities to accommodate the increase in scope and scale of the project. An NEB oral hearing is scheduled to commence in April 2008.

Keystone U.S. received, from the U.S. Department of State in January 2008, the Final Environmental Impact Statement (FEIS) regarding construction of the Keystone U.S. pipeline and its Cushing extension. The FEIS stated the pipeline would result in limited adverse environmental impacts. The FEIS is a requirement to proceed with the Presidential Permit process, which governs the construction and operation of facilities at the U.S.-Canada border crossing. The Presidential Permit is expected to be issued in March 2008.

ConocoPhillips contributed $207 million to acquire a 50 per cent ownership interest in Keystone in December 2007. Affiliates of TCPL will be responsible for constructing and operating Keystone, which is expected to have a capital cost of approximately US$5.2 billion.

Canadian Mainline

In July 2007, the NEB approved TCPL's request to add a new LNG receipt point at Gros Cacouna, Québec, as well as its request to calculate tolls for service from this point on a rolled-in basis. The approvals will be effective on the date the facilities required to connect the Gros Cacouna receipt point are placed in service.

On November 29, 2007, the NEB announced that, pursuant to its formula, the 2008 allowed ROE for NEB-regulated pipelines, including the Canadian Mainline, will be 8.71 per cent, up from 8.46 per cent in 2007.

Alberta System

TCPL received approval from the EUB in July 2007 to initiate negotiations on the Alberta System revenue requirement with the intent of reaching a settlement for a term of up to three years commencing January 1, 2008. Settlement negotiations with stakeholders are progressing. TCPL has a requirement to file a 2008 General Rate application or a settlement in first-quarter 2008.

On November 30, 2007 the EUB finalized the Alberta System's 2008 allowed ROE at 8.75 per cent, compared to 8.51 per cent in 2007.

TCPL received approval from the EUB in 2007 to construct four new natural gas transmission facilities to serve the firm intra-Alberta delivery contract requirements of oilsands developers in the Fort McMurray, Alberta area. The capital cost of the four pipeline facilities, which total 150 km, together with a 15-MW compression facility are expected to be $367 million.

TCPL submitted an application to the EUB in November 2007 for a permit to construct the North Central Corridor expansion, which comprises a 300-km natural gas pipeline and associated facilities on the northern section of the Alberta System. The expansion, if approved, will connect the northwest portion of the Alberta System with the northeast portion of the system. The estimated capital cost of this expansion is $983 million. The project is expected to be completed in two stages, the first one beginning in late 2008 with an in-service date of April 1, 2009 and the second one with an in-service date of April 1, 2010.

MANAGEMENT'S DISCUSSION AND ANALYSIS 19

ANR

As of December 31, 2007, ANR substantially completed a project that increased its saleable natural gas storage capacity by 13 Bcf, of which 10 Bcf was previously used for system operations. Construction has commenced on a second storage enhancement project, which is expected to increase ANR's natural gas storage capacity by 14 Bcf in 2008.

ANR is considering an additional storage expansion project, which, along with the utilization of other natural gas pipeline assets across TCPL's system, is intended to allow customers to access additional storage and markets. ANR is also pursuing potential additions of supply on both its southwest and southeast legs. Supply on the southwest leg was increased in early 2008 as a result of an interconnect with the Rockies Express natural gas pipeline, which commenced service in January 2008. There is potential for new supply on the southeast leg from LNG additions, shale gas from the mid-continent, and a potential additional interconnect with the Rockies Express pipeline.

GTN

In August 2007, Gas Transmission Northwest Corporation (GTNC), a wholly owned subsidiary of TCPL, and Northwest Natural Gas Company (NW Natural) formed an equally owned joint venture, Palomar Gas Transmission LLC (Palomar), to develop a 354-km (220 mile) natural gas pipeline to serve the Oregon, Pacific Northwest and Western U.S markets. The proposed Palomar pipeline would connect TCPL's existing GTN System in central Oregon with NW Natural's distribution system near Molalla, Oregon, and could be extended to a proposed pipeline near the town of Wauna, Oregon. The Palomar pipeline is in the preliminary stages of the FERC permitting process.

North Baja

North Baja received a FERC expansion certificate in October 2007 authorizing modifications that would allow it to import natural gas from the Costa Azul LNG terminal in northwestern Mexico, which is nearing completion. The imported gas would serve markets in California and the U.S. Southwest. The FERC certificate authorizes phased expansion of North Baja. The first phase of the expansion includes system modifications to allow for bi-directional natural gas flow and the addition of a lateral natural gas pipeline to interconnect with a Southern California Gas Co. pipeline near Blythe, California. The first phase will also give North Baja the ability to import approximately 600 million cubic feet per day (mmcf/d) of natural gas from Mexico.

Foothills

TCPL's BC System was integrated into Foothills in 2007. In first quarter 2007, the NEB approved the transfer of assets and finalized the revised tolls for 2007. Foothills will continue to be regulated on a complaint basis only.

Tamazunchale

The Company's Tamazunchale natural gas pipeline in Mexico is designed to transport initial volumes of 170 mmcf/d. The pipeline's capacity is expected to be expanded to approximately 430 mmcf/d, to meet the needs of two additional proposed power plants near Tamazunchale. The timing of the expansion will be driven by the Comisión Federal de Electricidad's requirements for the power plants.

Mackenzie Gas Pipeline Project

The MGP is a proposed 1,200-km natural gas pipeline to be constructed from a point near Inuvik, Northwest Territories to the northern border of Alberta, where it is expected to connect to the Alberta System.

TCPL's involvement with the MGP arises from a 2003 agreement between the Mackenzie Valley Aboriginal Pipeline Group (APG) and the MGP, whereby TCPL agreed to finance the APG's one-third share of the pre-development costs associated with the project. Cumulative advances made by TCPL in this respect totalled $137 million at December 31, 2007 and are included in Other Assets. These amounts constitute a loan to the APG, which becomes repayable only after the pipeline commences commercial operations. The total amount of the loan is expected to form part of the rate base of the pipeline and subsequently be repaid from the APG's share of future natural gas 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, TCPL's ability to recover its investment is dependant upon a successful outcome of the project.

20 MANAGEMENT'S DISCUSSION AND ANALYSIS

Under the terms of certain MGP agreements, TCPL holds an option to acquire up to a five per cent equity ownership in the natural gas 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 natural gas pipeline owners and the APG sharing the balance.

TCPL and the other co-venture companies involved in the MGP continue to pursue approval of the proposed project, focusing on the regulatory process and discussions with the Canadian government on fiscal framework. Project timing is uncertain and is conditional upon resolution of regulatory and fiscal matters.

Alaska Pipeline Project

TCPL continued its discussions with Alaska North Slope producers and the State of Alaska in 2007 to advance the proposed Alaska Pipeline Project. TCPL submitted an application in November 2007 for a license to construct the Alaska Pipeline Project under the Alaska Gasline Inducement Act (AGIA). The State of Alaska announced on January 4, 2008, that TCPL had submitted a complete AGIA application and would be advancing to the Public Comment stage. No other applicant met all the AGIA requirements. If approved by the Alaska Administration and the Alaska Legislature, TCPL could be granted the AGIA license by mid-2008. Upon receipt of the AGIA license, TCPL will proceed with an open season to secure shipping commitments from shippers.

Foothills holds the priority right to build, own and operate the first natural gas pipeline through Canada for the transportation of Alaskan gas. This right was granted under the Northern Pipeline Act of Canada (NPA) following a lengthy competition hearing before the NEB in the late 1970s, which produced 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, British Columbia (B.C.) and Saskatchewan that constitute a pre-build for the Alaska Pipeline Project, and to expand these facilities five times, the latest of which was in 1998. Continued development of the Alaska Pipeline Project under the NPA is expected to ensure the earliest in-service date for the project.

PIPELINES – BUSINESS RISKS

Supply, Markets and Competition

TCPL faces competition at both the supply and market ends of its systems. This competition comes from other natural gas pipelines accessing the increasingly mature WCSB and 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 and shifts to short-term firm contracts on the Canadian Mainline, the Alberta System, Foothills and the GTN System.

TCPL's primary source of natural gas supply is the WCSB. As of December 2006, 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, sufficient additional reserves have been discovered on an ongoing basis to maintain the reserves-to-production ratio at close to nine years. However, gas supply is expected to decline due to a continued reduction in levels of drilling activity in the WCSB. The reduced drilling activity is a result of lower prices, higher supply costs, which include higher royalties, and the stronger Canadian dollar. TCPL anticipates there will be excess natural gas pipeline capacity out of the WCSB in the foreseeable future as a result of capacity expansion on its wholly owned and partially owned natural gas pipelines over the past decade, competition from other pipelines, and significant growth in natural gas demand in Alberta driven by oilsands and electricity generation requirements.

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. Despite reduced overall drilling levels, activity remains robust in certain areas of the WCSB, which has resulted in the need for new transmission infrastructure. The primary areas of high activity have been deeper conventional drilling in western Alberta and in the foothills region of B.C., and coalbed methane development in central Alberta. The Alberta System has faced, and will continue to face,

MANAGEMENT'S DISCUSSION AND ANALYSIS 21

increasing competition from other natural gas pipelines. An emerging competitive issue for the Alberta System is the existence and access to natural gas liquids (NGL) contained in the natural gas transported by the pipeline system. In 2007, the EUB began a proceeding in relation to NGL extraction matters. The outcome of this proceeding may affect the way in which regulated natural gas pipelines compete within Alberta.

Historically, TCPL's eastern natural gas pipeline system has been supplied by long-haul flows from the WCSB and by short-haul volumes received from storage fields and interconnecting pipelines in southwestern Ontario. Over the last few years, the Canadian Mainline has experienced reductions in long-haul flows, which have been partially offset by increases in short-haul volumes. This reflects the combined impact of new U.S. Midwest-to-Ontario pipeline capacity and lower supply available for export from the WCSB region.

Demand for natural gas in TCPL's key eastern markets, which are served by the Canadian Mainline, 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 natural gas pipeline and supply options. Eastern markets that historically received Canadian supplies only from TCPL are now capable of receiving supplies from new natural gas pipelines that can source U.S. and Western and Atlantic Canadian supplies.

ANR's primary natural gas supply is sourced from the Gulf of Mexico and mid-continent U.S. regions, which are served by competing natural gas pipelines. ANR also has competition from other natural gas pipelines in its primary markets in the U.S. Midwest. The Gulf of Mexico region is extremely competitive given its extensive natural gas pipeline network. ANR is one of many interstate and intrastate pipelines in the region competing for new and existing production as well as for new supplies from LNG, from shale production in the mid-continent, and from the Rockies Express natural gas pipeline originating in the Rocky Mountain region. Several new natural gas pipelines are proposed or under construction to connect new supplies to the numerous pipelines in the Gulf of Mexico region. ANR competes with other natural gas pipelines in the region to attract supply to its pipeline for alternative markets and storage. The most recent changes in ANR's market region are the FERC-approved expansions of two competing pipelines, which will provide approximately 500 mmcf/d of incremental capacity into the Wisconsin market and approximately 200 mmcf/d of incremental capacity into the market extending from Chicago, Illinois, to Dawn, Ontario. The expanded transportation capacity competes directly with alternatives provided by ANR and Great Lakes, while incremental storage connections provide competitive alternatives to ANR's storage in Michigan.

The GTN System must compete with other pipelines to access natural gas supplies and markets. Transportation service capacity on the GTN System provides customers in the U.S. Pacific Northwest, California and Nevada with access to supplies of natural gas primarily from the WCSB. These three markets may also access supplies from other basins. In the Pacific Northwest market, natural gas transported on the GTN System competes with the Rocky Mountain natural gas supply and with additional western Canadian supply transported by other natural gas pipelines. Historically, natural gas supplies from the WCSB have been competitively priced in relation to supplies from the other regions serving these markets. The GTN System experienced significant contract non-renewals in 2005 and 2006 as natural gas transported from the WCSB on the GTN System competed for the California and Nevada markets against supplies from the Rocky Mountain and southwestern U.S. supply basins. Recently, Pacific Gas and Electric Company, the GTN System's largest customer, filed an application with the California Public Utilities Commission (CPUC) requesting approval to commit to capacity on a proposed project out of the Rocky Mountain basin to the California border. This project has not yet been filed with the FERC and TCPL is protesting the application filed with the CPUC.

Regulatory Financial Risk

Regulatory decisions continue to have a significant impact on the financial returns from existing investments in TCPL's Canadian wholly owned pipelines and are expected to have a similarly significant impact on financial returns from future investments. TCPL remains concerned that financial returns approved by regulators could potentially fail to be competitive with returns from assets with similar risk profiles. In recent years, TCPL applied to the NEB and the EUB for an ROE of 11 per cent on 40 per cent deemed common equity for both the Canadian Mainline and the Alberta System, respectively. The NEB has reaffirmed its ROE formula and the EUB has established a generic ROE, which largely aligns

22 MANAGEMENT'S DISCUSSION AND ANALYSIS

with the NEB formula. Through rate applications and negotiated settlements, TCPL has been able to improve the common equity components of its Canadian Mainline and Alberta System capital structures to the current 40 per cent and 35 per cent respectively.

TQM filed an application with the NEB in December 2007 requesting a fair return on capital, consisting of an ROE of 11 per cent on 40 per cent deemed common equity. The outcome of this proceeding may influence the regulators' view of fair financial returns on equity associated with TCPL's other Canadian wholly owned pipelines.

Throughput Risk

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

Execution and Capital Cost Risk

The construction of Keystone is subject to execution and capital cost risks, which is subject to a capital cost risk- and reward-sharing mechanism with its customers.

Refer to the "Risk Management and Financial Instruments" section of this MD&A for information on managing risks in the Pipelines business.

PIPELINES – OUTLOOK

Demand for natural gas and crude oil is expected to continue to grow across North America in 2008. TCPL's Pipelines business will continue to focus on the delivery of natural gas to growing markets, connecting new supply, progressing development of new infrastructure to connect natural gas from the north and unconventional supplies such as coalbed methane and LNG, and development of the Keystone oil pipeline.

TCPL expects producers will continue to explore and develop new fields in Western Canada, particularly in northeastern B.C. and the west central foothills regions of Alberta. There is also expected to be significant activity aimed at unconventional resources such as coalbed methane, which will be further incented starting in 2009 due to the new royalty structure in Alberta benefiting lower productivity wells.

Most of TCPL's current expansion plans in Canadian natural gas transmission are focused on the Alberta System. New facilities are expected to be needed to expand the integrated Alberta System to reflect changes in the distribution of supply and market within Alberta, connect new discrete supply sources, as well as new delivery points, primarily in the Alberta oilsands region and the central Alberta industrial heartland.

In the U.S., TCPL expects unconventional production will continue to be developed from the coalbed methane and tight gas sands of the Rocky Mountain region, as well as from shale plays in east Texas, southwestern Oklahoma and Arkansas. In addition, incremental supplies are anticipated from LNG imports into the U.S. Significant infrastructure is being built in the U.S. to accommodate these supply sources. The resulting growth in supply from LNG and the unconventional supply sources is likely to offer additional commercial opportunities for TCPL. In particular, the southwest leg of ANR is expected to continue to remain fully subscribed for the foreseeable future, and new transport routes are being developed to move additional Rocky Mountain production to midwestern and eastern U.S. markets, including interconnections with ANR. The southeast leg of ANR has the capacity to transport additional volumes of LNG and mid-continent shale production as these supplies develop.

Producers continue to develop new oil supply in the WCSB. In 2008, there are several new oilsands projects that will begin production, along with growth at existing projects. Oilsands production is expected to grow from 1.2 million Bbl/d in 2007 to 3.0 million Bbl/d in 2015, while total WCSB oil supply is projected to grow from 2.5 million Bbl/d to 3.9 million Bbl/d over the same period. The primary market for this new oilsands production is the U.S., extending from

MANAGEMENT'S DISCUSSION AND ANALYSIS 23

the U.S. Midwest to the Gulf of Mexico region, which contains a number of very large refineries, well equipped to handle Canadian heavy crude oil blends. WCSB crude oil is expected to replace declining U.S. imports of heavy crude oil from other countries.

This increase in WCSB crude oil exports requires new pipeline capacity, including Keystone, and further expansions to the Gulf of Mexico. TCPL will continue to pursue additional opportunities to move crude oil from the Alberta oilsands to U.S. markets.

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

Earnings

The Company expects continued growth on its Alberta System. The Company anticipates a modest level of investment in its other existing Canadian natural gas pipelines, resulting in an expected continued net decline in the average investment base due to annual depreciation. A net decline in the average investment base has the effect of reducing year-over-year earnings from these assets. However, this impact will be partially mitigated in 2008 by a slight increase in the formula-based regulated ROEs. Additionally, a settlement resulting from the current negotiations on the Alberta System may provide the opportunity for additional earnings contribution in 2008. Under the current regulatory model, earnings from Canadian pipelines are not affected by short-term fluctuations in the commodity price of natural gas, changes in throughput volumes or changes in contract levels.

Reduced FT contract volumes due to customer defaults, reduced supply available for export from the WCSB and expiry of long-term contracts could have a negative impact on short-term earnings from TCPL's U.S. natural gas pipelines, unless the available capacity can be recontracted. The ability to recontract available capacity is influenced by prevailing market conditions and competitive factors including competing natural gas pipelines and supply from other natural gas sources in markets served by TCPL's U.S. pipelines. Earnings from Pipelines' foreign operations are impacted by changes in foreign currency exchange rates. Pipelines' earnings in 2008 are expected to be positively impacted by a full year of operations from ANR and the additional interests in Great Lakes.

Certain subsidiaries of Calpine filed for bankruptcy protection in both Canada and the U.S. in 2005. Portland and GTNC have reached agreements with Calpine for allowed unsecured claims of US$125 million and US$192.5 million, respectively, in the Calpine bankruptcy. Creditors will receive shares in the re-organized Calpine and these shares will be subject to market price fluctuations as the new Calpine shares begin to trade. In February 2008, Portland and GTNC received initial distributions of 6.1 million shares and 9.4 million shares, respectively, which are expected to result in a significant increase in TCPL's net earnings in first-quarter 2008.

Claims by NOVA Gas Transmission Limited and Foothills Pipe Lines (South B.C.) Ltd. for $31.6 million and $44.4 million, respectively, were received in cash in January 2008 and will be passed on to shippers on these systems.

Capital Expenditures

Excluding the cost of acquiring ANR and additional interests in Great Lakes, total capital spending for the wholly owned pipelines in 2007 was $487 million. Capital spending for the wholly owned pipelines in 2008 is expected to be approximately $1.0 billion. In addition, capital spending for TCPL's 50 per cent share of constructing the Keystone pipeline is expected to be approximately $800 million.

24 MANAGEMENT'S DISCUSSION AND ANALYSIS

NATURAL GAS THROUGHPUT VOLUMES
(Bcf)

	2007	2006	2005
Canadian Mainline(1)	3,183	2,955	2,997
Alberta System(2)	4,015	4,051	3,999
ANR(3)	1,210
GTN System	827	790	777
Foothills(4)	1,441	1,403	1,372
North Baja	90	95	84
Great Lakes	829	816	850
Northern Border	800	799	808
Iroquois	394	384	394
TQM	207	158	166
Ventures LP	178	179	138
Gas Pacifico	71	52	34
Portland	58	52	62
Tamazunchale(5)	29	–
Tuscarora	28	28	25
TransGas	24	22	19

⁽¹⁾

Canadian Mainline deliveries originating at the Alberta border and in Saskatchewan in 2007 were 2,199 Bcf (2006 – 2,224 Bcf; 2005 – 2,215 Bcf).

⁽²⁾

Field receipt volumes for the Alberta System in 2007 were 4,047 Bcf (2006 – 4,160 Bcf, 2005 – 4,034 Bcf).

⁽³⁾

ANR was acquired February 22, 2007 and its volumes are included from this date.

⁽⁴⁾

Foothills volumes reflects the combined operations of Foothills and the BC System.

⁽⁵⁾

Tamazunchale's results include volumes since December 1, 2006.

MANAGEMENT'S DISCUSSION AND ANALYSIS 25

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

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

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

SUNDANCE A&B   The largest coal-fired electric power generating facility in Western Canada, Sundance is located in south-central Alberta. TCPL has the rights to 100 per cent of the generating capacity of the 560-MW Sundance A facility under a power purchase arrangement (PPA), which expires in 2017. TCPL also has the rights to 50 per cent of the generating capacity of the 706-MW Sundance B facility under a PPA, which expires in 2020.

SHEERNESS   Consisting of two 390-MW coal-fired thermal power generating units, the Sheerness plant is located in southeastern Alberta. TCPL has the rights to 756 MW of generating capacity from the Sheerness PPA, which expires in 2020.

26 MANAGEMENT'S DISCUSSION AND ANALYSIS

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

CANCARB   A 27-MW facility fuelled by waste heat from TCPL's adjacent thermal carbon black facility, Cancarb is located in Medicine Hat, Alberta.

BRUCE POWER   Consisting of two generating stations, Bruce A with approximately 3,000 MW of generating capacity and Bruce B with approximately 3,200 MW of generating capacity, Bruce Power is located in Ontario. TCPL owns 48.7 per cent of Bruce A, which has four power generating units, two of which have been idled for refurbishing and are expected to restart in 2010. TCPL owns 31.6 per cent of Bruce B, which also has four power generating units.

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

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

BÉCANCOUR   A 550-MW natural gas-fired cogeneration power plant, Bécancour is located near Trois-Rivières, Québec. The entire power output is supplied to Hydro-Québec under a 20-year power purchase contract. Steam is also sold to an industrial customer for use in commercial processes.

CARTIER WIND   The 740-MW Cartier wind farm project consists of six wind power projects located in Québec. Cartier Wind is 62 per cent owned by TCPL. Baie-des-Sables, with a generation capacity of 110 MW, and Anse-á-Valleau, with a generation capacity of 101 MW, were placed into service in November 2006 and November 2007, respectively. Construction of a third project, the 110-MW Carleton wind farm, began in late 2007. Planning and construction of the remaining three projects will continue, subject to future approvals.

GRANDVIEW   A 90-MW natural gas-fired cogeneration power plant, Grandview is located in Saint John, New Brunswick. Irving Oil Limited receives 100 per cent of the plant's heat and electricity output under a 20-year tolling agreement.

KIBBY WIND   A 132-MW wind power project, the proposed Kibby Wind includes 44 turbines located in Kibby and Skinner Townships in northwestern Franklin County, Maine. Subject to U.S. federal and state approvals, construction could begin in early 2008 and the new facilities could go into service in 2009-2010.

TC HYDRO   With a total generating capacity of 583 MW, TC Hydro comprises 13 hydroelectric facilities, including stations and associated dams and reservoirs, on the Connecticut and Deerfield rivers in New Hampshire, Vermont and Massachusetts.

OSP   A 560-MW natural gas-fired, combined-cycle facility, OSP is located in Rhode Island.

EDSON   An underground natural gas storage facility, Edson is connected to the Alberta System near Edson, Alberta. The facility's 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.

CROSSALTA   An underground natural gas storage facility, CrossAlta is connected to the Alberta System and is located near Crossfield, Alberta. TCPL owns 60 per cent of CrossAlta, which has a working natural gas capacity of 54 Bcf with a maximum deliverability capability of 480 mmcf/d.

CACOUNA   A proposed LNG project at Gros Cacouna Harbour on the St. Lawrence River in Québec, Cacouna would be capable of receiving, storing and regasifying imported LNG with an average send-out capacity of approximately 500 mmcf/d of natural gas. TCPL has a 50 per cent ownership interest in Cacouna.

BROADWATER   A proposed offshore LNG project located in the New York waters of Long Island Sound, Broadwater would be capable of receiving, storing and regasifying imported LNG with an average send-out capacity of approximately 1 Bcf/d of natural gas. TCPL has a 50 per cent ownership interest in Broadwater.

MANAGEMENT'S DISCUSSION AND ANALYSIS 27

ENERGY – HIGHLIGHTS

Net Earnings

•

Energy's net earnings were $514 million in 2007, an increase of $62 million from $452 million in 2006.



•

Energy's comparable earnings were $466 million in 2007, up $37 million from $429 million in 2006. Comparable earnings excluded positive income tax adjustments in 2007 and 2006 and a gain on sale of land in 2007, and increased primarily due to higher operating income from Eastern Power and Natural Gas Storage.



•

Results in 2007 included the first full year of earnings from the Bécancour cogeneration plant, the Baie-des-Sables Cartier Wind project, and the Edson natural gas storage facility.

Expanding Asset Base

•

Approximately 2,000 MW of additional generation capacity was under construction at December 31, 2007, with an anticipated capital cost of more than $4.2 billion.



•

Since 1999, TCPL's Energy business has grown its nominal generating capacity by approximately 5,300 MW, excluding 2,000 MW currently under construction, representing an investment of more than $5 billion to the end of 2007.



•

The Anse-á-Valleau Cartier Wind project was completed and placed into service in November 2007.



•

Construction continued in 2007 on the Bruce A refurbishment and restart project, which includes restart of the currently idle power generating Units 1 and 2, and replacement of the steam generators and installation of new fuel channels on Units 3 and 4.

Plant Availability

•

Weighted average power plant availability was 91 per cent in 2007, which was consistent with 2006.



•

Weighted average power plant availability, excluding Bruce, was 93 per cent in 2007, which was consistent with 2006.

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

	2007		2006		2005
Western Power	308		297		123
Eastern Power	255		187		137
Bruce Power	167		235		195
Natural Gas Storage	146		93		32
Power LP Investment	–		–		29
General, administrative, support costs and other	(158	)	(144	)	(129	)
Operating income	718		668		387
Financial charges	(22	)	(23	)	(11	)
Interest income and other	10		5		5
Income taxes	(240	)	(221	)	(123	)
Comparable earnings(1)	466		429		258
Income tax adjustments	34		23		–
Gain on sale of land	14		–		–
Gain on sale of Paiton Energy	–		–		193
Gain on sale of Power LP units	–		–		115
Net earnings	514		452		566

⁽¹⁾

Refer to the "Non-GAAP Measures" section of this MD&A for further discussion of comparable earnings.

28 MANAGEMENT'S DISCUSSION AND ANALYSIS

Energy's net earnings in 2007 were $514 million compared to $452 million in 2006. Comparable earnings were $466 million in 2007, an increase of $37 million from 2006. Comparable earnings exclude the $14-million gain on sale of land and the $34-million favourable income tax adjustments in 2007 as well as the $23-million favourable impact in 2006 from future income taxes as a result of reductions in Canadian federal and provincial corporate income tax rates. The increase was due primarily to higher operating income in Eastern Power, Natural Gas Storage and Western Power, partially offset by a reduced contribution from Bruce Power.
Energy's net earnings in 2006 were $452 million compared to $566 million in 2005. The decrease was due primarily to the inclusion in 2005 net earnings of gains related to the disposal of TCPL's investments in

Paiton Energy and Power LP. In 2005, TCPL sold its interest of approximately 11 per cent in Paiton Energy resulting in an after-tax gain of $115 million and sold its ownership interest in Power LP resulting in an after-tax gain of $193 million.

Energy's comparable earnings, which exclude the $23-million favourable impact on future income taxes in 2006 and the Power LP and Paiton Energy gains in 2005, were $429 million in 2006, an increase of $171 million from $258 million in 2005. The increase was due primarily to higher contributions from each of Energy's existing businesses, including a full year of earnings from TC Hydro, partially offset by the loss of operating income associated with the sale of the Power LP interest in 2005.

POWER PLANTS – NOMINAL GENERATING CAPACITY AND FUEL TYPE

		MW	Fuel Type
Western Power
	Sheerness(1)	756	Coal
	Sundance A(2)	560	Coal
	Sundance B(2)	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
	Halton Hills(3)	683	Natural gas
	TC Hydro(4)	583	Hydro
	OSP	560	Natural gas
	Bécancour(5)	550	Natural gas
	Cartier Wind(6)	458	Wind
	Portlands Energy(7)	275	Natural gas
	Grandview(8)	90	Natural gas
		3,199
Bruce Power(9)		2,474	Nuclear
Total nominal generating capacity		7,734

⁽¹⁾

TCPL has sole access to 756 MW from Sheerness through a long-term PPA lease.

MANAGEMENT'S DISCUSSION AND ANALYSIS 29

⁽²⁾

TCPL directly or indirectly has the rights to 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.

⁽³⁾

Currently under construction.

⁽⁴⁾

Acquired in second-quarter 2005.

⁽⁵⁾

Placed in service in third-quarter 2006.

⁽⁶⁾

Represents TCPL's 62 per cent share of the total 740-MW project. Two of six wind farms were placed in service, one in November 2006 and the other in November 2007, with a combined generating capacity of 211 MW.

⁽⁷⁾

Represents TCPL's 50 per cent share of this 550-MW facility, which is currently under construction.

⁽⁸⁾

Placed in service in first-quarter 2005.

⁽⁹⁾

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, two of which are currently being refurbished and are expected to restart in 2010. Bruce B consists of four reactors, which are currently in operation and have a combined capacity of approximately 3,200 MW.

ENERGY – FINANCIAL ANALYSIS

Western Power

As at December 31, 2007, Western Power owns or has the rights to approximately 2,100 MW of power supply in Alberta from its three long-term PPAs and five natural gas-fired cogeneration facilities. The power supply portfolio of Western Power comprises approximately 1,700 MW of low-cost, base-load coal-fired generation supply through the three long-term PPAs 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. On December 31, 2005, $585 million was paid to the Alberta Balancing Pool for the remaining rights of the Sheerness PPA, which has a remaining term of approximately 13 years. The Sundance A and B PPAs have remaining terms of 10 years and 13 years, respectively.

Western Power relies on its two integrated functions, marketing and plant operations, to generate earnings. The marketing function, based in Calgary, Alberta, purchases and resells electricity sourced from the PPAs, markets uncommitted 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 to managing risks associated with uncontracted volumes. A portion of its power is sold into the spot market for operational reasons and the amount of supply volumes eventually sold into the spot market is dependent upon the ability to transact in forward sales markets at acceptable contract terms. This approach to portfolio management helps to minimize costs in situations where TCPL would otherwise have to purchase electricity in the open market to fulfil its contractual sales obligations. To reduce its exposure to spot market prices on uncontracted volumes, Western Power had, as at December 31, 2007, fixed-price power sales contracts to sell approximately 9,200 gigawatt hours (GWh) in 2008 and 6,800 GWh in 2009.

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 remaining output is subject to fluctuations in the price of power and gas. Market heat rate is an economic measure for natural gas-fired power plants and is determined by dividing the average price of power per megawatt hour (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 profitability of a natural gas-fired generating facility rises in proportion to increases in the market heat rate, and, conversely, declines in proportion to decreases in the market heat rate. Market heat rates in Alberta decreased in 2007 by approximately 16 per cent as a result of a decrease in average power prices, while spot market natural gas prices remained relatively unchanged. Market heat rates averaged approximately 11.4 GJ/MWh in 2007 compared to approximately 13.5 GJ/MWh in 2006.

All plants in Western Power operated with an average plant availability of approximately 90 per cent in 2007 compared to 88 per cent in 2006.

30 MANAGEMENT'S DISCUSSION AND ANALYSIS

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

		2007		2006		2005
Revenues
	Power	1,045		1,185		715
	Other(1)	89		169		158
		1,134		1,354		873
Commodity purchases resold
	Power	(608	)	(767	)	(476	)
	Other(2)	(65	)	(135	)	(104	)
		(673	)	(902	)	(580	)
Plant operating costs and other		(135	)	(135	)	(149	)
Depreciation		(18	)	(20	)	(21	)
Operating income		308		297		123

⁽¹⁾

Includes natural gas sold and Cancarb Thermax, the thermal carbon black facility adjacent to Cancarb.

⁽²⁾

Includes the cost of natural gas sold.

Western Power Sales Volumes
Year ended December 31 (GWh)

			2007	2006	2005
Supply
	Generation		2,154	2,259	2,245
	Purchased
		Sundance A & B and Sheerness PPAs	12,199	12,712	6,974
		Other purchases	1,433	1,905	2,687
			15,786	16,876	11,906
Contracted vs. Spot
	Contracted		11,998	12,750	10,374
	Spot		3,788	4,126	1,532
			15,786	16,876	11,906

Operating income was $308 million in 2007, an increase of $11 million from $297 million in 2006. The increase was due primarily to lower PPA costs, partially offset by slightly lower overall realized power prices. Revenues decreased in 2007 compared to 2006 due mainly to the lower overall power sales prices realized in 2007 as well as lower volumes purchased and generated. Commodity purchases resold decreased in 2007 compared to 2006 due primarily to lower PPA costs, a decrease in volumes purchased and the expiry of certain retail contracts. Purchased power volumes in 2007 decreased compared to 2006 mainly as a result of an increase in outage hours at the Sundance A facility and the expiry of certain retail contracts. Approximately 24 per cent of power sales volumes were sold in to the spot market in 2007, which was consistent with 2006.

Operating income was $297 million in 2006, an increase of $174 million from $123 million in 2005. The increase was due primarily to incremental earnings from the acquisition of the Sheerness PPA on December 31, 2005, and increased

MANAGEMENT'S DISCUSSION AND ANALYSIS 31

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 due mainly to the acquisition of the Sheerness PPA as well as higher realized power prices. Plant operating costs and other, which includes fuel gas consumed in power generation, decreased due to lower natural gas prices. Purchased power volumes in 2006 increased compared to 2005 due primarily to the acquisition of the Sheerness PPA. Approximately 24 per cent of power sales volumes were sold into the spot market in 2006 compared to 13 per cent in 2005.

Eastern Power

Eastern Power owns approximately 3,200 MW of power generation capacity, including facilities under construction or in the development phase. Eastern Power's current operating power generation assets are TC Hydro, Ocean State Power (OSP), Bécancour and Grandview, and the Baie-des-Sables and Anse-á-Valleau wind farms. The TC Hydro assets include 13 hydroelectric stations housing 39 hydroelectric generating units in New Hampshire, Vermont and Massachusetts.

Eastern Power conducts its business primarily in the deregulated New England power market and in Eastern Canada. In the New England market, TCPL has established a successful marketing operation through its wholly owned subsidiary, TransCanada Power Marketing Ltd. (TCPM), located in Westborough, Massachusetts. To reduce exposure to spot market prices on uncontracted volumes, Eastern Power had, as at December 31, 2007, fixed price sales contracts to sell forward approximately 8,200 GWh in 2008 and 9,900 GWh in 2009. Fixed price sales contracts in 2008 exclude approximately 4,200 GWh of generation from the Bécancour power plant as a result of the request from Hydro-Québec to suspend electricity generation, beginning January 1, 2008.

TCPM focuses 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. In 2007, TCPM continued to expand its marketing presence and customer base.

In June 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 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 May 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. Eastern Power's OSP plant and TC Hydro generation facilities are eligible to receive payments during the transition period. Under the new FCM design, Independent System Operator New England will project the needs of the power system three years in advance, following which it will hold an annual auction to purchase power resources to satisfy a region's future needs. Suppliers will receive payments pursuant to the FCM auction mechanism commencing June 1, 2010.

32 MANAGEMENT'S DISCUSSION AND ANALYSIS

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

		2007		2006		2005
Revenues
	Power	1,481		789		505
	Other(2)	239		292		412
		1,720		1,081		917
Commodity purchases resold
	Power	(755	)	(379	)	(215	)
	Other(2)	(208	)	(257	)	(373	)
		(963	)	(636	)	(588	)
Plant operating costs and other		(454	)	(226	)	(167	)
Depreciation		(48	)	(32	)	(25	)
Operating income		255		187		137

⁽¹⁾

Includes Bécancour, Baie-des-Sables and Anse-à-Valleau, effective September 17, 2006, November 21, 2006 and November 10, 2007, respectively.

⁽²⁾

Other includes natural gas sales and purchases.

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

		2007	2006	2005
Supply
	Generation	8,095	4,700	2,879
	Purchased	6,986	3,091	2,627
		15,081	7,791	5,506
Contracted vs. Spot
	Contracted	14,505	7,374	4,919
	Spot	576	417	587
		15,081	7,791	5,506

⁽¹⁾

Includes Bécancour, Baie-des-Sables and Anse-à-Valleau, effective September 17, 2006, November 21, 2006 and November 10, 2007, respectively.

Operating income was $255 million in 2007, $68 million higher than the $187 million earned in 2006. The increase was due primarily to incremental income from the first full year of operation of the Bécancour facility and the Baie-des-Sables wind farm, and from the start-up of the Anse-à-Valleau wind farm in November 2007. Also contributing to the increase were payments received under the start-up of the FCM in New England and higher sales volumes to commercial and industrial customers in 2007. Partially offsetting these increases was the impact of reduced water flows from the TC Hydro generation assets in 2007, compared to the above-average water flows experienced in 2006 following higher precipitation in the surrounding area.

Eastern Power's revenues from power were $1,481 million in 2007, an increase of $692 million from $789 million in 2006. The substantial growth was driven primarily by the first full year of revenue from the Bécancour facility and the

MANAGEMENT'S DISCUSSION AND ANALYSIS 33

Baie-des-Sables wind farm, which went into service in September and November 2006, respectively, as well as by 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 OSP's natural gas supply contracts. Power commodity purchases resold and purchased power volumes were higher in 2007 due to the impact of increased purchases to supply higher sales volumes to wholesale, commercial and industrial customers. The increase in purchased power volumes was partially offset by additional power generation from the OSP plant, which reduced the requirement to purchase power to fulfill contractual sales obligations. Plant operating costs and other, which includes fuel gas consumed in generation, were higher in 2007 due primarily to the full year of operations of the Bécancour facility and increased power generation from the OSP plant.

Operating income was $187 million in 2006, an increase of $50 million from $137 million earned in 2005. The increase was due mainly to incremental income from the full year of ownership of the TC Hydro assets, the start-up of the Bécancour facility, 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.

Bruce Power

In 2005, Bruce Power and the Ontario Power Authority (OPA) completed a long-term agreement whereby Bruce A committed to refurbish and restart 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. An amendment to this agreement in 2007 is described further in the "Energy – Opportunities and Developments" section of this MD&A. As a result of an agreement between Bruce Power and the OPA, and Cameco Corporation's (Cameco) decision not to participate in the refurbishment and restart program, the Bruce A partnership was formed by TCPL and BPC Generation Infrastructure Trust (BPC), with each owning a 48.7 per cent interest in Bruce A at December 31, 2007 (2006 – 48.7 per cent, 2005 – 47.9 per cent). 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 interest in Bruce A is owned by BPC, a trust established by the Ontario Municipal Employees Retirement System, the Power Worker's Union and The Society of Energy Professionals. The Bruce A partnership subleases Bruce A 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 six of the eight Bruce Power units in all periods.

34 MANAGEMENT'S DISCUSSION AND ANALYSIS

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

			2007		2006		2005
Bruce Power (100 per cent basis)
	Revenues
		Power	1,920		1,861		1,907
		Other(1)	113		71		35
			2,033		1,932		1,942
	Operating expenses
		Operations and maintenance(2)	(1,051	)	(912	)	(871	)
		Fuel	(104	)	(96	)	(77	)
		Supplemental rent(2)	(170	)	(170	)	(164	)
		Depreciation and amortization	(151	)	(134	)	(198	)
			(1,476	)	(1,312	)	(1,310	)
	Revenues, net of operating expenses		557		620		632
		Financial charges under equity accounting(3)	–		–		(58	)
			557		620		574
TCPL's proportionate share – Bruce A			24		91		22
TCPL's proportionate share – Bruce B			161		137		166
TCPL's proportionate share			185		228		188
Adjustments			(18	)	7		7
TCPL's operating income from Bruce Power(3)			167		235		195
Bruce Power – Other Information
Plant availability
	Bruce A		78%		81%		94%
	Bruce B		89%		91%		79%
	Combined Bruce Power		86%		88%		80%
Planned outage days
	Bruce A		121		81		106
	Bruce B		93		65		153
Unplanned outage days
	Bruce A		17		37		30
	Bruce B		32		31		104
Sales volumes (GWh)
	Bruce A – 100 per cent		10,180		10,650		2,100
	Bruce A – TCPL's proportionate share		4,959		5,158		999
	Bruce B – 100 per cent		25,290		25,820		30,800
	Bruce B – TCPL's proportionate share		7,992		8,159		9,733
	Combined Bruce Power – 100 per cent		35,470		36,470		32,900
	TCPL's proportionate share		12,951		13,317		10,732
Results per MWh
	Bruce A power revenues		$59		$58		$57
	Bruce B power revenues		$52		$48		$58
	Combined Bruce Power revenues		$55		$51		$58
	Combined Bruce Power fuel		$3		$3		$2
	Combined Bruce Power total operating expenses(4)		$41		$35		$40
Percentage of output sold to spot market			45%		35%		49%

MANAGEMENT'S DISCUSSION AND ANALYSIS 35

⁽¹⁾

Includes fuel cost recoveries of $35 million for Bruce A in 2007 (2006 – $30 million; November 1 to December 31, 2005 – $4 million). Includes changes in fair value of held-for-trading derivatives of $47 million in 2007 (2006 – nil; 2005 – nil).

⁽²⁾

Includes adjustments to eliminate the effects of inter-partnership transactions between Bruce A and Bruce B.

⁽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⁾

Net of fuel cost recoveries.

TCPL's operating income from its investment in Bruce Power was $167 million in 2007 compared to $235 million in 2006. TCPL's proportionate share of operating income in Bruce B increased $24 million to $161 million in 2007 compared with 2006 due primarily to higher realized power prices, partially offset by higher operating costs associated with an increase in planned outage days in 2007. TCPL's proportionate share of operating income in Bruce A decreased $67 million to $24 million in 2007 compared with 2006 due primarily to lower output and higher operating costs associated with an increase in planned outage days in 2007. Higher post-employment benefit costs and lower positive purchase price amortizations related to the expiry of power sales agreements also contributed to the decrease in TCPL's operating income from its combined investment in Bruce power in 2007 compared to 2006.

Combined Bruce Power prices (excluding other revenues) were $55 per MWh in 2007 compared to $51 per MWh in 2006, reflecting higher prices on both contracted volumes and uncontracted volumes sold into the spot market. Bruce Power's combined operating expenses (net of fuel cost recoveries) increased to $41 per MWh in 2007 from $35 per MWh in 2006 due primarily to higher operating costs and decreased output in 2007.

The Bruce units ran at a combined average availability of 86 per cent in 2007, compared to an 88 per cent average availability in 2006. The lower availability in 2007 was the result of more planned maintenance outage days, partially offset by fewer unplanned outage days in 2007.

TCPL's operating income from its combined investment in Bruce Power was $235 million in 2006 compared to $195 million in 2005. The increase of $40 million was due primarily 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.

Adjustments to TCPL's combined interest in Bruce Power's income before income taxes were lower in 2007 than in 2006 and 2005 due primarily to lower positive purchase price amortizations related to the expiry of power sales agreements.

Income from Bruce B is directly affected by fluctuations in wholesale spot market prices for electricity. Income from both Bruce A and Bruce B is affected by overall plant availability, which in turn is affected by planned and unplanned maintenance. As a result of a contract with the OPA, all of the output from Bruce A is sold at a fixed price per MWh, adjusted for inflation annually on April 1, and before recovery of fuel costs from the OPA. Per the 2007 amendment of the contract with the OPA, discussed in the "Energy – Opportunities and Developments" section, effective April 1, 2008, the fixed price for output from Bruce A will also increase by $2.11 per MWh, subject to inflation adjustments from October 31, 2005.

	per MWh
April 1, 2007 – March 31, 2008	$59.69
April 1, 2006 – March 31, 2007	$58.63
October 31, 2005 – March 31, 2006	$57.37

36 MANAGEMENT'S DISCUSSION AND ANALYSIS

Payments received pursuant to the fixed-price contract are capped at $575 million for the period ending on the commercial in-service date of the later of the restarted Unit 1 and Unit 2. Post-refurbishment prices will also be adjusted for capital cost variances associated with the refurbishment and restart projects.

As part of this contract, sales from the Bruce B Units 5 to 8 are subject to a floor price adjusted annually for inflation on April 1.

	per MWh
April 1, 2007 – March 31, 2008	$46.82
April 1, 2006 – March 31, 2007	$45.99
October 31, 2005 – March 31, 2006	$45.00

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 date do not include any amounts received pursuant to this floor mechanism. To further reduce its exposure to spot market prices, Bruce B entered into fixed price sales contracts as at December 31, 2007, to sell forward approximately 10,200 GWh in 2008 and 4,900 GWh in 2009.

The overall plant availability percentage in 2008 is expected to be in the low 90s for the four Bruce B units and the low 80s for the two operating Bruce A units. A planned maintenance outage of Bruce B Unit 7 began at the end of January 2008 and the unit is expected to be back in service in March 2008. A planned maintenance outage of Bruce B Unit 5 is scheduled to begin in early May 2008 and the unit is expected to return to service in late second-quarter 2008. A one-month maintenance outage of Bruce A Unit 4 is scheduled to start in late March 2008 and a two-month outage of Bruce A Unit 3 is expected to commence mid-September 2008.

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 refurbishment and restart project.

Power LP Divestiture

TCPL sold all of its interest in Power LP to EPCOR Utilities Inc. in August 2005 for net proceeds of $523 million, resulting in an after-tax gain of $193 million. TCPL's investment in Power LP generated operating income of $29 million in 2005.

Plant Availability

Weighted average power plant availability for all plants, excluding Bruce Power, was 93 per cent in 2007 and 2006, compared to 87 per cent in 2005. Plant availability represents the percentage of time in a year that the plant is available to generate power whether actually running or not, reduced by planned and unplanned outages. Western Power's plant availability was affected negatively in 2006 and 2005 by an unplanned outage at Bear Creek, which returned to service in August 2006. A planned outage was taken in 2005 at the MacKay River facility, further decreasing Western Power's plant availability in 2005. Eastern Power achieved plant availability of 96 per cent in 2007, which was consistent with 2006. Availability was lower in 2005 as a result of OSP experiencing two significant outages.

MANAGEMENT'S DISCUSSION AND ANALYSIS 37

Weighted Average Plant Availability⁽¹⁾
Year ended December 31

	2007	2006	2005
Western Power(2)	90%	88%	85%
Eastern Power(3)	96%	95%	83%
Bruce Power	86%	88%	80%
Power LP investment(4)	–	–	94%
All plants, excluding Bruce Power investment	93%	93%	87%
All plants	91%	91%	84%

⁽¹⁾

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

⁽²⁾

The Sheerness PPA is included in Western Power, effective December 31, 2005.

⁽³⁾

TC Hydro, Bécancour, Baie-des-Sables and Anse-á-Valleau are included in Eastern Power effective April 1, 2005, September 17, 2006, November 21, 2006 and November 10, 2007, respectively.

⁽⁴⁾

Power LP is included to August 31, 2005.

Natural Gas Storage

TCPL became one of the largest natural gas storage providers in Western Canada when the Edson storage facility was placed in service on December 31, 2006, with a final commissioning date of April 1, 2007. TCPL owns or has rights to 120 Bcf of natural gas storage capacity in Alberta, including a 60 per cent ownership interest in CrossAlta Gas Storage & Services Ltd. (CrossAlta), an independently operated storage facility. TCPL also has contracts for long-term, Alberta-based storage capacity from a third party, which expire in 2030 and include mutual early termination rights in 2015.

Natural Gas Storage Capacity

	Working Gas Storage Capacity (Bcf)	Maximum Injection/ Withdrawal Capacity (mmcf/d)
Edson	50	725
CrossAlta(1)	32	288
Third-party storage	38	630
	120	1,643

⁽¹⁾

Represents TCPL's 60 per cent ownership interest in CrossAlta, a 54-Bcf, 480-mmcf/d facility.

TCPL believes the market fundamentals for natural gas storage remain strong. The Company's additional gas storage capacity is expected to help balance seasonal and short-term supply and demand, and bring flexibility to the supply of natural gas to Alberta and the rest of North America. The increasing seasonal imbalance in North American natural gas supply and demand has increased natural gas price volatility and the demand for storage services. 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 and ANR's regulated storage business, which is included in TCPL's Pipelines segment.

TCPL manages its non-regulated natural gas storage assets' exposure to seasonal natural gas price spreads by hedging storage capacity with a portfolio of third-party storage capacity leases and proprietary natural gas purchases and sales.

38 MANAGEMENT'S DISCUSSION AND ANALYSIS

In Alberta, TCPL offers a broad range of injection and withdrawal storage alternatives specific to customer needs in multi-year contracts. Market volatility frequently creates arbitrage opportunities and TCPL's storage operations offer solutions to capture value from these short-term price movements. Products consist of short-term deliver-redeliver contracts, parking, peak-day supply and other related services. Earnings from third-party storage capacity leases are recognized over the term of the lease. At December 31, 2007, TCPL had contracted approximately 74 per cent of the total 120 Bcf of working gas storage capacity in 2008 and 50 per cent of storage capacity in 2009.

TCPL adopted an accounting policy to record proprietary natural gas inventory held in storage at its fair value using the one-month forward price for natural gas, effective April 1, 2007. Changes in the fair value of inventory are recorded in Net Income.

Proprietary natural gas storage transactions are comprised of a forward purchase of natural gas to be injected into storage and a simultaneous forward sale of natural gas for withdrawal at a later period, typically during the winter withdrawal season. By matching purchase and sales volumes on a back-to-back basis, TCPL locks in a margin, thereby effectively eliminating its exposure to the price movements of natural gas. These forward natural gas contracts provide highly effective economic hedges but do not meet the specific criteria for hedge accounting and, therefore, are recorded at their fair values based on the forward market prices for the contracted month of delivery. Changes in the fair value of these contracts are recorded in Net Income. In 2007, operating income included a $10-million net unrealized gain for the changes in fair value of the proprietary natural gas inventory and forward purchase and sales contracts.

Natural Gas Storage operating income was $146 million in 2007, an increase of $53 million compared to 2006. The increase was due primarily to income earned from the first full year of operations of the Edson facility.

Natural Gas Storage operating income was $93 million in 2006, an increase of $61 million compared to 2005. The increase was due primarily to higher contributions from CrossAlta as a result of increased utilization and higher natural gas storage spreads as well as income from contracted third-party natural gas storage capacity. The Edson facility did not contribute to earnings in 2006 as it went into service on December 31, 2006.

ENERGY – OPPORTUNITIES AND DEVELOPMENTS

Portlands Energy    Construction continued in 2007 on the Portlands Energy Centre L.P. (Portlands Energy) project. The capital cost is expected to be approximately $730 million and the facility is expected to be operational in single cycle mode beginning June 2008. Upon final completion of the combined-cycle mode planned for second-quarter 2009, the plant is expected to provide power under a 20-year Accelerated Clean Energy Supply contract with the OPA.

Halton Hills    Site preparation and construction began in 2007 on the Halton Hills Generating Station (Halton Hills). The project includes the construction and operation of a natural gas-fired power plant near the town of Halton Hills, Ontario. TCPL expects to invest approximately $670 million in the project, which is anticipated to be in service in third-quarter 2010. Power from the facility will be sold to the OPA under a 20-year Clean Energy Supply contract.

Cartier Wind    The Anse-à-Valleau wind farm went into commercial operation in November 2007, providing up to 101 MW of power to the Hydro Québec grid, and construction began in 2007 on the Carleton wind farm with a generation capacity of 110 MW. Carleton is expected to enter commercial service in fourth-quarter 2008. Anse-à-Valleau and Carleton are the second and third phases, respectively, of the six-phase, multi-year Cartier Wind project, located in the Gaspé region of Québec. The first phase, Baie-des-Sables, went into service in November 2006, generating up to 110 MW of power. The remaining phases of Cartier Wind are expected to be constructed through 2012, subject to the necessary approvals. Capacity is expected to total 740 MW when all six phases are complete.

MANAGEMENT'S DISCUSSION AND ANALYSIS 39

Kibby Wind    In January 2008, Maine's Land Use Regulation Commission voted to recommend the approval of the zoning changes and preliminary development plan submitted by TCPL to build, own and operate a wind farm in Maine. Subject to U.S. federal and state approvals, construction of the new facilities could begin in 2008, with the project being commissioned in 2009-2010.

Bécancour    TCPL entered into an agreement with Hydro-Québec in November 2007 to temporarily suspend all electricity generation from the Bécancour power plant during 2008. The agreement, which was requested by Hydro-Québec as a result of its excess electricity supply, was approved by Québec's Régie de l'énergie in December 2007. The agreement also provides Hydro-Québec the option to extend the suspension to 2009. TCPL will receive payments under the agreement similar to those that would have been received under the normal course of operation.

Bruce Power    Bruce Power and the OPA amended their Bruce A refurbishment agreement in 2007 to allow for the installation of 480 new fuel channels in Unit 4. Under the original plan, Bruce Power intended to install new steam generators in all four Bruce A units and replace the fuel channels in Units 1, 2 and 3. By replacing the fuel channels in Unit 4, Bruce Power will extend the expected operational life of the unit to 2036 from 2017. Under the amended agreement, the OPA may elect prior to April 1, 2008 to proceed with a three-unit refurbishment and restart program.

The amended refurbishment capital program was originally expected to cost $5.25 billion with $2.75 billion being attributed to refurbishing and restarting Units 1 and 2 and $2.5 billion being attributed to refurbishing Units 3 and 4. In January 2008, a milestone in the Bruce A Units 1 and 2 refurbishment and restart project was completed when the sixteenth and final new steam generator was installed. With the completion of this stage of the project, the authorized funding for Units 1 and 2 was increased to approximately $3.0 billion from $2.75 billion. Bruce Power is currently preparing a comprehensive estimate of the cost to complete the Unit 1 and 2 restart. This process is expected to result in a further increase in the total project cost. Project cost increases are subject to the capital cost risk- and reward-sharing mechanism under the agreement with the OPA. Bruce A Units 1 and 2 are expected to produce an additional 1,500 MW of power when completed in 2010.

As at December 31, 2007, Bruce A had incurred $1.9 billion in costs with respect to the refurbishment and restart of Units 1 and 2 and approximately $0.2 billion for the refurbishment of Units 3 and 4.

LNG Projects

TCPL continues to pursue proposals to build, own and operate LNG facilities, including the Broadwater LNG project (Broadwater) and the Cacouna LNG project (Cacouna).

Broadwater    Broadwater, a joint venture with Shell US Gas & Power LLC in which TCPL holds a 50 per cent interest, is a proposed LNG facility in New York State waters in Long Island Sound. The Broadwater terminal would be capable of receiving, storing, and regasifying imported LNG with an average send-out capacity of approximately 1 Bcf/d of natural gas. Coincident with the FERC process, Broadwater applied to the New York Department of State for a determination that the project is consistent with New York's coastal zone policies. The state's decision is expected in second-quarter 2008. In January 2008, the FERC issued the FEIS, which confirmed project need, supported the location of the project with acknowledgement of its target market and delivery goals, and found safety and security risks to be limited and acceptable. The FEIS also concluded that with adherence to federal and state permit requirements and regulations, Broadwater's proposed mitigation measures and the FERC's recommendations, the project will not result in a significant impact on the environment. At December 31, 2007, the Company had capitalized $40 million related to Broadwater.

Cacouna    Cacouna, a joint venture with Petro-Canada in which TCPL holds a 50 per cent interest, 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 regasifying imported LNG with an average throughput capacity of approximately 500 mmcf/d of natural gas. Following public hearings in 2006, the Québec government granted a provincial decree in June 2007 approving the Cacouna terminal. Also in June 2007, the project received federal approvals pursuant to the Canadian Environmental Assessment Act. A delay to 2012 from 2010 in the planned in-service date for the regasification terminal was announced in September 2007. This delay resulted from a need to assess the impacts of permit conditions, to

40 MANAGEMENT'S DISCUSSION AND ANALYSIS

review the facility design in light of escalating costs and to align the schedule with potential LNG supply facilities. In February 2008, the potential anchor LNG supplier for the Cacouna terminal announced it would no longer be pursuing the development of its LNG supply as originally planned. As a result of this announcement, TCPL and Petro-Canada are currently reviewing their strategy for the project.

ENERGY – BUSINESS RISKS

Fluctuating Power and Natural Gas Market Prices

TCPL operates in competitive power and natural gas markets in North America. Volatility in power and natural gas prices is caused by 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 wholly owned assets.

Uncontracted Volumes

Energy has certain uncontracted power sales volumes in Western Power and Eastern Power and through its investment in Bruce Power. Sale of uncontracted power volumes into the spot market is subject to market price 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 into the Ontario wholesale power spot market under fixed contract price terms with the OPA. 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 containing 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, which is to provide low-cost, reliable operating performance at each of the Company's facilities. Unexpected plant outages and 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 ensure TCPL meets 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

TCPL's power operations are subject to hydrology risk arising from the 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 programs in Ontario and Québec, including its investment in Bruce Power, are subject to execution and capital cost risks. At Bruce Power, Bruce A's four unit refurbishment and restart project is also subject to a capital cost risk- and reward-sharing mechanism with the OPA.

Asset Commissioning

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 their first year of operations.

MANAGEMENT'S DISCUSSION AND ANALYSIS 41

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 regulatory reform and participate in and lead discussions around these topics.

Refer to the "Risk Management and Financial Instruments" section of this MD&A for information on managing risks in the Energy business.

ENERGY – OUTLOOK

Although TCPL has sold forward significant output from its Alberta PPAs and power plants and capacity from its natural gas storage facilities, operating income in 2008 can be affected by changes in the spot market price of power, market heat rates, hydrology, natural gas storage spreads and unplanned outages. Operating income from Energy's foreign operations is impacted by changes in foreign currency exchange rates. TCPL's operating income from its investment in Bruce B can be significantly affected by the impact on uncontracted output of changes in spot market prices for power. Bruce Power's operating income is expected to be impacted by higher projected generation volumes and lower outage costs resulting from a decrease in planned outages in 2008 compared to 2007.

Other factors such as plant availability, regulatory changes, weather, currency movements, and overall stability of the energy industry can also impact 2008 operating income. Refer to the "Energy – Business Risks" section of this MD&A for a complete discussion of these factors.

Capital Expenditures

Total capital expenditures for Energy in 2007 were $1.1 billlion. Energy's overall capital spending in 2008 is expected to be approximately $1.1 billion and includes cash calls for the Bruce A refurbishment and restart project as well as continued construction at Halton Hills, Portlands Energy and Cartier Wind.

CORPORATE

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

		2007		2006		2005
Indirect financial charges and non-controlling interests		266		139		131
Interest income and other		(81	)	(43	)	(29	)
Income taxes		(127	)	(61	)	(65	)
Comparable expenses(1)		58		35		37
	Income tax reassessments and adjustments	(68	)	(72	)	–
Net (earnings)/expenses, after income taxes		(10	)	(37	)	37

⁽¹⁾

Refer to the "Non-GAAP Measures" section of this MD&A for further discussion of comparable earnings.

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

•

Indirect Financial Charges and Non-Controlling Interests  Direct financial charges are reported in their respective business segments and are associated primarily with debt and preferred securities related to the Company's wholly owned natural gas pipelines. Indirect financial charges, including the related foreign exchange impacts, reside mainly

42 MANAGEMENT'S DISCUSSION AND ANALYSIS

in Corporate. These costs are influenced directly by the amount of debt that TCPL maintains and the degree to which the Company is affected by fluctuations in interest and foreign exchange rates.

•

Interest Income and Other  Interest income includes interest earned on invested cash balances and income tax refunds. Gains and losses on foreign exchange related to hedges of the Company's U.S.-dollar net income and of working capital are also included in Interest Income and Other.

•

Income Taxes  Income tax recoveries includes income taxes calculated on Corporate's net expenses as well as income tax refunds, reassessments and adjustments that have not been excluded for comparable earnings purposes.

CORPORATE – FINANCIAL RESULTS

Net earnings in Corporate were $10 million in 2007 compared to net earnings of $37 million in 2006 and net expenses of $37 million in 2005.

Corporate's net earnings included favourable income tax reassessments and adjustments of $68 million and $72 million in 2007 and 2006, respectively. Excluding these income tax adjustments, Corporate had comparable expenses of $58 million in 2007, an increase of $23 million from comparable expenses of $35 million in 2006. Gains on derivatives used to manage the Company's exposure to foreign exchange rate fluctuations and the impact of positive tax rate differentials were more than offset by higher financial charges resulting primarily from financing the acquisitions of ANR and additional interest in Great Lakes.

The increase in Corporate's net earnings in 2006 compared with 2005 was due mainly to the $72 million of favourable income tax legislative changes, reassessments and adjustments and the positive impact of the weaker U.S. dollar.

CORPORATE – OUTLOOK

Corporate's net expenses in 2007 included certain favourable income tax reassessments and adjustments that are not expected to recur in 2008. Financing costs associated with debt issued in 2007 and new debt expected to be issued in 2008 to partially finance the Company's capital programs are expected to increase net expenses in Corporate in 2008, which will be partially offset by capitalized interest for projects under construction. Corporate's results could also be affected by debt levels, interest rates, foreign exchange and income tax refunds and adjustments. The performance of the Canadian dollar relative to the U.S. dollar will influence Corporate's results, although this impact is mitigated by offsetting U.S.-dollar exposures in certain of TCPL's other businesses and by the Company's hedging activities.

DISCONTINUED OPERATIONS

TCPL did not have income from discontinued operations in 2007 and 2005. Income from discontinued operations was $28 million in 2006, reflecting bankruptcy settlements with Mirant related to TCPL's Gas Marketing business, which the Company divested in 2001.

LIQUIDITY AND CAPITAL RESOURCES

SUMMARIZED CASH FLOW
Year ended December 31 (millions of dollars)

	2007	2006		2005
Funds generated from operations	2,603	2,374		1,950
Decrease/(increase) in operating working capital	215	(300	)	(48	)
Net cash provided by operations	2,818	2,074		1,902

MANAGEMENT'S DISCUSSION AND ANALYSIS 43

HIGHLIGHTS

Investing Activities

•

Capital expenditures and acquisitions, including assumed debt, totalled approximately $11.0 billion over the three-year period ending December 31, 2007.

Dividend

•

TCPL's Board of Directors declared a dividend for the quarter ending March 31, 2008 in an aggregate amount equal to the quarterly dividend to be paid by TransCanada on its issued and outstanding common shares at the close of business on March 31, 2008. The Board also declared regular dividends on TCPL's preferred shares.

Funds Generated from Operations

Funds Generated from Operations were $2.6 billion in 2007 compared to $2.4 billion and $2.0 billion, in 2006 and 2005, respectively. The increase in 2007 compared to 2006 was mainly a result of higher earnings. The Pipelines business was the primary source of the increase in Funds Generated from Operations in each of the three years. Growth in Energy's operations also caused an increase in Funds Generated from Operations in 2007 compared to the two prior years.
At December 31, 2007, 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 $1,651 million in 2007 compared to $1,572 million in 2006 and $754 million in 2005. Expenditures in 2007 were related primarily to construction of new power plants in Canada, the development of new pipelines, including Keystone, and maintenance and capacity projects in the Pipelines business in Canada and the U.S. Expenditures in 2006 and 2005 were related primarily to construction of new power plants and natural gas storage facilities in Canada and maintenance and capacity projects in the Pipelines business.
TCPL acquired, from El Paso Corporation, 100 per cent of ANR and an additional 3.6 per cent interest in Great Lakes for US$3.4 billion in 2007, subject to certain post-closing adjustments, including approximately US$491 million of assumed long-term debt. The additional interest in Great Lakes increased TCPL's ownership to 53.6 per cent. PipeLines LP acquired, from El Paso Corporation, the remaining 46.4 per cent of Great Lakes for US$942 million, subject to certain post-closing adjustments, including US$209 million of assumed long-term debt.

In December 2007, PipeLines LP purchased, from Sierra Pacific Resources, a one per cent ownership interest in Tuscarora for approximately $2 million. In a separate transaction, PipeLines LP also purchased TCPL's one per cent ownership interest in Tuscarora for approximately $2 million. As a result of these transactions, PipeLines LP owns 100 per cent of Tuscarora. At December 31, 2007, TCPL held a 32.1 per cent interest in PipeLines LP.

In fourth-quarter 2007, the Company's Energy segment sold land in Ontario that had been previously held for development, generating net proceeds of $38 million.

In 2006, PipeLines LP acquired an additional 49 per cent interest in Tuscarora for US$100 million, subject to closing adjustments, in addition to indirectly assuming US$37 million of debt. PipeLines LP also 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. TCPL sold its 17.5 per cent general partner interest in Northern Border Partners, L.P. for proceeds of $35 million, net of current tax.

In 2005, TCPL obtained the remaining rights to full generating capacity under the Sheerness PPA for $585 million, invested $100 million in Bruce A as part of the Bruce Power reorganization, purchased the TC Hydro assets from

44 MANAGEMENT'S DISCUSSION AND ANALYSIS

USGen New England, Inc. 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, and also sold its ownership interest of approximately 11 per cent 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.

Financing Activities

In 2007, TCPL issued Long-Term Debt of $2.6 billion and Junior Subordinated Notes of US$1.0 billion, and its proportionate share of Long-Term Debt issued by joint ventures was $142 million. The Company also reduced its Long-Term Debt by $1.1 billion, its Notes Payable by $412 million and its proportionate share of the Long-Term Debt of Joint Ventures by $157 million.

At December 31, 2007, total unsecured revolving and demand credit facilities of $2.9 billion were available to support the Company's commercial paper program and for general corporate purposes. These credit facilities include the following:

•

in December 2007, the $1.5 billion committed five-year term syndicated credit facility was increased to $2.0 billion and extended to December 2012. The cost to maintain the credit facility was $2 million in 2007 (2006 – $2 million).



•

at December 31, 2007, a US$300 million five-year, extendible revolving facility was available, which is part of the US$1.0 billion TransCanada PipeLine USA Ltd. credit facility discussed below in the section "2007 Long-Term Debt Financing Activities".



•

the Company also has in place $600 million of demand lines, which support the issuance of letters of credit and provide additional liquidity. The Company had used approximately $334 million of its total lines of credit for letters of credit at December 31, 2007. When 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.

Related Party Debt Financings

Related party transactions consist of amounts due to and from TransCanada as well as accrued interest income and expense.

At December 31, 2007, TransCanada had issued discount notes to TCPL for $1.2 billion (2006 – $0.5 billion). The notes bear interest at 4.8 per cent and mature in June 2008.

At December 31, 2007, TransCanada had issued two promissory notes to TCPL totalling $181 million. These notes are non-interest bearing and are payable on demand.

In February 2007, TCPL issued a promissory note to TransCanada for US$700 million bearing interest at LIBOR plus 32.5 basis points to partially finance the acquisitions of ANR and additional interest in Great Lakes. The promissory note was due on or before February 9, 2008. The US$370 that was outstanding at December 31, 2007 was fully repaid on January 7, 2008.

In December 2006, TCPL established a $1 billion, three-year credit facility agreement with TransCanada, bearing interest, at TCPL's option, at the prime rate or Bankers' Acceptance rate plus 65 basis points. The borrowings under this facility can be used to repay indebtedness, make partner contributions to Bruce Power A, or used for working capital and general corporate purposes. In October 2007, the agreement was amended to increase the amount of the credit facility to $2.5 billion. This credit agreement matures on December 15, 2009. At December 31, 2007, $1.3 billion was outstanding on this credit facility (2006 – $550 million).

In May 2003, TCPL established a demand revolving credit facility with TransCanada for general corporate purposes at $500 million, or a US dollar equivalent amount, bearing interest at the prime rate per annum or the US base rate per annum. As at December 31, 2007, $207 million was outstanding on this facility (2006 – $7 million).

In 2007, Financial Charges included $72 million (2006 – $3 million) of interest expense and $30 million (2006 – $1 million) of interest income as a result of these financing arrangements with TransCanada. At December 31, 2007, Accounts Payable included $5 million of interest payable to TransCanada (2006 – nil), net of $2 million of interest receivable from TransCanada.

MANAGEMENT'S DISCUSSION AND ANALYSIS 45

2007 Long-Term Debt Financing Activities

In March 2007, the Company filed debt shelf prospectuses in Canada and the U.S. qualifying for issuance $1.5 billion of Medium-Term Notes and US$1.5 billion of debt securities, respectively. At December 31, 2007, the Company had issued no Medium-Term Notes under the Canadian prospectus and, in September 2007, replaced the March 2007 U.S. debt shelf prospectus with a new US$2.5-billion U.S. debt shelf prospectus. In October 2007, TCPL issued US$1.0 billion of Senior Unsecured Notes under the US$2.5-billion U.S. debt shelf prospectus. These notes mature on October 15, 2037 and bear interest at a rate of 6.20 per cent. US$1.5 billion remains available under the U.S. debt shelf at December 31, 2007.

In July 2007, TCPL exercised its rights to redeem the US$460-million 8.25 per cent Preferred Securities due 2047. The Preferred Securities were redeemed for cash, at par, as part of the settlement on the Canadian Mainline. The foreign exchange gain realized on redemption of the securities will flow through to Canadian Mainline shippers over the five-year period of the settlement.

In April 2007, TCPL issued US$1.0 billion of Junior Subordinated Notes, maturing in 2067 and bearing interest of 6.35 per cent per year until May 15, 2017, when interest will convert to a floating rate, reset quarterly to the three-month London Interbank Offered Rate (LIBOR) plus 221 basis points. The Company has the option to defer payment of interest for periods of up to ten years without giving rise to a default and without permitting acceleration of payment under the terms of the Junior Subordinated Notes. The Company would be prohibited from paying dividends during any deferral period. The Junior Subordinated Notes are subordinated in right of payment to existing and future senior indebtedness and are effectively subordinated to all indebtedness and obligations of TCPL. The Junior Subordinated Notes are callable at the Company's option at any time on or after May 15, 2017 at 100 per cent of the principal amount of the Junior Subordinated Notes plus accrued and unpaid interest to the date of redemption. The Junior Subordinated Notes are callable earlier at the Company's option, in whole or in part, at an amount equal to the greater of 100 per cent of the principal amount of the Junior Subordinated Notes plus accrued and unpaid interest to the date of redemption and an amount determined by formula in accordance with the terms of the Junior Subordinated Notes. The Junior Subordinated Notes were issued under the U.S. shelf prospectus filed in March 2007.

In April 2007, Northern Border increased its five-year bank facility to US$250 million from US$175 million. A portion of the bank facility was drawn to refinance US$150 million of Senior Notes that matured on May 1, 2007, with the balance available to fund Northern Border's ongoing operations.

In March 2007, ANR Pipeline voluntarily withdrew the New York Stock Exchange listing of its 9.625 per cent Debentures due 2021, 7.375 per cent Debentures due 2024, and 7.0 per cent Debentures due 2025. With the delisting, which became effective April 12, 2007, ANR Pipeline deregistered these securities with the SEC.

In February 2007, the Company established a US$1.0 billion committed, unsecured credit facility, consisting of a US$700-million five-year term loan and a US$300-million five-year, extendible revolving facility. 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 and increased ownership in Great Lakes, as well as its additional investment in PipeLines LP. At December 31, 2007, US$860 million remained outstanding on the committed facility and the demand line had been fully repaid.

In February 2007, PipeLines LP increased the size of its syndicated revolving credit and term loan facility in connection with its Great Lakes acquisition. The amount available under the facility increased to US$950 million from US$410 million and consisted of a US$700-million senior term loan and a US$250-million senior revolving credit facility, with US$194 million of the available senior term loan amount being terminated upon closing of the Great Lakes acquisition. At December 31, 2007, US$507 million remained outstanding on the facility.

In January 2008, the Company retired $105 million of 6.0 per cent Medium-Term Notes. In October 2007, the Company retired $150 million of 6.15 per cent Medium-Term Notes. In February 2007, the Company retired $275 million of 6.05 per cent Medium-Term Notes.

46 MANAGEMENT'S DISCUSSION AND ANALYSIS

2006 Long-Term Debt Financing Activities

In 2006, TCPL reduced its Long-Term Debt by $729 million, its Notes Payable by $495 million and its proportionate share of the Long-Term Debt of Joint Ventures by a net amount of $14 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 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, a portion of which was utilized to finance the acquisition of additional interests in Tuscarora. In February 2007, PipeLines LP increased the size of this facility, as discussed above.

2005 Long-Term Debt Financing Activities

In 2005, TCPL reduced its Long-Term Debt by $1,113 million and increased its Notes Payable by $416 million. Financing activities included a net reduction in the Company's proportionate share of Long-Term Debt of Joint Ventures of $42 million. In June 2005, GTNC redeemed all of its outstanding US$150-million 7.8 per cent Senior Unsecured Debentures and US$250-million 7.1 per cent Senior Unsecured Notes. Following an application by GTNC, it 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.

2007 Equity Financing Activities

In 2007, TCPL issued 48.2 million common shares to TransCanada for proceeds of approximately $1.8 billion. Of this total, $1.5 billion was used towards the acquisitions of ANR and additional interest in Great Lakes.

In 2007, TransCanada's Board of Directors authorized the issuance of common shares from treasury at a discount of two per cent to participants in TransCanada's Dividend Reinvestment 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. Commencing with the dividend payable in April 2007, the DRP shares were provided to the participants at a two per cent discount to the average market price in the five days before dividend payment.

In February 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 were acquired by TCPL for US$300 million. TCPL also invested an additional US$12 million to maintain its general partnership ownership interest in PipeLines LP. As a result of these additional investments, TCPL's ownership in PipeLines LP increased to 32.1 per cent on February 22, 2007. The total private placement together with TCPL's additional general partnership investment resulted in gross proceeds to PipeLines LP of US$612 million, which were used to partially finance its acquisition of a 46.4 per cent ownership interest in Great Lakes.

Dividends

Cash dividends on common and preferred shares amounting to $725 million were paid in 2007 compared to cash dividends amounting to $639 million in 2006 and $608 million in 2005.

In January 2008, TCPL's Board of Directors declared a quarterly dividend for the quarter ending March 31, 2008 in an aggregate amount equal to the quarterly dividend to be paid on April 30, 2008 by TransCanada on its issued and outstanding common shares at the close of business on March 31, 2008. The Board also declared regular dividends on TCPL's preferred shares.

Issuer Ratings

TCPL's issuer rating assigned by Moody's Investors Service (Moody's) is A3 with a stable outlook. TCPL's senior unsecured debt is rated A with a stable outlook by DBRS, A2 with a stable outlook by Moody's, and A- with a stable outlook by Standard and Poor's.

MANAGEMENT'S DISCUSSION AND ANALYSIS 47

CONTRACTUAL OBLIGATIONS

Obligations and Commitments

At December 31, 2007, the Company had total long-term debt of $12.9 billion and US$1.0 billion of Junior Subordinated Notes, compared to long-term debt of $11.5 billion at December 31, 2006. TCPL's share of the total debt of joint ventures, including capital lease obligations, was $903 million at December 31, 2007, compared to $1.3 billion at December 31, 2006. Total notes payable, including TCPL's proportionate share of the notes payable of joint ventures, were $55 million at December 31, 2007, compared to $467 million at December 31, 2006. The security provided by each joint venture, except for the capital lease obligation at Bruce Power, is limited to the rights and assets of the joint venture and does not extend to the rights and assets of TCPL, but does extend to the Company's investment. TCPL has provided certain pro-rata guarantees related to the capital lease obligations of Bruce Power and to the performance obligations of Bruce Power and certain other partially owned entities.

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(1)	14,568	577	1,965	2,182	9,844
Capital lease obligations	243	9	23	33	178
Operating leases(2)	1,081	49	91	106	835
Purchase obligations	11,694	3,414	2,657	1,635	3,988
Other long-term liabilities reflected on the balance sheet	372	10	24	29	309
Total contractual obligations	27,958	4,059	4,760	3,985	15,154

⁽¹⁾

Includes Junior Subordinated Notes.

⁽²⁾

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 2021, with an option to renew certain lease agreements for one to ten years. The operating lease agreement for the natural gas storage facility expires in 2030. The lessee has the right to terminate the agreement on anniversary dates five years apart commencing in 2010, and the lessor has the right to terminate the agreement on the same schedule commencing in 2015.

TCPL's commitments under the Alberta PPAs are considered to be operating leases and a portion of these PPAs have been subleased to third parties under similar terms and conditions. Future payments under these PPAs have been excluded from the above table as these payments are dependent upon plant availability, among other things. The amount of power purchased under the PPAs in 2007 was $440 million (2006 – $499 million; 2005 – $230 million).

48 MANAGEMENT'S DISCUSSION AND ANALYSIS

At December 31, 2007, scheduled principal repayments and interest payments related to long-term debt and the Company's proportionate share of the long-term debt of joint ventures were as follow:

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	12,933	556	1,619	2,051	8,707
Junior subordinated notes	975	–	–	–	975
Long-term debt of joint ventures	660	21	346	131	162
Total principal repayments	14,568	577	1,965	2,182	9,844

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	10,978	832	1,511	1,339	7,296
Interest payments on junior subordinated notes	588	63	125	125	275
Interest payments on long-term debt of joint ventures	332	55	85	53	139
Total interest payments	11,898	950	1,721	1,517	7,710

MANAGEMENT'S DISCUSSION AND ANALYSIS 49

At December 31, 2007, the Company's approximate future purchase obligations were as follow:

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)	719	197	283	133	106
Capital expenditures(3),(4)	1,677	1,107	567	3	–
Other	153	55	46	46	6
Energy
Commodity purchases(5)	7,381	1,134	1,278	1,225	3,744
Capital expenditures(3),(6)	1,293	723	354	168	48
Other(7)	377	175	83	42	77
Corporate
Information technology and other	94	23	46	18	7
Total purchase obligations	11,694	3,414	2,657	1,635	3,988

⁽¹⁾

The amounts in this table exclude funding contributions to pension plans and funding to the APG.

⁽²⁾

Rates are based on known 2008 levels. Beyond 2008, 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⁾

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.

⁽⁴⁾

Primarily consists of capital expenditures related to TCPL's share of the construction costs for Keystone and other pipeline projects.

⁽⁵⁾

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.

⁽⁶⁾

Primarily consists of capital expenditures related to TCPL's share of the construction costs for Halton Hills, Portlands Energy and the remaining Cartier Wind projects.

⁽⁷⁾

Includes estimates of certain amounts that are subject to change depending on plant fired hours, the consumer price index, actual plant maintenance costs, plant salaries, and changes in regulated rates for transportation.

TCPL expects to make funding contributions to the Company's pension plans and other benefit plans in the amount of approximately $60 million and $14 million, respectively, in 2008. The expected increase in total pension and post-retirement benefits funding in 2008, from $61 million in 2007, is attributed primarily to a decline in the actual return on plan assets compared to investment performance expectations for 2007 and plan experience being different than expected. TCPL's proportionate share of funding contributions expected to be made by joint ventures to their respective pension plans and other benefit plans in 2008 is approximately $31 million and $3 million, respectively.

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 transacted at market prices and in the normal course of business.

50 MANAGEMENT'S DISCUSSION AND ANALYSIS

Bruce Power

Bruce A has signed commitments to third-party suppliers related to refurbishing and restarting Units 1 and 2 and refurbishing Units 3 and 4 to extend their operating life. TCPL's share of these signed commitments, which extend over the four-year period ending December 31, 2011, are as follow:

Year ended December 31 (millions of dollars)

2008	360
2009	151
2010	69
2011	14
	594

Aboriginal Pipeline Group

On June 18, 2003, the Mackenzie Delta gas producers, the APG and TCPL reached an agreement governing TCPL's role in the MGP project to build a natural gas pipeline from Inuvik, Northwest Territories, to the northern border of Alberta, where it would connect with the Company's Alberta System. Under the agreement, TCPL agreed to finance the APG for its one-third share of project pre-development costs. These costs are currently forecasted to be between $150 million and $200 million, depending on the pace of project development. As at December 31, 2007, the Company had advanced $137 million of this total.

TCPL and the other co-venture companies involved in the MGP continue to pursue approval of the proposed project, focusing on the regulatory process and discussions with the Canadian government on the fiscal framework. Project timing is uncertain and is conditional upon resolution of regulatory and fiscal matters. TCPL's ability to recover its investment depends on the successful outcome of the project.

Contingencies

The Canadian Alliance of Pipeline Landowners' Associations (CAPLA) and two individual landowners commenced an action in 2003 against TCPL and Enbridge Inc. under Ontario's Class Proceedings Act, 1992 for damages of $500 million. The damages are alleged to have arisen from the creation of a control zone within 30 metres of a pipeline pursuant to Section 112 of the National Energy Board Act. In November 2006, TCPL and Enbridge Inc. were granted a dismissal of the case but CAPLA appealed the decision. The Ontario Court of Appeal heard the appeal on December 18, 2007, and reserved its 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.

TCPL and its subsidiaries are subject to various legal proceedings and actions arising in the normal course of business. While the final outcome of such legal proceedings and actions cannot be predicted with certainty, it is the opinion of management that the resolution of such proceedings and actions will not have a material impact on the Company's consolidated financial position or results of operations.

Guarantees

TCPL, Cameco and BPC have each severally guaranteed one-third of certain contingent financial obligations of Bruce B related to power sales agreements, operator licenses, a lease agreement and contractor services. The guarantees have terms ranging from one year ending in 2008 to perpetuity.

TCPL and BPC have each severally guaranteed one-half of certain contingent financial obligations related to an agreement with the OPA to refurbish and restart Bruce A power generation units. The guarantees were part of the reorganization of Bruce Power in 2005 and have terms ending in 2019 to 2036. TCPL's share of the potential exposure under these Bruce Power guarantees was estimated at December 31, 2007, to range from $711 million to a maximum of $750 million. The fair value of these guarantees is estimated to be $12 million.

MANAGEMENT'S DISCUSSION AND ANALYSIS 51

The Company and its partners in certain jointly owned entities have severally and joint and severally guaranteed the performance of these entities related primarily to construction projects, redelivery of natural gas, PPA payments and the payment of liabilities. TCPL's share of the potential exposure under these guarantees was estimated at December 31, 2007 to range from $699 million to a maximum of $1,210 million. For certain of these entities, any payments made by TCPL under these guarantees in excess of its ownership interest are to be reimbursed by its partners. Deferred Amounts includes $7 million for the fair value of these joint and several guarantees.

TCPL has guaranteed a subsidiary's equity undertaking that supports the payment, under certain conditions, of principal and interest on US$75 million of the public debt obligations of TransGas. The Company has a 46.5 per cent interest in TransGas. Under the terms of a shareholder agreement, TCPL and another major multinational company may be required to severally 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 Company's potential exposure is contingent on the impact any change of law would have on the ability of TransGas to service the debt. There has been no change in applicable law since the issuance of debt in 1995 and, thus, no exposure for TCPL. The debt matures in 2010. The Company has made no provision related to this guarantee.

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

FINANCIAL RISKS

Risk Management Overview

TCPL has exposure to market, counterparty credit and liquidity risk. The risk management function assists in managing these risks. TCPL's primary risk management objective is to protect earnings and cash flow, and ultimately shareholder value.

Risk management strategies, policies and limits are designed to ensure TCPL's risks and related exposures are in line with the Company's business objectives and risk tolerance. Risks are managed within limits established by the Company's Board of Directors, implemented by senior management and monitored by risk management personnel. TCPL's Audit Committee oversees how management monitors compliance with risk management policies and procedures, and management's review of the adequacy of the risk management framework. Internal audit personnel assist the Audit Committee in its oversight role by performing regular and ad-hoc reviews of risk management controls and procedures, the results of which are reported to the Audit Committee.

Market Risk

The Company constructs and invests in large infrastructure projects, purchases and sells commodities, issues short- and long-term debt including amounts in foreign currencies, and invests in foreign operations. These activities expose the Company to market risk from changes in commodity prices, foreign exchange rates and interest rates, which affect the Company's earnings and the value of the financial instruments it holds.

The Company uses derivatives as part of its overall risk management policy to manage exposures to market risk that result from these activities.

Contracts used to manage market risk generally consist of the following:

•

Forwards and futures contracts – contractual agreements to purchase or sell a specific financial instrument or commodity at a specified price and date in the future. TCPL enters into foreign exchange and commodity forwards and futures to mitigate the impact of volatility in foreign exchange rates and commodity prices.

•

Swaps – contractual agreements between two parties to exchange streams of payments over time according to specified terms. The Company enters into interest rate, cross-currency and commodity swaps to mitigate the impact of changes in interest rates, foreign exchange rates and commodity prices.

•

Options – contractual agreements to convey the right, but not the obligation, for the purchaser to buy or sell a specific amount of a financial instrument or commodity at a fixed price, either at a fixed date or at any time within a

52 MANAGEMENT'S DISCUSSION AND ANALYSIS

specified period. The Company enters into option agreements to mitigate the impact of changes in interest rates, foreign exchange rates and commodity prices.

•

Heat rate contracts – contracts for the purchase or sale of power that are priced based on a natural gas index.

Commodity Price Risk

The Company is exposed to commodity price movements as part of its normal business operations, particularly in relation to the prices of power and natural gas. A number of strategies are used to mitigate these exposures, including the following:

•

The Company enters into offsetting or back-to-back physical positions and derivative financial instruments to manage market risk exposures created by certain fixed and variable pricing arrangements at different pricing indices and delivery points.



•

Subject to the Company's overall risk management policies, the Company commits a significant portion of its power supply to medium- or long-term sales contracts, while reserving an amount of unsold supply to maintain operational flexibility in the overall management of its asset portfolio.



•

The Company purchases a portion of the natural gas required for its gas-fired cogeneration plants or enters into heat-rate contracts that base the sales price of electricity on the cost of natural gas, effectively locking in a margin. A significant portion of the electricity needed to fulfill the Company's power requirements is purchased with forward contracts or fulfilled through power generation, thereby reducing the Company's exposure to fluctuating commodity prices.

The Company assesses its commodity contracts and derivative instruments used to manage energy commodity risk to determine the appropriate accounting treatment. Contracts, with the exception of leases, have been assessed to determine whether they meet the definition of a derivative. Certain commodity purchase and sale contracts are derivatives but are not within the scope of CICA Handbook Section 3855 "Financial Instruments – Recognition and Measurement", as they were entered into and continue to be held for the purpose of receipt or delivery in accordance with the Company's normal purchases and normal sales exemption. Certain other contracts are not within the scope of Section 3855 as they are considered to meet other exemptions.

TCPL manages its exposure to seasonal natural gas price spreads in its natural gas storage business by hedging storage capacity with a portfolio of third-party storage capacity leases and proprietary natural gas purchases and sales. By matching purchase and sale volumes, TCPL locks in a margin on a back-to-back basis and thereby effectively eliminates its exposure to natural gas market price fluctuations.

Natural Gas Inventory Price Risk

Effective April 1, 2007, TCPL began valuing its proprietary natural gas inventory held in storage at fair value, as measured by the one-month forward price for natural gas. At December 31, 2007, $190 million of proprietary natural gas inventory was included in Inventories. The amount recorded in 2007 in Revenues for the net change in the fair value of proprietary natural gas held in inventory was insignificant. A gain of $10 million was recorded in 2007 in Revenues for the net change in fair value of the forward proprietary natural gas purchase and sales contracts.

Foreign Exchange and Interest Rate Risk

Foreign exchange and interest rate risk is created by fluctuations in the fair values or cash flows of financial instruments due to changes in foreign exchange rates and/or changes in the market interest rates.

A portion of TCPL's earnings from its Pipelines and Energy operations outside of Canada is generated primarily in U.S. dollars and is subject to currency fluctuations. The performance of the Canadian dollar relative to the U.S. dollar could positively or negatively affect TCPL's earnings. This foreign exchange impact is offset by exposures in certain of TCPL's businesses and by the Company's hedging activities. Due to its growing operations in the U.S., including the acquisitions of ANR and additional interests in Great Lakes and PipeLines LP, TCPL expects to have a greater exposure to U.S. dollar fluctuations than in prior years.

MANAGEMENT'S DISCUSSION AND ANALYSIS 53

The Company uses foreign currency and interest rate derivatives to manage the foreign exchange and interest rate risks related to its U.S. dollar-denominated debt and other transactions, as well as to manage the interest rate exposures of the Canadian Mainline, Alberta System and Foothills. Certain of the realized gains and losses on these derivatives are shared with shippers on predetermined terms. These gains and losses are deferred as regulatory assets and liabilities until they are recovered from or paid to the shippers in accordance with the terms of the shipping agreements.

The Company has fixed-rate long-term debt, which subjects it to interest rate price risk, and has floating interest rate debt, which subjects it to interest rate cash flow risk. The Company uses a combination of forwards, interest rate swaps and options to manage its exposure to these risks.

Net Investment in Self-Sustaining Foreign Operations

The Company hedges its net investment in self-sustaining foreign operations on an after-tax basis with U.S. dollar-denominated debt, forward contracts, cross-currency interest rate swaps and options. The Company had designated U.S. dollar-denominated debt with a carrying value of $4.3 billion (US$4.4 billion) and a fair value of $4.4 billion (US$4.5 billion) as a net investment hedge at December 31, 2007. The forwards, swaps and options are recorded at their fair value and are included in Other Assets.

The fair values and notional or principal amount for the derivatives designated as a net investment hedge were as follow:

		2007			2006
Asset/(Liability) December 31 (millions of dollars)		Fair Value(1)		Notional or Principal Amount	Fair Value(1)		Notional or Principal Amount
U.S. dollar cross-currency swaps
	(maturing 2009 to 2014)	77		U.S. 350	58		U.S. 400
U.S. dollar options
	(maturing 2008)	3		U.S. 600	(6	)	U.S. 500
U.S. dollar forward foreign exchange contracts
	(maturing 2008)	(4	)	U.S. 150	(7	)	U.S. 390
		76		U.S. 1,100	45		U.S. 1,290

⁽¹⁾

Other Comprehensive Income in 2007 included unrealized foreign currency translation losses of $350 million (2006 – gains of $6 million; 2005 – losses of $34 million) related to the change in value of investments in foreign operations. Other Comprehensive Income also included unrealized gains of $79 million (2006 – losses of $6 million; 2005 – gains of $15 million) for changes in fair value of hedges of investments in foreign operations.

VaR Analysis

TCPL uses a Value-at-Risk methodology (VaR) to estimate the potential impact resulting from its exposure to market risk. VaR estimates the potential change in pre-tax earnings over a given holding period for a specified confidence level. The VaR number calculated and used by TCPL reflects the 95 per cent probability that the daily change resulting from normal market fluctuations in its liquid positions will not exceed the reported VaR. VaR methodology is a statistically-defined, probability-based approach that takes into consideration market volatilities as well as risk diversification by recognizing offsetting positions and correlations between products and markets. Risks are measured across all products and markets, and risk measures can be aggregated to arrive at a single VaR number.

There is currently no uniform industry methodology for estimating VaR. The use of VaR has limitations because it is based on historical correlations and volatilities in commodity prices, interest rates and foreign exchange rates, and assumes that future price movements will follow a statistical distribution. Although losses are not expected to exceed the statistically estimated VaR on 95 per cent of occasions, losses on the other five per cent of occasions could be substantially greater than the estimated VaR.

54 MANAGEMENT'S DISCUSSION AND ANALYSIS

TCPL's estimation of VaR includes wholly owned subsidiaries, and incorporates relevant risks associated with each market or business unit. The calculation does not include the Pipelines segment as the rate-regulated nature of the pipeline business reduces the impact of market risks and limits TCPL's ability to manage these risks. The Company's Board of Directors has established a VaR limit, which is monitored on an ongoing basis as part of the Company's risk management policy. TCPL's consolidated VaR was less than $10 million at December 31, 2007.

Counterparty Credit Risk

Counterparty credit risk represents the financial loss that the Company would experience if a counterparty to a financial instrument, in which the Company has an amount owing from the counterparty, failed to meet its obligations in accordance with the terms and conditions of its contracts with the Company.

Counterparty credit risk is mitigated through established credit management techniques, including conducting financial and other assessments to establish and monitor a counterparty's creditworthiness, setting exposure limits, monitoring exposures against these limits, utilizing master netting arrangements and obtaining financial assurances where warranted. In general, financial assurances include guarantees, letters of credit and cash. The Company monitors and manages its concentration of counterparty credit risk on an ongoing basis.

TCPL's maximum counterparty credit exposure at the balance sheet date consists primarily of the carrying amount of non-derivative financial assets as well as the fair value of derivative financial assets.

The Company has contracts for the sale of non-financial items. Many of these contracts do not meet the definition of a financial instrument since the underlying volumes are physically delivered during the Company's normal course of business. Exposure to counterparty credit risk on these non-financial contracts results from the potential of a counterparty defaulting on invoiced amounts owing to TCPL. These invoiced amounts are included in the Accounts Receivable and Other Assets amounts disclosed in the Non-Derivative Financial Instruments Summary table presented later in this section. Some of these non-financial contracts do meet the definition of a derivative and are recorded at fair value.

The carrying amounts and fair values of financial assets and non-financial derivatives are disclosed in the Non-Derivative Financial Instruments Summary and the Derivative Financial Instruments Summary tables presented later in this section.

The Company does not have any significant concentrations of counterparty credit risk and the majority of the counterparty credit exposure is with counterparties who are investment grade.

The Company has reached agreements for allowed unsecured claims with certain subsidiaries of Calpine, former shippers on TCPL's pipeline systems that have filed for bankruptcy protection, as discussed in the "Pipelines – Outlook" section of this MD&A.

Liquidity Risk

Liquidity risk is the risk that TCPL will not be able to meet its financial obligations as they fall due. The Company's approach to managing liquidity risk is to ensure that it always has sufficient cash and credit facilities to meet its obligations when due, under both normal and stressed conditions, without incurring unacceptable losses or damage to the Company's reputation.

Management typically forecasts cash flows for a period of 12 months to identify financing requirements. These requirements are then addressed through a combination of committed and demand credit facilities, and through access to capital markets.

MANAGEMENT'S DISCUSSION AND ANALYSIS 55

Fair Values

The fair value of Cash and Cash Equivalents and Notes Payable approximates their carrying amounts due to the short time period to maturity. 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.

Fair values of financial instruments are determined by reference to quoted bid or asking price, as appropriate, in active markets at period-end dates. In the absence of an active market, the Company determines fair value by using valuation techniques that refer to observable market data or estimated market prices. These include comparisons with similar instruments that have observable market prices, option pricing models and other valuation techniques commonly used by market participants. Fair values determined using valuation models require the use of assumptions about the amount and timing of estimated future cash flows and discount rates. In making these assumptions, the Company looks primarily to readily observable external market input factors such as interest rate yield curves, currency rates, and price and rate volatilities as applicable.

The fair value of the Company's Long-Term Debt was estimated based on quoted market prices for the same or similar debt instruments and, when such information was not available, by discounting future payments of interest and principal at estimated interest rates that were made available to the Company at December 31, 2007.

Non-Derivative Financial Instruments Summary

The carrying and fair values of non-derivative financial instruments were as follow:

December 31, 2007 (millions of dollars)	Carrying Amount	Fair Value
Financial Assets(1)
Cash and cash equivalents	504	504
Accounts receivable and other assets(2)(3)	1,231	1,231
Available-for-sale assets(2)	17	17
	1,752	1,752
Financial Liabilities(1)(3)
Notes payable	55	55
Accounts payable and deferred amounts(4)	1,452	1,452
Long-term debt and junior subordinated notes	13,908	15,340
Long-term debt of joint ventures	903	937
Other long-term liabilities of joint ventures(4)	60	60
	16,378	17,838

⁽¹⁾

Consolidated Net Income in 2007 included unrealized gains or losses of nil for the fair value adjustments to each of these financial instruments.

⁽²⁾

The Consolidated Balance Sheet included financial assets of $1,018 million in Accounts Receivable and $230 million in Other Assets at December 31, 2007.

⁽³⁾

Recorded at amortized cost, except for Long-Term Debt of $150 million and US$200 million adjusted to fair value.

⁽⁴⁾

The Consolidated Balance Sheet included financial liabilities of $1,434 million in Accounts Payable and $78 million in Deferred Amounts at December 31, 2007.

56 MANAGEMENT'S DISCUSSION AND ANALYSIS

Derivative Financial Instruments Summary

Information for the Company's derivative financial instruments is as follows.

			2007
December 31 (all amounts in millions unless otherwise indicated)			Power		Natural Gas		Foreign Exchange		Interest
Derivative Financial Instruments Held for Trading
Fair Values(1)
	Assets		$55		$43		$11		$23
	Liabilities		$(44	)	$(19	)	$(79	)	$(18	)
Notional Values
	Volumes(2)
		Purchases	3,774		47		–		–
		Sales	4,469		64		–		–
	Canadian dollars		–		–		–		615
	U.S. dollars		–		–		U.S. 484		U.S. 550
	Japanese yen (in billions)		–		–		JPY 9.7		–
	Cross-currency		–		–		227/U.S. 157		–
Unrealized gains/(losses) in the period(3)			$16		$(10	)	$8		$(5	)
Realized (losses)/gains in the period(3)			$(8	)	$47		$39		$5
Maturity dates			2008 - 2016		2008 - 2010		2008 - 2012		2008 - 2016
Derivative Financial Instruments in Hedging Relationships(4)(5)(6)
Fair Values(1)
	Assets		$135		$19		$ –		$2
	Liabilities		$(104	)	$(7	)	$(62	)	$(16	)
Notional Values
	Volumes(2)
		Purchases	7,362		28		–		–
		Sales	16,367		4		–		–
	Canadian dollars		–		–		–		150
	U.S. dollars		–		–		U.S. 113		U.S. 875
	Cross-currency		–		–		136/U.S. 100		–
Realized (losses)/gains in the period(3)			$(29	)	$18		$ –		$3
Maturity dates			2008 - 2013		2008 - 2010		2008 - 2013		2008 - 2013

⁽¹⁾

Fair value is equal to the carrying value of these derivatives.

⁽²⁾

Volumes for power and natural gas derivatives are in gigawatt hours and billion cubic feet, respectively.

⁽³⁾

All realized and unrealized gains and losses are included in Net Income. Realized gains are included in Net Income after the financial instrument has been settled.

⁽⁴⁾

All hedging relationships are designated as cash flow hedges except for $2 million of interest-rate derivative financial instruments designated as fair value hedges.

⁽⁵⁾

Net Income in 2007 included gains of $7 million for the changes in fair value of power and natural gas cash flow hedges that were ineffective in offsetting the change in fair value of their related underlying positions. Net Income in 2007 included a loss of $4 million for the changes in fair value of an interest-rate cash flow hedge that was reclassified as a result of discontinuance of cash flow hedge accounting. The cash flow hedge accounting was discontinued when the anticipated transaction was not probable of occurring by the end of the originally specified time period.

⁽⁶⁾

Other Comprehensive Income in 2007 included unrealized gains of $42 million for the change in fair value of cash flow hedges.

MANAGEMENT'S DISCUSSION AND ANALYSIS 57

Balance Sheet Presentation of Derivative Financial Instruments

The fair values of the derivative financial instruments in the Company's Balance Sheet were as follow:

December 31 (millions of dollars)		2007
Current
	Other Current Assets	160
	Accounts Payable	(144	)
Long-term
	Other Assets	204
	Deferred Amounts	(205	)

OTHER RISKS

Development Projects and Acquisitions

TCPL continues to focus on growing its Pipelines and Energy operations through greenfield projects and acquisitions. TCPL capitalizes costs incurred on certain of its greenfield development projects during the period prior to construction when the project meets specific criteria and is expected to proceed through to completion. The related capital costs of a project that does not proceed through to completion would be expensed at the time it is discontinued. There is a risk with respect to TCPL's acquisition of existing assets and operations that certain commercial opportunities and operational synergies may not materialize as expected.

Health, Safety and Environment Risk Management

TCPL is committed to providing a safe and healthy environment for its employees, contractors and the public, and to protecting the environment. Health, safety and environment (HS&E) is a priority in all of TCPL's operations and the Company is committed to ensuring it is in conformance with its internal policies and regulated requirements, and is an industry leader. The HS&E Committee of TCPL's Board of Directors monitors conformance with TCPL's HS&E corporate policy through regular reporting. TCPL's HS&E management system is modeled to the elements of the International Organization of Standardization (ISO) standard for environmental management systems, ISO 14001, and focuses resources on the areas of significant risk to the organization's HS&E business activities. Management is regularly advised of all important HS&E operational issues and initiatives 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 requested by the HS&E Committee. The most recent assessment was conducted in November 2006. These assessments involve senior management and employee interviews, review of policies, procedures, objectives, performance measurement and reporting.

Health and Safety

In 2007, employee and contractor health and safety performance continued to improve relative to previous years and benchmarked within the top level of industry peers. The Company's assets were highly reliable in 2007 and there were no incidents that were material to the Company's operations.

Under the approved regulatory models in Canada, pipeline integrity expenditures on NEB- and AUC-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 $120 million in 2008 for pipeline integrity on its wholly owned pipelines, which is slightly higher than the amount spent in 2007, reflecting the acquisition of ANR and slightly increased spending in Canada. Spending associated with public safety on the Energy assets is focused primarily on hydro dams and associated equipment, and is consistent with previous years.

58 MANAGEMENT'S DISCUSSION AND ANALYSIS

Environment

TCPL's operations are subject to various environmental laws and regulations that establish compliance and remediation obligations. There are no outstanding orders, material claims or lawsuits against the Company in relation to the release or discharge of any material into the environment or in connection with environmental protection. The Company believes that it has established appropriate reserves, where required, for environmental liabilities.

Environmental risks from TCPL's facilities typically include air emissions such as nitrogen oxides (NOx), particulate matter and greenhouse gases, potential land impacts, including land reclamation following construction, releases, chemical and hydrocarbon storage, and waste management control to minimize hazardous wastes, and water impacts such as water discharge. TCPL utilizes a risk-based environmental assessment approach. All businesses are assessed annually and specific facilities, installations and activities are reviewed on a one- to three-year cycle, depending on the Company's assessment of risk. Business and/or facility inspections are completed on a monthly, quarterly or annual basis, depending on the entity and the assessment of risk. There were no materially significant environmental matters arising from these assessments conducted during 2007.

Climate change policy continues to evolve at regional, national and international levels. Under the Specified Gas Emitters Regulation, as of July 1, 2007, industrial facilities in Alberta are required to reduce their greenhouse gas emissions intensities by 12 per cent. TCPL's Alberta-based facilities are subject to this regulation, which also extends to the Sundance and Sheerness facilities with which the Company has PPAs. Plans have been developed to manage the costs of compliance incurred by these assets. The regulation is not expected to have a material impact on the Company's results. Compliance costs related to the Alberta System are expected to be recovered through tolls paid by customers. Recovery of compliance costs related to the Company's power generation facilities in Alberta is dependent ultimately on market prices for electricity. The Company recorded a charge of $14 million for the period from July 1, 2007 to December 31, 2007 related to the new Alberta environmental regulation.

A hydrocarbon royalty tax took effect in Québec on October 1, 2007 and is expected to affect mainly the Bécancour power generation facility. A regulatory proceeding is under way to determine the method of collecting the tax. The Company recorded a charge of $2 million for the period October 1, 2007 to December 31, 2007 for Québec royalties.

British Columbia recently announced a carbon tax, with an effective date of July 2008, which is expected to be applied to fuel usage at the Company's pipeline compressor facilities in that province. The specifics of the application of the tax are still being assessed. Compliance costs related to this tax are anticipated to be recovered through tolls paid by customers.

The Government of Canada released in April 2007 the Regulatory Framework for Air Emissions (Framework). The Framework outlines short-, medium- and long-term objectives for managing both greenhouse gas emissions and air pollutants in Canada. The Company expects a number of its facilities will be affected by pending Federal climate change regulations that will be put in place to meet the Framework's objectives. It is unknown at this time whether the impacts from the pending regulations will be material as the final form of compliance options is still evolving.

Climate change legislation is evolving at both the federal and state levels in the U.S. The Company expects a number of its facilities could be affected by these legislative initiatives, but timing and specific policy objectives remain uncertain.

The Company continues to be involved in discussions with governments in jurisdictions where TCPL has operations and where climate change policy is under development. TCPL is also continuing its programs to manage greenhouse gas emissions from its facilities and to evaluate new processes and technologies that result in improved efficiencies and lower greenhouse gas emission rates. The Company also incorporates compliance costs associated with environmental regulations as part of its normal assessment of existing operations and new growth opportunities.

MANAGEMENT'S DISCUSSION AND ANALYSIS 59

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 at December 31, 2007, 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 SEC. Based on this evaluation, the President and Chief Executive Officer and the Chief Financial Officer concluded that the design and operation of TCPL's disclosure controls and procedures were effective as at December 31, 2007.

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 and with the participation of the President and Chief Executive Officer and the 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. In 2007, the Company acquired ANR and began consolidating the operations of ANR into the Company. Management excluded this business from its evaluation of the effectiveness of the Company's internal control over financial reporting as at December 31, 2007. The net income attributable to this business represented approximately nine per cent of the Company's consolidated net income in 2007, and its aggregate total assets represented approximately 12 per cent of the Company's consolidated total assets as at December 31, 2007.

Based on this evaluation, management concluded that internal control over financial reporting is effective as at December 31, 2007, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes.

In 2007, there was no change in TCPL's internal control over financial reporting that materially affected or is reasonably likely to materially affect TCPL's internal control over financial reporting.

CEO and CFO Certifications

TCPL's President and Chief Executive Officer has provided the New York Stock Exchange with the annual CEO certification for 2007 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 2007 reports filed with the SEC and the Canadian securities regulators.

60 MANAGEMENT'S DISCUSSION AND ANALYSIS

SIGNIFICANT ACCOUNTING POLICIES AND CRITICAL ACCOUNTING ESTIMATES

To prepare financial statements that conform with Canadian GAAP, TCPL is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses. The Company uses the most current information available and exercises careful judgment in making these estimates and assumptions.

Regulated Accounting

The Company accounts for the impacts of rate regulation in accordance with GAAP. 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 with respect to each of the regulated natural gas pipelines accounted for using regulated accounting principles. 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.

Financial Instruments

Effective January 1, 2007, the Company adopted the new Canadian Institute of Chartered Accountants (CICA) Handbook accounting requirements for Section 3855 "Financial Instruments – Recognition and Measurement" and Section 3865 "Hedges". The CICA Handbook requirements for Section 3862 "Financial Instruments – Disclosure" and Section 3863 "Financial Instruments – Presentation" are effective January 1, 2008, however the Company chose to adopt these standards effective December 31, 2007.

These standards are described further in the "Risk Management and Financial Instruments" and "Accounting Changes" sections of this MD&A.

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 ranging from two per cent to six per cent. Metering and other plant equipment are depreciated at various rates. Major power generation and natural gas storage plant, equipment and structures in the Energy business are depreciated on a straight-line basis over estimated service lives at average annual rates ranging from two per cent to ten per cent. Nuclear power generation assets under capital lease are amortized on a straight-line basis over the shorter of their useful life and the remaining terms of their lease. Other equipment is depreciated at various rates. Corporate plant, property and equipment are depreciated on a straight-line basis over estimated useful lives at average annual rates ranging from three to 20 per cent.

Depreciation expense in 2007 was $1,179 million (2006 – $1,059 million) and primarily affects the Pipelines and Energy segments of the Company. In Pipelines, depreciation rates are approved by regulators where applicable and depreciation expense is recoverable based on the cost of providing the services or products. If regulators permit recovery through rates, a change in the estimate of the useful lives of plant, property and equipment in the Pipelines segment would have no material impact on TCPL's net income but would directly affect funds generated from operations.

ACCOUNTING CHANGES

Changes in Accounting Policies for 2007

Effective January 1, 2007, the Company adopted the CICA Handbook accounting requirements for Sections 1506 "Accounting Changes", 1530 "Comprehensive Income", 3251 "Equity", 3855 "Financial Instruments – Recognition and Measurement", and 3865 "Hedges". In addition, the Company chose to adopt the accounting requirements for

MANAGEMENT'S DISCUSSION AND ANALYSIS 61

Sections 3862 "Financial Instruments – Disclosure", 3863 "Financial Instruments – Presentation" and 1535 "Capital Disclosures" at December 31, 2007, as well as the accounting requirements for Section 3031 "Inventories" at April 1, 2007. Adjustments to the consolidated financial statements for 2007 have been made in accordance with the transitional provisions for these new standards.

Comprehensive Income and Equity

The Company's financial statements include statements of Consolidated Comprehensive Income and Consolidated Accumulated Other Comprehensive Income. In addition, as required in CICA Handbook Section 3251, the Company now presents separately, in the Consolidated Shareholder's Equity statement, the changes for each of its components of Shareholder's Equity, including Accumulated Other Comprehensive Income.

Financial Instruments

All financial instruments must initially be included on the balance sheet at their fair value. Subsequent measurement of the financial instruments is based on their classification. Financial assets are classified into the following categories: held for trading, available for sale, held-to-maturity investments and loans and receivables. Financial liabilities are classified as held for trading or other financial liabilities.

Held-for-trading financial assets and liabilities consist of swaps, options, forwards and futures, and are entered into with the intention of generating a profit. A financial asset or liability that does not meet this criterion may also be designated as held for trading. Power and natural gas held-for-trading instruments are initially recorded at their fair value and changes to fair value are included in Revenues. Changes in the fair value of interest rate and foreign exchange held-for-trading instruments are recorded in Financial Charges and in Interest Income and Other, respectively. The Company had not designated any financial assets or liabilities as held for trading at December 31, 2007.

The available-for-sale classification includes non-derivative financial assets that are designated as available for sale or are not included in the other three classifications. TCPL's available-for-sale financial instruments include fixed-income securities held for self-insurance. These instruments are initially accounted for at their fair value and changes to fair value are recorded through Other Comprehensive Income. Income from the settlement of available-for-sale financial assets will be included in Interest Income and Other.

Held-to-maturity financial assets are accounted for at their amortized cost using the effective interest method. The Company did not have any held-to-maturity financial assets at December 31, 2007.

Trade receivables, loans and other receivables with fixed or determinable payments that are not quoted in an active market are classified as "loans and receivables" and are measured net of any impairment. Loans and receivables include primarily trade accounts receivable and non-interest-bearing third-party loans receivable. Interest and other income earned from these financial assets are recorded in Interest Income and Other.

Other financial liabilities consist of liabilities not classified as held for trading. Interest expense is included in Financial Charges and in Financial Charges of Joint Ventures. Items in this financial instrument category are recognized at amortized cost using the effective interest method.

All derivatives are recorded on the balance sheet at fair value, with the exception of those that were entered into and continue to be held for the purpose of receipt or delivery in accordance with the Company's expected purchase, sale or usage requirements (normal purchase and normal sale exemption). Changes in the fair value of derivatives that are not designated in a hedging relationship are recorded in Net Income. Derivatives used in hedging relationships are discussed further under the heading Hedges in this section.

Derivatives embedded in other financial instruments or contracts (the host instrument) are recorded as separate derivatives and are measured at fair value if the economic characteristics of the embedded derivative are not closely related to the host instrument, the terms of the embedded derivative are the same as those of a stand-alone derivative

62 MANAGEMENT'S DISCUSSION AND ANALYSIS

and the total contract is not held for trading or accounted for at fair value. Changes in the fair value of embedded derivates that are recorded separately are included in Revenues. The Company used January 1, 2003 as the transition date for embedded derivatives.

Transaction costs are incremental costs that are directly attributable to the acquisition, issue or disposal of a financial instrument. Effective January 1, 2007, the Company began offsetting long-term debt transaction costs against the associated debt and began amortizing these costs using the effective interest method. Previously, these costs were amortized on a straight-line basis over the life of the debt. There was no material impact on the Company's financial statements as a result of this change in policy. In 2007, the impact on Net Income for the amortization of transaction costs using the effective interest method was nominal.

The Company records the fair values of material joint and several guarantees. These fair values cannot be readily obtained from an open market and therefore, the fair value of these guarantees is estimated by discounting the cash flows that would be incurred by the Company if letters of credit were used in place of the guarantees. Guarantees are recorded as an increase to an investment account, Property, Plant and Equipment or a charge to Net Income, and a corresponding liability in Deferred Amounts.

Hedges

Section 3865 specifies the criteria that must be satisfied in order to apply hedge accounting and the accounting for each of the permitted hedging strategies, including: fair value hedges, cash flow hedges and hedges of foreign currency exposures of net investments in self-sustaining foreign operations. Hedge accounting is discontinued prospectively when the derivative no longer qualifies as an effective hedge or is terminated or sold, or upon the sale or early termination of the hedged item.

Documentation must be prepared at the inception of the hedging arrangement in order to qualify for hedge accounting treatment. In addition, the Company must perform an assessment of effectiveness at inception of the contract and at each reporting date.

In a fair value hedging relationship, the carrying value of the hedged item is adjusted for changes in fair value attributable to the hedged risk. The changes in fair value are recognized in Net Income. Changes in the fair value of the hedged item, to the extent that the hedging relationship is effective, are offset by changes in the fair value of the hedging item, which is also recorded in Net Income. Changes in the fair value of foreign exchange and interest rate hedges are recorded in Interest Income and Other and Financial Charges, respectively. When hedge accounting is discontinued, the carrying value of the hedged item is no longer adjusted and the cumulative fair value adjustments to the carrying value of the hedged item are amortized to Net Income over the remaining term of the original hedging relationship.

In a cash flow hedging relationship, the effective portion of the change in the fair value of the hedging derivative is recognized in Other Comprehensive Income, while any ineffective portion is recognized in Net Income in the same financial category as the underlying transaction. When hedge accounting is discontinued, the amounts recognized previously in Accumulated Other Comprehensive Income are reclassified to Net Income during the periods when the variability in cash flows of the hedged item affects Net Income. Gains and losses on derivatives are reclassified immediately to Net Income when the hedged item is sold or terminated early, or when a hedged anticipated transaction is no longer expected to occur.

The Company also enters into cash flow hedges and fair value hedges for activities subject to rate regulation. The gains and losses arising from the changes in fair value of these hedges can be recovered through the tolls charged by the Company. As a result, these gains and losses are deferred as rate-regulated assets or liabilities on behalf of the ratepayers. When the hedges are settled, the realized gains or losses are collected from or refunded to the ratepayers in subsequent years.

MANAGEMENT'S DISCUSSION AND ANALYSIS 63

In hedging the foreign currency exposure of a net investment in a self-sustaining foreign operation, the effective portion of foreign exchange gains and losses on the hedging instruments is recognized in Other Comprehensive Income and the ineffective portion is recognized in Net Income. The amounts recognized previously in Accumulated Other Comprehensive Income are recognized in Net Income in the event the Company settles or otherwise reduces its investment.

Net Effect of Accounting Policy Changes

The net effect of the preceding accounting policy changes on the Company's financial statements at January 1, 2007 was as follows:

Increases/(decreases) (millions of dollars)
Other current assets	(127	)
Other assets	(203	)
Accounts payable	(29	)
Deferred amounts	(75	)
Future income taxes	(42	)
Long-term debt	(85	)
Long-term debt of joint ventures	(7	)
Accumulated other comprehensive income	(96	)
Retained earnings	4

The primary changes in 2007 to the Company's accounting policies for financial instruments related to the requirements to record certain non-financial contracts at their fair value and to offset transaction costs against long-term debt.

Section 3862 Financial Instruments – Disclosures and Section 3863 Financial Instruments – Presentation

CICA Handbook Sections 3862 "Financial Instruments – Disclosure" and 3863 "Financial Instruments – Presentation", which replaced Section 3861 "Financial Instruments – Disclosure and Presentation", are effective January 1, 2008. However, the Company chose to adopt these standards effective December 31, 2007. The Company's December 31, 2007 financial statements provided the additional disclosure necessary to comply with these standards.

Section 1535 Capital Disclosures

CICA Handbook Section 1535 "Capital Disclosures" is effective for fiscal years beginning on or after October 1, 2007, however, TCPL chose to adopt this standard effective December 31, 2007. The Company has provided qualitative disclosure regarding objectives, policies and processes for managing capital as well as quantitative data of capital as of December 31, 2007 in the "Risk Management and Financial Instruments" section of this MD&A.

Proprietary Natural Gas Inventories and Revenue Recognition

CICA Handbook Section 3031 "Inventories" is effective January 1, 2008. However, the Company chose to adopt this standard effective April 1, 2007, and began valuing its proprietary natural gas inventory held in storage at fair value, as measured by the one-month forward price for natural gas. To record inventory at fair value, TCPL has designated its natural gas storage business as a broker/trader business that purchases and sells natural gas on a back-to-back basis. TCPL did not have any proprietary natural gas inventory prior to April 1, 2007. The Company records its proprietary natural gas storage results in Revenues net of Commodity Purchases Resold. All changes in the fair value of the proprietary natural gas inventories are reflected in Inventories and Revenues.

64 MANAGEMENT'S DISCUSSION AND ANALYSIS

Future Accounting Changes

Rate-Regulated Operations

Effective January 1, 2009, the temporary exemption from CICA Handbook Section 1100, "Generally Accepted Accounting Principles", which permits the recognition and measurement of assets and liabilities arising from rate regulation, will be withdrawn. In addition, Section 3465 "Income Taxes" was amended to require the recognition of future income tax liabilities and assets. As a result of the changes, TCPL will be required to recognize future income tax liabilities and assets instead of using the taxes payable method, and will record an offsetting adjustment to regulatory assets and liabilities. If the liability method of accounting had been used at December 31, 2007, additional future income tax liabilities in the amount of $1,138 million would have been recorded and would have been recoverable from future revenue. These changes will be applied prospectively beginning January 1, 2009.

International Financial Reporting Standards

The CICA's Accounting Standards Board (AcSB) announced that Canadian publicly accountable enterprises will adopt International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB) effective January 1, 2011. IFRS will require increased financial statement disclosure. Although IFRS uses a conceptual framework similar to Canadian GAAP, differences in accounting policies will need to be addressed. TCPL is currently assessing the impact of this AcSB announcement on its financial statements.

Intangible Assets

The CICA Handbook implemented revisions to standards dealing with Intangible Assets effective for fiscal years beginning on or after October 1, 2008. The revisions are intended to align the definition of an Intangible Asset in Canadian GAAP with that in IFRS and U.S. GAAP. Section 1000 "Financial Statement Concepts" was revised to remove material that permitted the recognition of assets that might not otherwise meet the definition of an asset and to add guidance from the IASB's "Framework for the Preparation and Presentation of Financial Statements" that will help distinguish assets from expenses. Section 3064 "Goodwill and Intangible Assets", which replaced Section 3062 "Goodwill and Other Intangible Assets", gives guidance on the recognition of intangible assets as well as the recognition and measurement of internally developed intangible assets. Section 3450 "Research and Development Costs" will be withdrawn from the Handbook. The Company does not expect these changes to have a material effect on its financial statements.

MANAGEMENT'S DISCUSSION AND ANALYSIS 65

SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA⁽¹⁾

		2007
(millions of dollars except per share amounts)		Fourth	Third	Second	First
Revenues		2,189	2,187	2,208	2,244
Net Income Applicable to Common Shares
	Continuing operations	373	320	254	263
	Discontinued operations	–	–	–	–
		373	320	254	263
Share Statistics
Net income per share – Basic and Diluted
	Continuing operations	$0.69	$0.60	$0.49	$0.50
	Discontinued operations	–	–	–	–
		$0.69	$0.60	$0.49	$0.50

		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
Share Statistics
Net income per share – 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

⁽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.

Factors Impacting Quarterly Financial Information

In Pipelines, which consists primarily of the Company's investments in regulated pipelines and regulated natural gas storage facilities, 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 resulting from adjustments being recorded due to regulatory decisions and negotiated settlements with shippers, seasonal fluctuations in short-term throughput volumes on U.S. pipelines, acquisitions and divestitures, and developments outside of the normal course of operations.

In Energy, which consists primarily of the Company's investments in electrical power generation plants and non-regulated 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, acquisitions and divestitures, and developments outside of the normal course of operations.

66 MANAGEMENT'S DISCUSSION AND ANALYSIS

Significant developments that affected quarterly net earnings in 2007 and 2006 were as follow:

•

First-quarter 2006 net earnings included proceeds of $18-million after tax ($29-million pre-tax) from a bankruptcy settlement with a former shipper on the GTN System.



•

Second-quarter 2006 net earnings included $33 million of future income tax benefits as a result of reductions in Canadian federal and provincial corporate income tax rates. Net earnings also included a $13-million after-tax gain related to the sale of the Company's interest in Northern Border Partners, L.P.



•

Third-quarter 2006 net earnings included an income tax benefit of approximately $50 million as a result of the resolution of certain income tax matters with taxation authorities and changes in estimates.



•

Fourth-quarter 2006 net earnings included approximately $12 million related to income tax refunds and related interest.



•

First-quarter 2007 net earnings included $15 million related to positive income tax adjustments. In addition, Pipelines' net earnings included contributions from the February 22, 2007, acquisition of ANR and an additional ownership interest in Great Lakes. Energy's net earnings included earnings from the Edson natural gas facility, which was placed in service on December 31, 2006.



•

Second-quarter 2007 net earnings included $16 million ($4 million in Energy and $12 million in Corporate) related to positive income tax adjustments resulting from reductions in Canadian federal income tax rates. Pipeline's net earnings increased as a result of a settlement reached on the Canadian Mainline, which was approved by the NEB in May 2007.



•

Third-quarter 2007 net earnings included $15 million of favourable income tax reassessments and associated interest income relating to prior years.



•

Fourth-quarter 2007 net earnings included $56 million ($30 million in Energy and $26 million in Corporate) of favourable income tax adjustments resulting from reductions in Canadian federal income tax rates and other legislative changes, and a $14-million ($16 million pre-tax) gain on sale of land previously held for development. Pipelines' net earnings increased as a result of recording incremental earnings related to the rate case settlement reached for the GTN System, effective January 1, 2007.

MANAGEMENT'S DISCUSSION AND ANALYSIS 67

FOURTH-QUARTER 2007 HIGHLIGHTS

CONSOLIDATED RESULTS OF OPERATIONS
Reconciliation of Comparable Earnings to Net Income
Applicable to Common Shares

(millions of dollars)			2007		2006
Pipelines Net Earnings			202		126
Energy Net Earnings
	Comparable earnings(1)		114		132
	Specific items:
		Income tax reassessments and adjustments	30		–
		Gain on sale of land	14		–
	Net earnings		158		132
Corporate Net Earnings
	Comparable earnings(1)		(13	)	(2	)
	Specific item:
		Income tax reassessments and adjustments	26		12
	Net earnings		13		10
Net Income Applicable to Common Shares			373		268
Comparable Earnings(1)			303		256
	Specific items (net of tax, where applicable):
		Income tax reassessments and adjustments	56		12
		Gain on sale of land	14		–
	Net Income Applicable to Common Shares		373		268

⁽¹⁾

Refer to the "Non-GAAP Measures" section of this MD&A for further discussion of comparable earnings.

TCPL's net income applicable to common shares and net earnings in fourth-quarter 2007 were $373 million compared to $268 million in fourth-quarter 2006, an increase of $105 million. The increase reflected the impact of favourable income tax adjustments of $56 million in fourth-quarter 2007 as a result of changes in Canadian federal income tax legislation compared to income tax refunds and related interest of $12 million in fourth-quarter 2006. The increase was also due to additional earnings from the acquisition of ANR in February 2007 and the start-up of the Edson facility in December 2006, the positive impact of the rate case settlements on both the GTN System and the Canadian Mainline, a $14-million after-tax ($16 million pre-tax) gain on the sale of land and lower operating costs on the Alberta System. Lower realized power prices in Alberta and a lower contribution from Bruce Power partially offset these increases to net earnings in fourth-quarter 2007 compared to fourth-quarter 2006.

Comparable earnings in fourth-quarter 2007 were $303 million, compared to $256 million in the same period in 2006. Comparable earnings excluded the $56-million and $12-million positive income tax adjustments in fourth-quarter 2007 and fourth-quarter 2006, respectively, as well as the $14-million gain on sale of land in fourth-quarter 2007.

In Pipelines, net earnings were $202 million in fourth-quarter 2007, an increase of $76 million from $126 million in the same period in 2006. Additional income from the acquisition of ANR, the positive impact of the rate case settlements on both the Canadian Mainline and the GTN System, and lower operating costs on the Alberta System contributed to higher earnings.

68 MANAGEMENT'S DISCUSSION AND ANALYSIS

Canadian Mainline's net earnings in fourth-quarter 2007 were $72 million, an increase of $12 million from the corresponding period in 2006. The increase reflected the impact of the five-year rate case settlement on the Canadian Mainline, effective January 1, 2007 to December 31, 2011. Canadian Mainline's net earnings increased due to certain performance-based incentive arrangements and OM&A cost savings in addition to the positive impact of the increase in deemed common equity ratio in the settlement. Partially offsetting these increases were the negative impacts of a lower allowed ROE of 8.46 per cent in 2007 (2006 – 8.88 per cent) and a lower average investment base.

Alberta System's net earnings in fourth-quarter 2007 were $41 million, an increase of $7 million from the same quarter of 2006. The increase was due mainly to OM&A cost savings, partially offset by a lower investment base as well as a lower allowed ROE in 2007. Earnings in 2007 reflected an ROE of 8.51 per cent compared to 8.93 per cent in 2006, both on deemed common equity of 35 per cent.

GTN's comparable earnings in fourth-quarter 2007 were $32 million, an increase of $25 million from the same period in 2006 due primarily to the positive impact of the rate case settlement. GTN recorded the full-year impact of the rate case settlement in fourth-quarter 2007 upon receipt of FERC approval in January 2008. The positive impact of the rate case settlement on net earnings was partially offset by the impacts of lower long-term firm contracted volumes and a weaker U.S. dollar in 2007 as well as a higher provision taken in 2007 for non-payment of contract revenues from a subsidiary of Calpine that filed for bankruptcy protection.

In Energy, fourth-quarter 2007 net earnings were $158 million, an increase of $26 million from $132 million in the same period in 2006. Net earnings in fourth-quarter 2007 included $30 million of positive income tax reassessments and adjustments, a $14-million after-tax ($16 million pre-tax) gain on sale of land, higher prices and volumes at Bruce B, and revenue from the Edson facility, which commenced operation in December 2006. These gains were partially offset by lower overall realized power prices in Western Power as well as lower volumes and increased outage days and related costs at Bruce A.

Western Power's operating income in fourth-quarter 2007 was $58 million, a decrease of $51 million from fourth-quarter 2006. This decrease was due primarily to lower overall realized power prices and lower market heat rates on higher uncontracted volumes of power sold, partially offset by lower PPA costs. Average spot market power prices in Alberta decreased 47 per cent, or $55 per MWh, in fourth-quarter 2007 compared to fourth-quarter 2006. The power price decrease was also the main contributor to a decrease of approximately 43 per cent in market heat rates, partially offset by an 11 per cent, or $0.73 per GJ, decrease in average spot market natural gas prices in Alberta in fourth-quarter 2007 compared to the same quarter in 2006.

Eastern Power's operating income in fourth-quarter 2007 was $66 million, an increase of $11 million from the same period in 2006. The increase was due primarily to payments received under the newly-designed FCM in New England and increased earnings from higher sales volumes to commercial and industrial customers. These positive impacts were partially offset by decreased power generation from the TC Hydro facilities compared with fourth-quarter 2006 when water flows were above normal.

Operating income from Bruce Power in fourth-quarter 2007 was $43 million, a decrease of $16 million from fourth-quarter 2006. The decrease was due to lower power generation volumes and higher operating costs related to the significant increase in planned outage days at Bruce A as well as higher post-employment benefit costs and lower positive purchase price amortizations related to the expiry of power sales agreements. These negative impacts were partially offset by higher realized prices, higher power generation volumes and lower operating costs as a result of fewer planned outage days at Bruce B.

Natural Gas Storage operating income in fourth-quarter 2007 was $57 million, an increase of $27 million from fourth-quarter 2006 due primarily to income earned from the Edson facility, which commenced operation in December 2006. Operating income in fourth-quarter 2007 included a $15-million net unrealized gain from the changes in fair value of proprietary natural gas inventory, forward purchase contracts and forward sale contracts.

MANAGEMENT'S DISCUSSION AND ANALYSIS 69

Corporate net earnings in fourth-quarter 2007 were $13 million compared to $10 million in the same period in 2006. The increase was due primarily to $26 million of favourable income tax adjustments arising from legislated Canadian corporate income tax changes in fourth-quarter 2007, compared to $12 million in income tax refunds and related interest in the same period in 2006. Gains on derivatives used to manage the Company's exposure to foreign exchange rate fluctuations and the impact of positive tax rate differentials also contributed to higher net earnings. However, these gains were more than offset by higher financial charges, resulting primarily from financing the acquisitions of ANR and additional interest in Great Lakes. Corporate's comparable expenses were $13 million in fourth-quarter 2007 compared with $2 million in the same period in 2006, excluding the favourable income tax adjustments in the two periods.

SHARE INFORMATION

At February 25, 2008, TCPL had 533.0 million 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 2000 to 2007 is found under the heading "Eight-Year Financial Highlights" in the Supplementary Information section of the Company's Annual Report.

70 MANAGEMENT'S DISCUSSION AND ANALYSIS

GLOSSARY OF TERMS

AGIA	Alaska Gasline Inducement Act
ANR	American Natural Resources Company and ANR Storage Company, collectively
ANR Pipeline	ANR Pipeline Company
APG	Aboriginal Pipeline Group
AUC	Alberta Utilities Commission
B.C.	British Columbia
Bbl/d	Barrels per day
Bcf	Billion cubic feet
Bcf/d	Billion cubic feet per day
BPC	BPC Generation Infrastructure Trust
Broadwater	Broadwater LNG project
Bruce A	Bruce Power A L.P.
Bruce B	Bruce Power L.P.
Bruce Power	Bruce A and Bruce B collectively
Cacouna	Cacouna LNG project
Calpine	Calpine Corporation
Cameco	Cameco Corporation
CAPLA	Canadian Alliance of Pipeline Landowners' Associations
CPUC	California Public Utilities Commision
CrossAlta	CrossAlta Gas Storage & Services Ltd.
DRP	Dividend Reinvestment and Share Purchase Plan
EPCOR	EPCOR Utilities Inc.
EUB	Alberta Energy and Utilities Board
FCM	Forward Capacity Market
FEIS	Final Environmental Impact Statement
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
GTN	GTN System and North Baja, collectively
GTNC	Gas Transmission Northwest Corporation
GWh	Gigawatt hours
Halton Hills	Halton Hills Generating Station
INNERGY	INNERGY Holdings S.A.
Iroquois	Iroquois Gas Transmission System, L.P.
Keystone	Keystone Canada and Keystone U.S. collectively
Keystone Canada	TransCanada Keystone Pipeline Limited Partnership
Keystone U.S.	TransCanada Keystone Pipeline LP
km	Kilometres
LIBOR	London Interbank Offered Rate
LNG	Liquefied natural gas
MD&A	Management's Discussion and Analysis
MGP	Mackenzie Gas Pipeline
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 hours
NEB	National Energy Board
Net earnings	Net income applicable to common shares from continuing operations
NGL	Natural gas liquid
NGTL	NOVA Gas Transmission Ltd.
Northern Border	Northern Border Pipeline Company
NPA	Northern Pipeline Act of Canada
NW Natural	Northwest Natural Gas Company
OM&A	Operating, maintenance and administration
OPA	Ontario Power Authority
OSP	Ocean State Power
Paiton Energy	P.T. Paiton Energy Company
Palomar	Palomar Gas Transmission LLC
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
SEC	U.S. Securities and Exchange Commission
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
Ventures LP	TransCanada Pipeline Ventures Limited Partnership
WCSB	Western Canada Sedimentary Basin

MANAGEMENT'S DISCUSSION AND ANALYSIS 71

Report of
Management The consolidated financial statements included in this Annual Report are the responsibility of TransCanada PipeLines Limited's 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's Discussion and Analysis in this Annual Report has been prepared by management based on the Company's financial results prepared in accordance with Canadian GAAP. It compares the Company's financial performance in 2007 to that in 2006 and should be read in conjunction with the consolidated financial statements and accompanying notes. In addition, it highlights significant changes between 2006 and 2005.

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 that govern ethical business conduct.

Under the supervision and with the participation of the President and Chief Executive Officer and the 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. TCPL acquired American Natural Resources Company and ANR Storage Company (collectively, ANR) in 2007 and began consolidating the operations of ANR into the Company. Management has excluded this business from its evaluation of the effectiveness of the Company's internal control over financial reporting as of December 31, 2007. The net income attributable to this business represented approximately nine per cent of the Company's consolidated net income for the year ended December 31, 2007, and their aggregate total assets represented approximately 12 per cent of the Company's consolidated total assets as at December 31, 2007.

Based on their evaluation, management concluded that internal control over financial reporting is effective as of December 31, 2007 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. The Audit Committee meets at least six times a year with management and meets 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.

The Audit Committee approves the terms of engagement of the independent external auditors 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 shareholder.

The shareholder has appointed KPMG LLP as independent external auditors to express an opinion as to whether the consolidated financial statements present fairly, in all material respects, the Company's consolidated financial position, results of operations and cash flows in accordance with Canadian GAAP. The report of KPMG LLP outlines the scope of its examination and its opinion on the consolidated financial statements.

Harold N. Kvisle	Gregory A. Lohnes
President and Chief Executive Officer	Executive Vice-President and Chief Financial Officer
February 25, 2008

72 TRANSCANADA PIPELINES LIMITED

Auditors'
Report To the Shareholder of TransCanada PipeLines Limited

We have audited the consolidated balance sheets of TransCanada PipeLines Limited as at December 31, 2007 and 2006, and the consolidated statements of income, comprehensive income, accumulated other comprehensive income, shareholder's equity and cash flows for each of the years in the three-year period ended December 31, 2007. 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, 2007 and 2006, 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 the audit to obtain reasonable assurance about 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, 2007 and 2006 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2007 in accordance with Canadian generally accepted accounting principles.

Chartered Accountants
Calgary, Canada

February 25, 2008

CONSOLIDATED FINANCIAL STATEMENTS 73

TRANSCANADA PIPELINES LIMITED
CONSOLIDATED INCOME

Year ended December 31 (millions of dollars)		2007		2006		2005
Revenues		8,828		7,520		6,124
Operating Expenses
Plant operating costs and other		3,030		2,411		1,825
Commodity purchases resold		1,959		1,707		1,232
Depreciation		1,179		1,059		1,017
		6,168		5,177		4,074
		2,660		2,343		2,050
Other Expenses/(Income)
Financial charges (Note 9)		961		828		837
Financial charges of joint ventures (Note 10)		75		92		66
Income from equity investments (Note 7)		(17	)	(33	)	(247	)
Interest income and other		(133	)	(123	)	(63	)
Gains on sales of assets (Note 8)		(16	)	(23	)	(445	)
		870		741		148
Income from Continuing Operations before Income Taxes and Non-Controlling Interests		1,790		1,602		1,902
Income Taxes (Note 19)
	Current	429		300		550
	Future	54		175		60
		483		475		610
Non-Controlling Interests (Note 15)		75		56		62
Net Income from Continuing Operations		1,232		1,071		1,230
Net Income from Discontinued Operations (Note 26)		–		28		–
Net Income		1,232		1,099		1,230
Preferred Share Dividends		22		22		22
Net Income Applicable to Common Shares		1,210		1,077		1,208
Net Income Applicable to Common Shares
	Continuing operations	1,210		1,049		1,208
	Discontinued operations	–		28		–
		1,210		1,077		1,208

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

74 CONSOLIDATED FINANCIAL STATEMENTS

TRANSCANADA PIPELINES LIMITED
CONSOLIDATED CASH FLOWS

Year ended December 31 (millions of dollars)	2007		2006		2005
Cash Generated from Operations
Net income	1,232		1,099		1,230
Depreciation	1,179		1,059		1,017
Income from equity investments in excess of distributions received (Note 7)	(1	)	(9	)	(71	)
Future income taxes (Note 19)	54		175		60
Non-controlling interests (Note 15)	75		56		62
Employee future benefits funding lower than/(in excess of) expense (Note 22)	43		(31	)	(9	)
Gains on sales of assets, net of current income taxes (Note 8)	(14	)	(11	)	(318	)
Other	35		36		(21	)
	2,603		2,374		1,950
Decrease/(increase) in operating working capital (Note 23)	215		(300	)	(48	)
Net cash provided by operations	2,818		2,074		1,902
Investing Activities
Capital expenditures	(1,651	)	(1,572	)	(754	)
Acquisitions, net of cash acquired (Note 8)	(4,223	)	(470	)	(1,317	)
Disposition of assets, net of current income taxes (Note 8)	35		23		671
Deferred amounts and other	(349	)	(95	)	65
Net cash used in investing activities	(6,188	)	(2,114	)	(1,335	)
Financing Activities
Dividends on common and preferred shares (Note 16 and 17)	(725	)	(639	)	(608	)
Distributions paid to non-controlling interests	(66	)	(50	)	(52	)
Advances from/(repaid to) parent	389		40		(36	)
Notes payable (repaid)/issued, net	(412	)	(495	)	416
Long-term debt issued	2,631		2,107		799
Reduction of long-term debt	(1,088	)	(729	)	(1,113	)
Long-term debt of joint ventures issued	142		56		38
Reduction of long-term debt of joint ventures	(157	)	(70	)	(80	)
Junior subordinated notes issued	1,107		–		–
Preferred securities redeemed	(488	)	–		–
Common shares issued, net of issue costs (Note 17)	1,842		–		80
Partnership units of subsidiary issued (Note 8)	348		–		–
Net cash provided by/(used in) financing activities	3,523		220		(556	)
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents	(50	)	9		11
Increase in Cash and Cash Equivalents	103		189		22
Cash and Cash Equivalents
Beginning of year	401		212		190
Cash and Cash Equivalents
End of year	504		401		212

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

CONSOLIDATED FINANCIAL STATEMENTS 75

TRANSCANADA PIPELINES LIMITED
CONSOLIDATED BALANCE SHEET

December 31 (millions of dollars)	2007		2006
ASSETS
Current Assets
Cash and cash equivalents	504		401
Accounts receivable	1,116		1,001
Inventories	497		392
Due from TransCanada Corporation (Note 25)	835		478
Other	188		297
	3,140		2,569
Long-Term Investments (Note 7)	63		71
Plant, Property and Equipment (Note 4)	23,452		21,487
Goodwill	2,633		281
Other Assets (Note 5)	1,877		1,978
	31,165		26,386
LIABILITIES AND SHAREHOLDER'S EQUITY
Current Liabilities
Notes payable (Note 20)	55		467
Accounts payable	1,769		1,510
Accrued interest	260		264
Current portion of long-term debt (Note 9)	556		616
Current portion of long-term debt of joint ventures (Note 10)	30		142
	2,670		2,999
Due to TransCanada Corporation (Note 25)	1,307		550
Deferred Amounts (Note 12)	1,107		1,029
Future Income Taxes (Note 19)	1,193		876
Long-Term Debt (Note 9)	12,377		10,887
Long-Term Debt of Joint Ventures (Note 10)	873		1,136
Junior Subordinated Notes (Note 11)	975
Preferred Securities (Note 14)	–		536
	20,502		18,013
Non-Controlling Interests (Note 15)	610		366
Shareholder's Equity
Preferred shares (Note 16)	389		389
Common shares (Note 17)	6,554		4,712
Contributed surplus	281		277
Retained earnings	3,202		2,719
Accumulated other comprehensive income	(373	)	(90	)
	2,829		2,629
	10,053		8,007
Commitments, Contingencies and Guarantees (Note 24)
Subsequent Events (Note 27)
	31,165		26,386

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

On behalf of the Board:

Harold N. Kvisle Director	Kevin E. Benson Director

76 CONSOLIDATED FINANCIAL STATEMENTS

TRANSCANADA PIPELINES LIMITED
CONSOLIDATED COMPREHENSIVE INCOME

Year ended December 31 (millions of dollars)	2007		2006		2005
Net Income	1,232		1,099		1,230
Other Comprehensive Income/(Loss), net of income taxes
Change in foreign currency translation gains and losses on investments in foreign operations(1)	(350	)	6		(34	)
Change in gains and losses on hedges of investments in foreign operations(2)	79		(6	)	15
Change in gains and losses on derivative instruments designated as cash flow hedges(3)	42		–		–
Reclassification to net income of gains and losses on derivative instruments designated as cash flow hedges pertaining to prior periods(4)	42		–		–
Other comprehensive income/(loss)	(187	)	–		(19	)
Comprehensive Income	1,045		1,099		1,211

⁽¹⁾

Net of income tax expense of $101 million in 2007 (2006 – $3-million expense; 2005 – $13-million expense).

⁽²⁾

Net of income tax expense of $41 million in 2007 (2006 – $3-million recovery; 2005 – $8-million expense).

⁽³⁾

Net of income tax expense of $27 million in 2007.

⁽⁴⁾

Net of income tax expense of $23 million in 2007.

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

CONSOLIDATED FINANCIAL STATEMENTS 77

TRANSCANADA PIPELINES LIMITED
CONSOLIDATED ACCUMULATED OTHER COMPREHENSIVE INCOME

(millions of dollars)	Currency Translation Adjustment		Cash Flow Hedges		Total
Balance at December 31, 2004	(71	)	–		(71	)
Change in foreign currency translation gains and losses on investments in foreign operations(1)	(34	)	–		(34	)
Change in gains and losses on hedges of investments in foreign operations(2)	15		–		15
Balance at December 31, 2005	(90	)	–		(90	)
Change in foreign currency translation gains and losses on investments in foreign operations(1)	6		–		6
Change in gains and losses on hedges of investments in foreign operations(2)	(6	)	–		(6	)
Balance at December 31, 2006	(90	)	–		(90	)
Transition adjustment resulting from adopting new financial instruments standards(3)	–		(96	)	(96	)
Change in foreign currency translation gains and losses on investments in foreign operations(1)	(350	)	–		(350	)
Change in gains and losses on hedges of investments in foreign operations(2)	79		–		79
Change in gains and losses on derivative instruments designated as cash flow hedges(4)	–		42		42
Reclassification to net income of gains and losses on derivative instruments designated as cash flow hedges pertaining to prior periods(5)(6)	–		42		42
Balance at December 31, 2007	(361	)	(12	)	(373	)

⁽¹⁾

Net of income tax expense of $101 million in 2007 (2006 – $3-million expense; 2005 – $13-million expense).

⁽²⁾

Net of income tax expense of $41 million in 2007 (2006 – $3-million recovery; 2005 – $8-million expense).

⁽³⁾

Net of income tax expense of $44 million in 2007.

⁽⁴⁾

Net of income tax expense of $27 million in 2007.

⁽⁵⁾

Net of income tax expense of $23 million in 2007.

⁽⁶⁾

The amount of gains and losses related to cash flow hedges reported in accumulated other comprehensive income that will be reclassified to net income in 2008 is not expected to be significant.

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

78 CONSOLIDATED FINANCIAL STATEMENTS

TRANSCANADA PIPELINES LIMITED
CONSOLIDATED SHAREHOLDER'S EQUITY

Year ended December 31 (millions of dollars)	2007		2006		2005
Preferred Shares
Balance at beginning and end of year	389		389		389
Common Shares
Balance at beginning of year	4,712		4,712		4,632
Proceeds from common shares issued (Note 17)	1,842		–		80
Balance at end of year	6,554		4,712		4,712
Contributed Surplus
Balance at beginning of year	277		275		270
Other	4		2		5
Balance at end of year	281		277		275
Retained Earnings
Balance at beginning of year	2,719		2,267		1,653
Transition adjustment resulting from adopting new financial instruments accounting standards (Note 2)	4
Net income	1,232		1,099		1,230
Preferred share dividend	(22	)	(22	)	(22	)
Common share dividends	(731	)	(625	)	(594	)
Balance at end of year	3,202		2,719		2,267
Accumulated Other Comprehensive Income, Net of Income Taxes
Balance at beginning of year	(90	)	(90	)	(71	)
Transition adjustment resulting from adopting new financial instruments accounting standards (Note 2)	(96	)
Other comprehensive income/(loss)	(187	)	–		(19	)
Balance at end of year	(373	)	(90	)	(90	)
Total Shareholder's Equity	10,053		8,007		7,553

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

CONSOLIDATED FINANCIAL STATEMENTS 79

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:

•

a natural gas transmission system extending from the Alberta border east into Québec (Canadian Mainline);

•

a natural gas transmission system in Alberta (Alberta System);

•

a natural gas transmission system extending from producing fields located primarily in Oklahoma, Texas, Louisiana and the Gulf of Mexico to markets located primarily in Wisconsin, Michigan, Illinois, Ohio and Indiana, and regulated natural gas storage facilities in Michigan (ANR);

•

a natural gas transmission system extending from the British Columbia/Idaho border to the Oregon/California border, traversing Idaho, Washington and Oregon (GTN System);

•

a natural gas transmission system extending from central Alberta to the British Columbia (B.C.)/United States border and to the Saskatchewan/U.S. border, and from the Alberta border west into southeastern B.C. (Foothills);

•

a natural gas transmission system extending from a point near Ehrenberg, Arizona to the Baja California, Mexico/California border (North Baja);

•

natural gas transmission systems in Alberta that supply natural gas to the oilsands region of northern Alberta and to a petrochemical complex at Joffre, Alberta (Ventures LP);

•

a natural gas transmission system in Mexico extending from Naranjos, Veracruz to Tamazunchale, San Luis Potosi (Tamazunchale);

•

a 53.6 per cent interest in a natural gas transmission system that connects to the Canadian Mainline and serves markets in Eastern Canada and northeastern and midwestern U.S. (Great Lakes);

•

a 50 per cent interest in a natural gas transmission system that connects with the Canadian Mainline and transports natural gas in Québec, from Montreal to the Portland system and to Québec City, (TQM); and

•

a 61.7 per cent interest in a natural gas transmission system that extends from a point near East Hereford, Québec, to the northeastern U.S. (Portland).

•

a 32.1 per cent interest in TC PipeLines, LP (PipeLines LP), which owns the following:

•

a 46.4 per cent interest in Great Lakes, in which TCPL has a 68.5 per cent effective ownership through PipeLines LP and direct interests;

•

a 50 per cent interest in a natural gas transmission system extending from a point near Monchy, Saskatchewan, to the U.S. Midwest (Northern Border), which TCPL began operating in April 2007 and in which it has a 16.1 per cent effective ownership interest through PipeLines LP; and

•

100 per cent of a natural gas transmission system extending from Malin, Oregon to Wadsworth, Nevada, (Tuscarora), which TCPL operates and in which it has a 32.1 per cent effective ownership interest through PipeLines LP.

Pipelines also holds the Company's investments in other pipelines and pipeline projects including the following:

•

a 44.5 per cent interest in a natural gas transmission system that connects with the Canadian Mainline near Waddington, New York, and delivers natural gas to customers in the northeastern U.S. (Iroquois);

•

a 46.5 per cent interest in a natural gas transmission system, which extends from Mariquita in the central region of Colombia to Cali in the southwest of Colombia (TransGas);

•

a 30 per cent interest in a natural gas transmission system extending from Loma de la Lata, Argentina to Concepción, Chile (Gas Pacifico), and in an industrial natural gas marketing company based in Concepción (INNERGY); and

•

a 50 per cent interest in a pipeline under construction that will transport crude oil from Hardisty, Alberta, to U.S. Midwest markets at Wood River and Patoka in Illinois, and to Cushing, Oklahoma (Keystone).

80 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Energy

The Energy segment builds, owns and operates electrical power generation plants, and sells electricity. Energy also holds investments in other electrical power generation plants, non-regulated natural gas storage facilities and interests in liquefied natural gas (LNG) regasification projects in North America. This business operates in Canada and the U.S. as follows:

Through its Energy segment, 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);

•

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) (collectively Bruce Power), respectively, located near Lake Huron, Ontario;

•

a 60 per cent interest in an underground natural gas storage facility near Crossfield, Alberta (CrossAlta); and

•

a 62 per cent interest in the Baie-des-Sables and Anse-à-Valleau wind farms, two of six wind farms in Gaspé, Québec (Cartier Wind).

TCPL also has long-term power purchase arrangements (PPA) in place for:

•

100 per cent of the production of the Sundance A power facilities and, through a partnership, 50 per cent of the production of the Sundance B power facilities near Wabamun, Alberta; and

•

756 megawatts (MW) of the generating capacity from the Sheerness power facility near Hanna, Alberta.

TCPL has interests in projects under construction as follow:

•

a 62 per cent interest in Carleton, the third of the six wind farms in the Cartier Wind project;

•

a 50 per cent interest in a combined-cycle natural gas cogeneration plant near downtown Toronto, Ontario (Portlands Energy); and

•

a natural gas-fired, combined-cycle power plant near Toronto (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.

In preparing these financial statements, TCPL is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgment in making these estimates. 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. The Company consolidates its 32.1 per cent ownership interest in PipeLines LP and its 61.7 per cent interest in Portland Natural Gas Transmission System (Portland), with the other partners' interests included in Non-Controlling Interests.

Regulation

The Canadian Mainline, Foothills Pipe Lines Ltd. (Foothills), including the BC System effective April 1, 2007, and Trans Québec & Maritimes System (TQM) are subject to the authority of the National Energy Board (NEB). Effective January 1, 2008, the Alberta System is regulated by

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 81

the Alberta Utilities Commission (AUC), a new regulatory body created as a result of the reorganization of the Alberta Energy and Utilities Board (EUB). The Alberta System was regulated by the EUB prior to this date. The GTN System and North Baja (collectively, GTN), ANR 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. The timing of recognition of certain revenues and expenses in these regulated businesses may differ from that otherwise expected under GAAP 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 impact of rate regulation on TCPL is provided in Note 13 of these financial statements.

Revenue Recognition

Pipelines

In the Pipelines segment, revenues from Canadian operations subject to rate regulation are recognized in accordance with decisions made by the NEB and AUC. Revenues from U.S. operations subject to rate regulation 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.

Energy

i)      Power

The majority of revenues from the Power business are derived from the sale of electricity from energy marketing activities and from the sale of unutilized natural gas fuel, which are recorded in the month of delivery. Revenues also include the impact of energy derivative contracts, the accounting for which is described in Note 2.

ii)     Natural Gas Storage

The majority of the revenues earned from natural gas storage are derived from providing storage services and are recognized in accordance with the terms of the gas storage contracts. Revenues earned on the sale of proprietary natural gas are recorded in the month of delivery. Forward contracts for the purchase or sale of natural gas, as well as proprietary natural gas inventory, are recorded at fair value with changes in fair value recorded in Net Income.

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 Cash Equivalents

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 uranium and materials and supplies, including spare parts, are carried at the lower of average cost or net realizable value. As a result of adopting the new Canadian Institute of Chartered Accountants (CICA) Handbook accounting requirements for Section 3031 "Inventories", effective April 1, 2007, TCPL began valuing its proprietary natural gas inventory held in storage at its fair value, as measured by the one-month forward price for natural gas.

Plant, Property and Equipment

Pipelines

Plant, property and equipment of the Pipelines segment 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 is capitalized based on the rate of return on rate base approved by regulators and included in the cost of gas transmission plant. Interest is capitalized during construction on non-regulated pipelines.

Energy

Major power generation and natural gas storage plant, equipment and structures in the Energy segment 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

82 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. Goodwill is not amortized and is tested for impairment annually, or more frequently if events or changes in circumstances indicate that the asset might be impaired. Currently, all goodwill relates to U.S. Pipelines acquisitions.

Power Purchase Arrangements

A PPA is a long-term contract for the purchase or sale of power on a predetermined basis. The initial payments for a PPA are deferred and amortized on a straight-line basis over the term of the contract, which ranges from nine to 12 years. PPAs, under which TCPL sells power, are accounted for as operating leases. A portion of these PPAs have been subleased to third parties under similar terms and conditions.

Income Taxes

The taxes payable method of accounting for income taxes is used for tollmaking purposes in Canadian regulated natural gas transmission operations, as prescribed by regulators. It is not necessary to provide for future income taxes under the taxes payable method. 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 the liability 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 anticipated to apply to taxable income in the years in which temporary differences are anticipated 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 that 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 consolidated statements of income, shareholder's equity, comprehensive income, accumulated other comprehensive income and cash flows are translated at the exchange rates in effect at the time of the transaction. Translation adjustments are reflected in Other Comprehensive Income.

Exchange gains or losses on the principal amounts of foreign currency debt related to the Alberta System, Foothills and Canadian Mainline are deferred until they are refunded or recovered in tolls.

Derivative Financial Instruments and Hedging Activities

The Company uses derivative and other financial instruments to manage its exposure to changes in foreign currency exchange rates, interest rates and energy commodity prices. The Company also uses a combination of derivatives and U.S. dollar-denominated debt to manage the foreign currency exposure of its foreign operations. The methods the Company uses to account for its derivative and other financial instruments are described in Notes 2 and 18.

The recognition of gains and losses on the derivatives for the Canadian Mainline, Alberta System and Foothills exposures is determined through the regulatory process. The gains and losses on derivatives accounted for as part of rate-regulated accounting are deferred in regulatory assets or regulatory liabilities.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 83

Asset Retirement Obligations

The Company recognizes the fair value of a liability for an asset retirement obligation in the period in which it is incurred, when a legal obligation exists and 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.

It is not possible to determine the scope and timing of asset retirements related to regulated natural gas transmission pipelines and therefore, not possible to make a reasonable estimate of the fair value of the associated liability. As a result, the Company has not recorded an amount for asset retirement obligations related to these assets, with the exception of abandoned facilities. Management believes it is reasonable to assume that all retirement costs associated with its regulated pipelines will be recovered through tolls in future periods.

Similarly, it is not possible to determine the scope and timing of asset retirements related to hydroelectric power plants and, therefore, not possible to make a reasonable estimate of the fair value of the associated liability. As a result, the Company has not recorded an amount for asset retirement obligations related to hydroelectric power plant assets. With respect to the nuclear assets leased by Bruce Power, the Company has not recorded an amount for asset retirement obligations, as the lessor is responsible for decommissioning liabilities under the lease agreement.

Employee Benefit and Other Plans

The Company sponsors defined benefit pension plans (DB Plans), defined contributions plans (DC Plans) and other post-employment plans. Contributions made by the Company to the DC Plans are expensed as incurred. The cost of the DB Plans and other post-employment benefits earned by employees is actuarially determined using the projected benefit method pro-rated based on service and management's best estimate of expected plan investment performance, salary escalation, retirement ages of employees and expected health care costs.

The DB Plans' assets are measured at fair value. The expected return on the DB Plans' 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 the DB Plans' 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. 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 employees' continued employment during a specified period and achievement of specified corporate performance targets.

Certain of the Company's joint ventures sponsor DB Plans. The Company records its proportionate share of expenses, funding contributions and accrued benefit assets and liabilities related to these plans.

NOTE 2    ACCOUNTING CHANGES

Changes in Accounting Policies for 2007

Effective January 1, 2007, the Company adopted the accounting requirements for CICA Handbook Sections 1506 "Accounting Changes", 1530 "Comprehensive Income", 3251 "Equity", 3855 "Financial Instruments – Recognition and Measurement", and 3865 "Hedges". In addition, the Company chose to adopt the accounting requirements for Sections 3862 "Financial Instruments – Disclosure", 3863 "Financial Instruments – Presentation", and 1535 "Capital Disclosures" effective December 31, 2007, as well as the accounting requirements for Section 3031 "Inventories" effective April 1, 2007. Adjustments to the consolidated financial statements for 2007 have been made in accordance with the transitional provisions for these new standards.

Comprehensive Income and Equity

The Company's financial statements include statements of Consolidated Comprehensive Income and Consolidated Accumulated Other Comprehensive Income. In addition, as required in CICA Handbook Section 3251, the Company now presents separately, in the Consolidated Shareholder's Equity statement, the changes for each of its components of Shareholder's Equity, including Accumulated Other Comprehensive Income.

Financial Instruments

All financial instruments must initially be included on the balance sheet at their fair value. Subsequent measurement of the financial instruments is based on their classification. Financial assets are classified into the following categories: held for trading, available for sale, held-to-maturity investments and loans and receivables. Financial liabilities are classified as held for trading or other financial liabilities.

84 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Held-for-trading financial assets and liabilities consist of swaps, options, forwards and futures, and are entered into with the intention of generating a profit. A financial asset or liability that does not meet this criterion may also be designated as held for trading. Power and natural gas held-for-trading instruments are initially recorded at their fair value and changes to fair value are included in Revenues. Changes in the fair value of interest rate and foreign exchange held-for-trading instruments are recorded in Financial Charges and in Interest Income and Other, respectively. The Company had not designated any financial assets or liabilities as held for trading at December 31, 2007.

The available-for-sale classification includes non-derivative financial assets that are designated as available for sale or are not included in the other three classifications. TCPL's available-for-sale financial instruments include fixed-income securities held for self-insurance. These instruments are initially accounted for at their fair value and changes to fair value are recorded through Other Comprehensive Income. Income from the settlement of available-for-sale financial assets will be included in Interest Income and Other.

Held-to-maturity financial assets are accounted for at their amortized cost using the effective interest method. The Company did not have any held-to-maturity financial assets at December 31, 2007.

Trade receivables, loans and other receivables with fixed or determinable payments that are not quoted in an active market are classified as "loans and receivables" and are measured net of any impairment. Loans and receivables include primarily trade accounts receivable and non-interest-bearing third-party loans receivable. Interest and other income earned from these financial assets are recorded in Interest Income and Other.

Other financial liabilities consist of liabilities not classified as held for trading. Interest expense is included in Financial Charges and in Financial Charges of Joint Ventures. Items in this financial instrument category are recognized at amortized cost using the effective interest method.

All derivatives are recorded on the balance sheet at fair value, with the exception of those that were entered into and continue to be held for the purpose of receipt or delivery in accordance with the Company's expected purchase, sale or usage requirements (normal purchase and normal sale exemption). Changes in the fair value of derivatives that are not designated in a hedging relationship are recorded in Net Income. Derivatives used in hedging relationships are discussed further under the heading Hedges in this Note.

Derivatives embedded in other financial instruments or contracts (the host instrument) are recorded as separate derivatives and are measured at fair value if the economic characteristics of the embedded derivative are not closely related to the host instrument, the terms of the embedded derivative are the same as those of a stand-alone derivative and the total contract is not held for trading or accounted for at fair value. Changes in the fair value of embedded derivates that are recorded separately are included in Revenues. The Company used January 1, 2003 as the transition date for embedded derivatives.

Transaction costs are incremental costs that are directly attributable to the acquisition, issue or disposal of a financial instrument. Effective January 1, 2007, the Company began offsetting long-term debt transaction costs against the associated debt and began amortizing these costs using the effective interest method. Previously, these costs were amortized on a straight-line basis over the life of the debt. There was no material impact on the Company's financial statements as a result of this change in policy. In 2007, the impact on Net Income for the amortization of transaction costs using the effective interest method was nominal.

The Company records the fair values of material joint and several guarantees. These fair values cannot be readily obtained from an open market and therefore, the fair value of these guarantees is estimated by discounting the cash flows that would be incurred by the Company if letters of credit were used in place of the guarantees. Guarantees are recorded as an increase to an investment account, Property, Plant and Equipment or a charge to Net Income, and a corresponding liability in Deferred Amounts.

Hedges

CICA Handbook Section 3865 specifies the criteria that must be satisfied in order to apply hedge accounting and the accounting for each of the permitted hedging strategies, including: fair value hedges, cash flow hedges and hedges of foreign currency exposures of net investments in self-sustaining foreign operations. Hedge accounting is discontinued prospectively when the derivative no longer qualifies as an effective hedge or is terminated or sold, or upon the sale or early termination of the hedged item.

Documentation must be prepared at the inception of the hedging arrangement in order to qualify for hedge accounting treatment. In addition, the Company must perform an assessment of effectiveness at inception of the contract and at each reporting date.

In a fair value hedging relationship, the carrying value of the hedged item is adjusted for changes in fair value attributable to the hedged risk. The changes in fair value are recognized in Net Income. Changes in the fair value of the hedged item, to the extent that the hedging relationship is effective, are offset by changes in the fair value of the hedging item, which is also recorded in Net Income. Changes in the fair value of foreign exchange and interest rate hedges are recorded in Interest Income and Other and Financial Charges, respectively. When hedge accounting is discontinued, the carrying value of the hedged item is no longer adjusted and the cumulative fair value adjustments to the carrying value of the hedged item are amortized to Net Income over the remaining term of the original hedging relationship.

In a cash flow hedging relationship, the effective portion of the change in the fair value of the hedging derivative is recognized in Other Comprehensive Income, while any ineffective portion is recognized in Net Income in the same financial category as the underlying transaction.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 85

When hedge accounting is discontinued, the amounts recognized previously in Accumulated Other Comprehensive Income are reclassified to Net Income during the periods when the variability in cash flows of the hedged item affects Net Income. Gains and losses on derivatives are reclassified immediately to Net Income when the hedged item is sold or terminated early, or when a hedged anticipated transaction is no longer expected to occur.

The Company also enters into cash flow hedges and fair value hedges for activities subject to rate regulation. The gains and losses arising from the changes in fair value of these hedges can be recovered through the tolls charged by the Company. As a result, these gains and losses are deferred as rate-regulated assets or liabilities on behalf of the ratepayers. When the hedges are settled, the realized gains or losses are collected from or refunded to the ratepayers in subsequent years.

In hedging the foreign currency exposure of a net investment in a self-sustaining foreign operation, the effective portion of foreign exchange gains and losses on the hedging instruments is recognized in Other Comprehensive Income and the ineffective portion is recognized in Net Income. The amounts recognized previously in Accumulated Other Comprehensive Income are recognized in Net Income in the event the Company settles or otherwise reduces its investment.

Net Effect of Accounting Policy Changes

The net effect of the preceding accounting policy changes on the Company's financial statements at January 1, 2007, was as follows:

Increases/(decreases) (millions of dollars)
Other current assets	(127	)
Other assets	(203	)
Accounts payable	(29	)
Deferred amounts	(75	)
Future income taxes	(42	)
Long-term debt	(85	)
Long-term debt of joint ventures	(7	)
Accumulated other comprehensive income	(96	)
Retained earnings	4

The primary changes in 2007 to the Company's accounting policies for financial instruments related to the requirements to record certain non-financial contracts at their fair value and to offset transaction costs against long-term debt.

Section 3862 Financial Instruments – Disclosures and Section 3863 Financial Instruments – Presentation

CICA Handbook Sections 3862 "Financial Instruments – Disclosure" and 3863 "Financial Instruments – Presentation", which replaced Section 3861 "Financial Instruments – Disclosure and Presentation", are effective January 1, 2008. However, the Company chose to adopt these standards effective December 31, 2007. The additional disclosure necessary to comply with these standards is provided in these consolidated financial statements. Certain information related to comparative years is not prescribed by these standards and accordingly has not been presented.

Section 1535 Capital Disclosures

CICA Handbook Section 1535 "Capital Disclosures" is effective for fiscal years beginning on or after October 1, 2007, however, TCPL chose to adopt this standard effective December 31, 2007. Note 18 in these consolidated financial statements provides qualitative disclosure regarding objectives, policies and processes for managing capital as well as quantitative data on capital as of December 31, 2007.

Proprietary Natural Gas Inventories and Revenue Recognition

CICA Handbook Section 3031 "Inventories" is effective January 1, 2008. However, the Company chose to adopt this standard effective April 1, 2007, and began valuing its proprietary natural gas inventory held in storage at fair value, as measured by the one-month forward price for natural gas. To record inventory at fair value, TCPL has designated its natural gas storage business as a broker/trader business that purchases and sells natural gas on a back-to-back basis. TCPL did not have any proprietary natural gas inventory prior to April 1, 2007.

The Company records its proprietary natural gas storage results in Revenues net of Commodity Purchases Resold. All changes in the fair value of the proprietary natural gas inventories are reflected in Inventories and Revenues.

86 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Future Accounting Changes

Rate-Regulated Operations

Effective January 1, 2009, the temporary exemption from CICA Handbook Section 1100, "Generally Accepted Accounting Principles", which permits the recognition and measurement of assets and liabilities arising from rate regulation, will be withdrawn. In addition, Section 3465 "Income Taxes" was amended to require the recognition of future income tax liabilities and assets. As a result of the changes, TCPL will be required to recognize future income tax liabilities and assets instead of using the taxes payable method, and will record an offsetting adjustment to regulatory assets and liabilities. If the liability method of accounting had been used at December 31, 2007, additional future income tax liabilities in the amount of $1,138 million would have been recorded and would have been recoverable from future revenue. These changes will be applied prospectively beginning January 1, 2009.

International Financial Reporting Standards

The CICA's Accounting Standards Board (AcSB) announced that Canadian publicly accountable enterprises will adopt International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB), effective January 1, 2011. IFRS will require increased financial statement disclosure. Although IFRS uses a conceptual framework similar to Canadian GAAP, differences in accounting policies will need to be addressed. TCPL is currently assessing the impact of this AcSB announcement on its financial statements.

Intangible Assets

The CICA Handbook implemented revisions to standards dealing with Intangible Assets effective for fiscal years beginning on or after October 1, 2008. The revisions are intended to align the definition of an Intangible Asset in Canadian GAAP with that in IFRS and U.S. GAAP. Section 1000 "Financial Statement Concepts" was revised to remove material that permitted the recognition of assets that might not otherwise meet the definition of an asset and to add guidance from the IASB's "Framework for the Preparation and Presentation of Financial Statements" that will help distinguish assets from expenses. Section 3064 "Goodwill and Intangible Assets", which replaced Section 3062 "Goodwill and Other Intangible Assets", gives guidance on the recognition of intangible assets as well as the recognition and measurement of internally developed intangible assets. Section 3450 "Research and Development Costs" will be withdrawn from the Handbook. The Company does not expect these changes to have a material effect on its financial statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 87

NOTE 3    SEGMENTED INFORMATION

NET INCOME/(LOSS)⁽¹⁾

Year ended December 31, 2007 (millions of dollars)	Pipelines		Energy		Corporate		Total
Revenues	4,712		4,116		–		8,828
Plant operating costs and other	(1,670	)	(1,353	)	(7	)	(3,030	)
Commodity purchases resold	(72	)	(1,887	)	–		(1,959	)
Depreciation	(1,021	)	(158	)	–		(1,179	)
	1,949		718		(7	)	2,660
Financial charges and non-controlling interests	(793	)	1		(266	)	(1,058	)
Financial charges of joint ventures	(52	)	(23	)	–		(75	)
Income from equity investments	17		–		–		17
Interest income and other	35		10		88		133
Gain on sale of assets	–		16		–		16
Income taxes	(470	)	(208	)	195		(483	)
Net Income Applicable to Common Shares	686		514		10		1,210

Year ended December 31, 2006 (millions of dollars)
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

Year ended December 31, 2005 (millions of dollars)
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 sales of assets	82		363		–		445
Income taxes	(497	)	(178	)	65		(610	)
Net Income Applicable to Common Shares	679		566		(37	)	1,208

⁽¹⁾

Certain expenses such as indirect financial charges and related income taxes are not allocated to business segments when determining their net income.

88 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

TOTAL ASSETS

December 31 (millions of dollars)	2007	2006
Pipelines	22,024	18,320
Energy	7,037	6,500
Corporate	2,104	1,566
	31,165	26,386

GEOGRAPHIC INFORMATION

Year ended December 31 (millions of dollars)	2007	2006	2005
Revenues(1)
Canada – domestic	5,019	4,956	3,499
Canada – export	1,006	972	1,160
United States and other	2,803	1,592	1,465
	8,828	7,520	6,124

⁽¹⁾

Revenues are attributed based on the country where the product or service originated.

December 31 (millions of dollars)	2007	2006
Plant, Property and Equipment
Canada	16,741	16,204
United States	6,564	5,109
Mexico	147	174
	23,452	21,487

CAPITAL EXPENDITURES

Year ended December 31 (millions of dollars)	2007	2006	2005
Pipelines	564	560	244
Energy	1,079	976	506
Corporate	8	36	4
	1,651	1,572	754

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 89

NOTE 4    PLANT, PROPERTY AND EQUIPMENT

		2007			2006
December 31 (millions of dollars)		Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value
Pipelines
Canadian Mainline
	Pipeline	8,889	4,149	4,740	8,850	3,911	4,939
	Compression	3,371	1,303	2,068	3,343	1,181	2,162
	Metering and other	345	140	205	346	136	210
		12,605	5,592	7,013	12,539	5,228	7,311
	Under construction	28	–	28	23	–	23
		12,633	5,592	7,041	12,562	5,228	7,334
Alberta System
	Pipeline	5,258	2,504	2,754	5,120	2,352	2,768
	Compression	1,522	842	680	1,510	760	750
	Metering and other	831	297	534	806	271	535
		7,611	3,643	3,968	7,436	3,383	4,053
	Under construction	120	–	120	98	–	98
		7,731	3,643	4,088	7,534	3,383	4,151
ANR(1)
	Pipeline	772	25	747
	Compression	424	32	392
	Metering and other	483	6	477
		1,679	63	1,616
	Under construction	69	–	69
		1,748	63	1,685
GTN
	Pipeline	1,181	134	1,047	1,386	111	1,275
	Compression	436	39	397	512	32	480
	Metering and other	81	3	78	89	–	89
		1,698	176	1,522	1,987	143	1,844
	Under construction	31	–	31	17	–	17
		1,729	176	1,553	2,004	143	1,861
Great Lakes(2)
	Pipeline	977	427	550	806	463	343
	Compression	359	75	284	255	85	170
	Metering and other	165	50	115	122	52	70
		1,501	552	949	1,183	600	583
	Under construction	8	–	8	4	–	4
		1,509	552	957	1,187	600	587
Foothills
	Pipeline	903	476	427	815	405	410
	Compression	632	286	346	377	141	236
	Metering and other	112	57	55	72	35	37
		1,647	819	828	1,264	581	683
Joint Ventures and Other
	Northern Border(3)	1,232	528	704	1,451	585	866
	Other	1,863	439	1,424	2,274	615	1,659
		3,095	967	2,128	3,725	1,200	2,525
		30,092	11,812	18,280	28,276	11,135	17,141
Energy(4)
	Nuclear(5)	1,479	286	1,193	1,349	214	1,135
	Natural gas	1,570	383	1,187	1,636	383	1,253
	Hydro	503	28	475	592	21	571
	Natural gas storage	358	33	325	344	22	322
	Wind	288	6	282	131	–	131
	Other	137	78	59	153	72	81
		4,335	814	3,521	4,205	712	3,493
	Under construction	1,606	–	1,606	809	–	809
		5,941	814	5,127	5,014	712	4,302
Corporate		60	15	45	65	21	44
		36,093	12,641	23,452	33,355	11,868	21,487

90 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

⁽¹⁾

TCPL acquired ANR on February 22, 2007.

⁽²⁾

In February 2007, PipeLines LP acquired a 46.4 per cent general partnership interest in Great Lakes and TCPL increased its ownership interest in Great Lakes by 3.6 per cent, bringing the Company's direct ownership to 53.6 per cent (December 31, 2006 – 50 per cent) and making Great Lakes a controlled entity. The Company commenced consolidating its investment in Great Lakes on a prospective basis. Prior to this, Great Lakes was being proportionately consolidated. TCPL's 32.1 per cent ownership interest in PipeLines LP brought its effective ownership of Great Lakes net of non-controlling interests, to 68.5 per cent at December 31, 2007.

⁽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. Through TCPL's ownership interest in PipeLines LP, Northern Border became a jointly controlled entity and TCPL commenced proportionately consolidating its investment in Northern Border on a prospective basis. TCPL's effective ownership of Northern Border, net of non-controlling interests, was 16.1 per cent at December 31, 2007 (2006 – 6.7 per cent).

⁽⁴⁾

Certain power generation facilities with long-term PPAs are accounted for as assets under operating leases. The net book value of these facilities was $78 million at December 31, 2007 (2006 – $81 million). Revenues of $16 million were recognized in 2007 (2006 – $13 million) through the sale of electricity under the related PPAs.

⁽⁵⁾

Includes assets under capital lease relating to Bruce Power.

NOTE 5    OTHER ASSETS

December 31 (millions of dollars)	2007	2006
PPAs(1)	709	767
Regulatory assets	336	178
Pension and other benefit plans	234	268
Fair value of derivative contracts	204	144
Loans and advances(2)	141	121
Deferred project development costs(3)	40	70
Hedging deferrals(4)	–	152
Debt issue costs(5)	–	77
Other	213	201
	1,877	1,978

⁽¹⁾

The following amounts related to the PPAs are included in the consolidated financial statements.

	2007			2006
December 31 (millions of dollars)	Cost	Accumulated Amortization	Net Book Value	Cost	Accumulated Amortization	Net Book Value
PPAs	915	206	709	915	148	767

The amortization expense for the PPAs was $58 million for the year ended December 31, 2007 (2006 – $58 million; 2005 – $24 million). The expected annual amortization expense in each of the next five years is: 2008 – $58 million; 2009 – $58 million; 2010 – $58 million; 2011 – $57 million; and 2012 – $57 million.

⁽²⁾

The balance at December 31, 2007 included a $137-million loan (2006 – $118 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 project. The ability to recover this investment remains dependent upon the successful outcome of the project.

⁽³⁾

The balance at December 31, 2007 included $40 million (2006 – $31 million) related to the Broadwater LNG project. The balance at December 31, 2006 included $39 million related to Keystone.

⁽⁴⁾

Changes in GAAP required the Company to record the effective portion and the changes in fair value of cash flow and fair value hedges in Other Comprehensive Income and Net Income, respectively, effective January 1, 2007. Prior to this date, the fair value of certain hedges was deferred and recognized in income when the instrument had settled.

⁽⁵⁾

Changes in GAAP required the Company to offset long-term debt transaction costs against the associated debt, effective January 1, 2007.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 91

NOTE 6    JOINT VENTURE INVESTMENTS

			TCPL's Proportionate Share
			Income Before Income Taxes Year ended December 31			Net Assets December 31
(millions of dollars)	Ownership Interest(1)		2007	2006	2005	2007	2006
Pipelines
Northern Border		(3)	63	47	–	542	634
Iroquois	44.5%	(4)	25	25	29	163	194
Great Lakes		(5)	13	69	73	–	370
TQM	50.0%		11	11	13	74	75
Keystone	50.0%	(6)	–	–	–	207	–
Other	Various		13	6	10	48	–
Energy
Bruce A	48.7%	(7)	8	75	19	1,640	916
Bruce B	31.6%	(7)	140	140	5	325	425
CrossAlta(2)	60.0%		59	64	31	38	36
Cartier Wind	62.0%	(8)	10	2	–	275	172
TC Turbines	50.0%		5	5	5	29	26
Portlands Energy	50.0%		–	–	–	269	90
ASTC Power Partnership	50.0%	(9)	–	–	–	76	82
Power LP		(10)	–	–	25	–	–
			347	444	210	3,686	3,020

⁽¹⁾

All ownership interests are as at December 31, 2007.

⁽²⁾

CrossAlta Gas Storage & Services Ltd. (CrossAlta).

⁽³⁾

PipeLines LP acquired an additional 20 per cent general partnership interest in Northern Border in April 2006, increasing its general partnership interest to 50 per cent. Through TCPL's 32.1 per cent ownership interest in PipeLines LP, Northern Border became a jointly controlled entity and TCPL commenced proportionately consolidating its investment in Northern Border on a prospective basis. The Company's effective ownership of Northern Border, net of non-controlling interests, was 16.1 per cent at December 31, 2007 (2006 – 6.7 per cent).

⁽⁴⁾

The Company acquired an additional 3.5 per cent ownership interest in Iroquois Gas Transmission System, L.P. (Iroquois) in June 2005.

⁽⁵⁾

In February 2007, TCPL acquired an additional 3.6 per cent interest in Great Lakes, bringing its direct ownership interest to 53.6 per cent, and PipeLines LP acquired a 46.4 per cent interest in Great Lakes, giving TCPL an indirect 14.9 per cent interest in Great Lakes. As a result of these transactions the Company's effective ownership of Great Lakes, net of non-controlling interests, was 68.5 per cent at December 31, 2007 (2006 – 50 per cent). TCPL commenced consolidating its investment in Great Lakes, on a prospective basis, effective February 22, 2007.

⁽⁶⁾

In December 2007, ConocoPhillips exercised its option to become a 50 per cent partner with TCPL in Keystone. As a result, TCPL transferred $207 million of net assets and ConocoPhillips contributed $207 million of cash to each become a 50 per cent joint venture partner in Keystone.

⁽⁷⁾

TCPL acquired a 47.4 per cent ownership interest in Bruce A on October 31, 2005. The Company's ownership interest in Bruce A was 48.7 per cent at December 31, 2007 (2006 – 48.7 per cent). The Company proportionately consolidated its investments in Bruce A and Bruce B on a prospective basis, effective October 31, 2005.

⁽⁸⁾

TCPL proportionately consolidates 62 per cent of the Cartier Wind assets. The first two phases of the six-phase Cartier Wind project, Baie-des-Sables and Anse-à-Valleau, began operating in November 2006 and 2007, respectively.

⁽⁹⁾

The Company has a 50 per cent ownership interest in ASTC Power Partnership, which is located in Alberta and holds the Sundance B PPA. The underlying power volumes related to this ownership interest are effectively transferred to TCPL.

⁽¹⁰⁾

In August 2005, the Company sold its 30.6 per cent interest in TransCanada Power, L.P.

92 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Summarized Financial Information of Joint Ventures

Year ended December 31 (millions of dollars)	2007		2006		2005
Income
Revenues	1,224		1,379		687
Plant operating costs and other	(659	)	(689	)	(328	)
Depreciation	(150	)	(162	)	(93	)
Financial charges and other	(68	)	(84	)	(56	)
Proportionate share of joint venture income before income taxes	347		444		210

Year ended December 31 (millions of dollars)	2007		2006		2005
Cash Flows
Operating activities	420		645		346
Investing activities	(761	)	(641	)	(133	)
Financing activities(1)	409		(31	)	(152	)
Effect of foreign exchange rate changes on cash and cash equivalents	(8	)	9		(1	)
Proportionate share of increase/(decrease) in cash and cash equivalents of joint ventures	60		(18	)	60

⁽¹⁾

Financing activities included cash outflows resulting from distributions paid to TCPL of $361 million in 2007 (2006 – $470 million; 2005 – $201 million) and cash inflows resulting from capital contributions paid by TCPL of $771 million in 2007 (2006 – $452 million; 2005 – $92 million).

December 31 (millions of dollars)	2007		2006
Balance Sheet
Cash and cash equivalents	170		127
Other current assets	314		304
Plant, property and equipment	4,283		4,110
Other assets	44		78
Current liabilities	(250	)	(443	)
Long-term debt	(873	)	(1,136	)
Future income taxes	(2	)	(20	)
Proportionate share of net assets of joint ventures	3,686		3,020

NOTE 7    LONG-TERM INVESTMENTS

			TCPL's Share
			Distributions from Equity Investments Year ended December 31			Income from Equity Investments Year ended December 31			Equity Investments December 31
(millions of dollars)	Ownership Interest		2007	2006	2005	2007	2006	2005	2007	2006
Pipelines
TransGas	46.5%		8	7	6	14	11	11	63	66
Northern Border		(1)	–	13	76	–	13	61	–	–
Other	Various		8	4	10	3	9	7	–	5
Energy
Bruce B	31.6%	(2)	–	–	84	–	–	168	–	–
			16	24	176	17	33	247	63	71

⁽¹⁾

PipeLines LP acquired an additional 20 per cent general partnership interest in Northern Border in April 2006, bringing its general partnership interest to 50 per cent. Through TCPL's 32.1 per cent ownership interest in PipeLines LP, Northern Border became a jointly controlled entity and TCPL commenced proportionately consolidating its investment in Northern Border on a prospective basis.

⁽²⁾

The Company commenced proportionately consolidating its 31.6 per cent ownership interest in Bruce B on a prospective basis, effective October 31, 2005.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 93

NOTE 8    ACQUISITIONS AND DISPOSITIONS

Acquisitions

Pipelines

ANR and Great Lakes

On February 22, 2007, TCPL acquired from El Paso Corporation 100 per cent of ANR and an additional 3.6 per cent interest in Great Lakes Gas Transmission Limited Partnership (Great Lakes) for a total of US$3.4 billion, subject to certain post-closing adjustments, including US$491 million of assumed long-term debt. The acquisitions were accounted for using the purchase method of accounting. TCPL began consolidating ANR and Great Lakes in the Pipelines segment after the acquisition date. The preliminary allocation of the purchase price at December 31, 2007, was as follows.

Purchase Price Allocation

(millions of US dollars)	ANR		Great Lakes		Total
Current assets	250		4		254
Plant, property and equipment	1,617		35		1,652
Other non-current assets	83		–		83
Goodwill	1,914		32		1,946
Current liabilities	(179	)	(3	)	(182	)
Long-term debt	(475	)	(16	)	(491	)
Other non-current liabilities	(326	)	(19	)	(345	)
	2,884		33		2,917

TC PipeLines, LP Acquisition of Interest in Great Lakes

On February 22, 2007, PipeLines LP acquired from El Paso Corporation a 46.4 per cent interest in Great Lakes for US$942 million, subject to certain post-closing adjustments, including US$209 million of assumed long-term debt. The acquisition was accounted for using the purchase method of accounting. TCPL began consolidating Great Lakes in the Pipelines segment after the acquisition date. The preliminary allocation of the purchase price at December 31, 2007, was as follows.

Purchase Price Allocation

(millions of US dollars)
Current assets	42
Plant, property and equipment	465
Other non-current assets	1
Goodwill	457
Current liabilities	(23	)
Long-term debt	(209	)
	733

The preliminary allocation of the purchase price for these transactions was made using the fair value of the net assets at the date of acquisition. Tolls charged by ANR and Great Lakes are subject to rate regulation based on historical costs. As a result, the regulated net assets, other than ANR's gas held for sale, were determined to have a fair value equal to their rate-regulated values.

Factors that contributed to goodwill included the opportunity to expand in the U.S. market and to gain a stronger competitive position in the North American gas transmission business. Goodwill related to TCPL's ANR and Great Lakes transactions is not amortizable for tax purposes. Goodwill related to PipeLines LP's Great Lakes transaction is amortizable for tax purposes.

TC PipeLines, LP Private Placement Offering

PipeLines LP completed a private placement offering of 17,356,086 common units at a price of US$34.57 per unit in February 2007. TCPL acquired 50 per cent of the units for US$300 million. TCPL also invested an additional US$12 million to maintain its general partnership interest in PipeLines LP. As a result of these additional investments, TCPL's ownership in PipeLines LP increased to 32.1 per cent on February 22, 2007. The total private placement, together with TCPL's additional investment, resulted in gross proceeds to PipeLines LP of US$612 million, which were used to partially finance its acquisition of a 46.4-per-cent ownership interest in Great Lakes.

94 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Tuscarora

PipeLines LP exercised its option to purchase Sierra Pacific Resources' remaining one per cent interest in Tuscarora Gas Transmission Company (Tuscarora) for US$2 million in December 2007. In addition, PipeLines LP purchased TCPL's one per cent interest in Tuscarora for US$2 million.

In December 2006, PipeLines LP acquired an additional 49 per cent controlling general partner interest in Tuscarora for US$100 million in addition to indirectly assuming 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 included opportunities for expansion and a stronger competitive position. The goodwill recognized on this transaction is amortizable for tax purposes. PipeLines LP began consolidating its investment in Tuscarora in December 2006. TCPL became the operator of Tuscarora in December 2006 as a result of this transaction.

PipeLines LP now owns 100 per cent of Tuscarora. At December 31, 2007, TCPL's 32.1 per cent ownership interest in PipeLines LP (December 31, 2006 – 13.4 per cent) gave it an effective ownership in Tuscarora of 32.1 per cent, net of non-controlling interests (December 31, 2006 – 14.3 per cent).

Northern Border

In April 2006, PipeLines LP acquired an additional 20 per cent general partnership interest in Northern Border Pipeline Company (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 included opportunities for expansion and a stronger competitive position. The goodwill recognized on this transaction is amortizable for tax purposes.

PipeLines LP now owns 50 per cent of Northern Border. At December 31, 2007, TCPL's 32.1 per cent ownership interest in PipeLines LP (2006 – 13.4 per cent) gave it an effective ownership in Northern Border of 16.1 per cent, net of non-controlling interests (2006 – 6.7 per cent). TCPL proportionately consolidated its interest in Northern Border since the date of acquisition. TCPL became the operator of Northern Border in April 2007 as a result of this transaction.

Energy

Sheerness PPA

TCPL obtained the 756 MW Sheerness PPA from the Alberta Balancing Pool for $585 million effective December 31, 2005. The PPA terminates in 2020.

Bruce Power

In October 2005, TCPL acquired an interest in Bruce A, a newly created partnership, as part of an agreement to restart Bruce A Units 1 and 2, which are currently idle. Under the Bruce A Sublease agreement, the new partnership subleased Units 1 to 4 from Bruce B and purchased certain other related assets. TCPL incurred a net cash outlay of $100 million related to this transaction. As part of the reorganization, Bruce A and Bruce B became jointly controlled entities and TCPL commenced proportionately consolidating its investment in both on a prospective basis effective October 31, 2005. At December 31, 2007 and 2006, the Company held a 48.7 per cent interest in Bruce A and a 31.6 per cent interest in Bruce B.

TC Hydro

TCPL acquired TC Hydro, the hydroelectric generation assets of USGen New England, Inc. for approximately US$503 million in April 2005. Substantially all of the purchase price was allocated to Plant, Property and Equipment.

Dispositions

Pre-tax gains on sales of assets were as follow:

Year ended December 31 (millions of dollars)	2007	2006	2005
Gain on sale of land	16	–	–
Gain on sale of Northern Border Partners, LP interest	–	23	–
Gains related to Power LP	–	–	245
Gain on sale of Paiton Energy	–	–	118
Gain on sale of PipeLines LP units	–	–	82
	16	23	445

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 95

Ontario Land Sale

In November 2007, TCPL's Energy segment sold land in Ontario that had been previously held for development, generating net proceeds of $37 million and recognizing an after-tax gain of $14 million on the sale.

Northern Border Partners, LP Interest

In April 2006, TCPL sold its 17.5 per cent general partner interest in Northern Border Partners, LP, generating net proceeds of $33 million (US$30 million) and recognizing an after-tax gain of $13 million. The net gain was recorded in the Pipelines segment and the Company recorded a $10-million income tax charge on the transaction, including $12 million of current income tax expense.

Power LP

In August 2005, TCPL sold its ownership interest in TransCanada Power, L.P. (Power LP) to EPCOR Utilities Inc. (EPCOR), generating net proceeds of $523 million and realizing 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 on the transaction, including $79 million of current income tax expense. The sale resulted in disposal of Power LP assets and liabilities with a book value of $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 assets.

Paiton Energy

In November 2005, TCPL sold its ownership interest of approximately 11 per cent in PT Paiton Energy Company (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 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.

TC PipeLines, LP

In March and April 2005, TCPL sold a total of 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 on the transaction, including $51 million of current income tax expense.

96 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 9    LONG-TERM DEBT

			2007		2006
Outstanding loan amounts (millions of dollars unless otherwise indicated)		Maturity Dates	Outstanding December 31	Interest Rate(1)(2)	Outstanding December 31	Interest Rate(2)(3)
TRANSCANADA PIPELINES LIMITED
First Mortgage Pipe Line Bonds
	Pounds sterling (2006 – £25 million)		–		57	16.5%
Debentures
	Canadian dollars	2008 to 2020	1,351	10.9%	1,355	10.9%
	U.S. dollars (2007 and 2006 – US$600)(4)	2012 to 2021	594	9.5%	699	9.5%
Medium-Term Notes
	Canadian dollars(5)	2008 to 2031	3,413	6.1%	3,848	6.0%
Senior Unsecured Notes
	U.S. dollars (2007 – US$3,223; 2006 –  US$2,223)(6)	2009 to 2037	3,161	6.0%	2,590	5.8%
			8,519		8,549
NOVA GAS TRANSMISSION LTD.
Debentures and Notes
	Canadian dollars	2008 to 2024	501	11.6%	564	11.6%
	U.S. dollars (2007 and 2006 – US$375)	2012 to 2023	368	8.2%	437	8.2%
Medium-Term Notes
	Canadian dollars	2008 to 2030	607	7.2%	609	7.1%
	U.S. dollars (2007 and 2006 – US$33)	2026	32	7.5%	38	7.5%
			1,508		1,648
TRANSCANADA PIPELINE USA LTD.
Bank Loan
	U.S. dollars (2007– US$860)	2012	850	5.7%
ANR PIPELINE COMPANY
Senior Unsecured Notes
	U.S. dollars (2007– US$444)	2010 to 2025	435	9.1%
GAS TRANSMISSION NORTHWEST CORPORATION
Senior Unsecured Notes
	U.S. dollars (2007 and 2006 – US$400)	2010 to 2035	399	5.4%	466	5.3%
TC PIPELINES, LP
Unsecured Loan
	U.S. dollars (2007 – US$507; 2006 –  US$397)	2011	499	6.2%	463	5.4%
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP(7)
Senior Unsecured Notes
	U.S. dollars (2007– US$440)	2011 to 2030	434	7.8%
TUSCARORA GAS TRANSMISSION COMPANY
Senior Unsecured Notes
	U.S. dollars (2007 – US$69; 2006 –  US$74)	2010 to 2012	67	7.4%	86	7.2%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Senior Secured Notes
	U.S. dollars (2007 – US$211; 2006 –  US$226)	2018	205	6.1%	263	5.9%
OTHER
Senior Notes
	U.S. dollars (2007 – US$17; 2006 – US$24)	2011	17	7.3%	28	7.3%
			12,933		11,503
Less: Current Portion of Long-Term Debt			556		616
			12,377		10,887

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 97

⁽¹⁾

Interest rates are the effective interest rates except for those pertaining to long-term debt issued for the Company's regulated operations, in which case the weighted average interest rate is presented as required by the regulators.

⁽²⁾

Weighted average and effective interest rates are stated as at the respective outstanding dates. The effective weighted average interest rate resulting from swap agreements was six per cent in 2007 on TCPL's U.S. dollar Medium-Term Notes (2006 – 5.8 per cent).

⁽³⁾

Interest rates are the weighted average interest rates.

⁽⁴⁾

Includes fair value adjustments for swap agreements on US$50 million of debt at December 31, 2007.

⁽⁵⁾

Includes fair value adjustments for swap agreements on $150 million of debt at December 31, 2007.

⁽⁶⁾

Includes fair value adjustments for swap agreements on US$150 million of debt at December 31, 2007.

⁽⁷⁾

TCPL increased its effective ownership in Great Lakes to 68.5 per cent from 50.0 per cent on February 22, 2007. The Company commenced consolidation of Great Lakes on a prospective basis effective February 22, 2007.

Principal Repayments

Principal repayments on the long-term debt of the Company are approximately as follow: 2008 – $556 million; 2009 – $1,002 million; 2010 – $617 million; 2011 – $805 million; and 2012 – $1,246 million.

Debt Shelf Programs

In March 2007, the Company filed debt shelf prospectuses in Canada and the U.S. qualifying for issuance $1.5 billion of Medium-Term Notes and US$1.5 billion of debt securities, respectively. At December 31, 2007, the Company had issued no Medium-Term Notes under the Canadian prospectus. In September 2007, the Company replaced the March 2007 U.S. debt shelf prospectus with a US$2.5-billion U.S. debt shelf prospectus. US$1.5 billion remains available under the U.S. debt shelf at December 31, 2007.

TransCanada PipeLines Limited

In October 2007, TCPL issued US$1.0 billion of Senior Unsecured Notes under the U.S. debt shelf prospectus filed in September 2007. These notes mature on October 15, 2037 and bear interest at a rate of 6.20 per cent. The effective interest rate at issuance was 6.30 per cent.

NOVA Gas Transmission Ltd.

Debentures issued by NOVA Gas Transmission Ltd. (NGTL) amount to $225 million and have retraction provisions that 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 were made at December 31, 2007.

On January 31, 2008, NGTL retired $105 million of 6.0 per cent Medium-Term Notes.

TransCanada PipeLine USA Ltd.

In February 2007, TransCanada PipeLine USA Ltd. established a US$1.0 billion committed, unsecured credit facility, consisting of a US$700-million five-year term loan and a US$300-million five-year, extendible revolving facility. A floating interest rate based on the three-month London Interbank Offered Rate (LIBOR) plus 22.5 basis points is charged on the balance outstanding and a facility fee of 7.5 basis points is charged on the entire facility. US$1.0 billion from this facility and an additional US$100 million from an existing demand line were used to partially finance the acquisitions of ANR and additional interest in Great Lakes and the Company's additional investment in PipeLines LP. There was an outstanding balance of US$860 million on the credit facility and nil on the demand line at December 31, 2007.

ANR Pipeline Company – Voluntary Withdrawal of Listing

In March 2007, ANR Pipeline Company (ANR Pipeline) voluntarily withdrew, from the New York Stock Exchange, the listing of its 9.625 per cent Debentures due 2021, 7.375 per cent Debentures due 2024, and 7.0 per cent Debentures due 2025. With the delisting, which became effective April 12, 2007, ANR Pipeline deregistered these securities with the U.S. Securities and Exchange Commission.

TC PipeLines, LP

In February 2007, PipeLines LP increased the size of its syndicated revolving credit and term loan facility in connection with its acquisition of a 46.4 per cent interest in Great Lakes. The amount available under the facility increased to US$950 million from US$410 million and consisted of a US$700-million senior term loan and a US$250-million senior revolving credit facility, with US$194 million of the senior term loan amount terminated upon closing of the Great Lakes acquisition. An additional US$18 million of the senior term loan was terminated due to a principal

98 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

payment made in November 2007. A floating interest rate based on the three-month LIBOR plus 55 basis points is charged on the senior term loan and a floating interest rate based on the one-month LIBOR plus 35 basis points is charged on the senior revolving credit facility. A facility fee of 10 basis points is charged on the US$250-million senior revolving credit facility.

Sensitivity

A one per cent change in interest rates would have the following effects assuming all other variables were to remain constant:

(millions of dollars)	Increase		Decrease
Effect on fair value of fixed interest rate debt	(1,023	)	1,185
Effect on interest expense of variable interest rate debt	7		(7	)

Financial Charges

Year ended December 31 (millions of dollars)	2007		2006		2005
Interest on long-term debt	986		849		849
Interest on junior subordinated notes	43
Interest on short-term debt	28		23		23
Capitalized interest	(68	)	(60	)	(24	)
Amortization and other financial charges(1)	(28	)	16		(11	)
	961		828		837

⁽¹⁾

Amortization and other financial charges in 2007 includes amortization of transaction costs and debt discounts calculated using the effective interest method.

The Company made interest payments of $944 million in 2007 (2006 – $771 million; 2005 – $838 million).

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 99

NOTE 10    LONG-TERM DEBT OF JOINT VENTURES

			2007		2006
Outstanding loan amounts (millions of dollars)		Maturity Dates	Outstanding December 31(1)	Interest Rate(2)(3)	Outstanding December 31(1)	Interest Rate(4)
NORTHERN BORDER PIPELINE COMPANY
Senior Unsecured Notes
	(2007 – US$232; 2006 – US$316)	2009 to 2021	229	7.7%	368	6.9%
Bank Facility
	(2007 – US$83)	2012	82	5.3%
IROQUOIS GAS TRANSMISSION SYSTEM, L.P.
Senior Unsecured Notes
	(2007 and 2006 – US$165)	2010 to 2027	162	7.4%	192	7.5%
Bank Loan
	(2007 – US$7; 2006 – US$15)	2008	7	7.4%	17	6.2%
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP(5)
Senior Unsecured Notes
	(2006 – US$225)		–		262	7.8%
BRUCE POWER L.P. AND BRUCE POWER A L.P.
Capital Lease Obligations		2018	243	7.5%	250	7.5%
TRANS QUÉBEC & MARITIMES PIPELINE INC.
Bonds		2009 to 2010	137	6.0%	138	6.0%
Term Loan		2011	28	4.6%	32	4.4%
Other		2008 to 2013	15	4.5%	19	3.8%
			903		1,278
Less: Current Portion of Long-Term Debt of Joint Ventures			30		142
			873		1,136

⁽¹⁾

Amounts outstanding represent TCPL's proportionate share.

⁽²⁾

Interest rates are the effective interest rates except those pertaining to long-term debt issued for TQM's regulated operations, in which case the weighted average interest rate is presented as required by the regulators.

⁽³⁾

Weighted average and effective interest rates are stated as at the respective outstanding dates. At December 31, 2007, the effective interest rate resulting from swap agreements were 7.5 per cent on the Iroquois bank loan (2006 – weighted average rate of 6.9 per cent).

⁽⁴⁾

Weighted average interest rates are stated at the respective outstanding dates.

⁽⁵⁾

TCPL increased its effective ownership in Great Lakes to 68.5 per cent from 50.0 per cent on February 22, 2007. The Company commenced consolidation of Great Lakes, on a prospective basis, effective February 22, 2007.

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. Other joint venture debt includes a demand loan secured by a first interest in all personal property, a floating charge over all real property and a demand collateral leasehold mortgage in the amount of $20 million creating a first fixed and specific charge over the joint venture's leasehold interest in all land and premises. TQM's Bonds are secured by a first interest in all TQM real and immoveable property and rights, a floating charge on all residual property and assets, and a specific interest on Bonds of TQM Finance Inc. and on rights under all licenses and permits relating to the TQM pipeline system and natural gas transportation agreements.

100 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 12 renewals thereafter is for a period of two years.

The Company's proportionate share of principal repayments resulting from maturities and sinking fund obligations of the non-recourse joint venture debt is approximately as follows: 2008 – $21 million; 2009 – $161 million; 2010 – $185 million; 2011 – $36 million; and 2012 – $95 million.

The Company's proportionate share of principal payments resulting from the capital lease obligations of Bruce Power is approximately as follows: 2008 – $9 million; 2009 – $11 million; 2010 – $13 million; 2011 – $15 million; and 2012 – $18 million.

In April 2007, Northern Border established a US$250-million five-year bank facility. A portion of the bank facility was drawn to refinance US$150 million of the Senior Unsecured Notes that matured on May 1, 2007, with the balance available to fund Northern Border's ongoing operations.

Sensitivity

A one per cent change in interest rates would have the following effects assuming all other variables were to remain constant:

(millions of dollars)	Increase		Decrease
Effect on fair value of fixed interest rate debt	(13	)	15
Effect on interest expense of variable interest rate debt	1		(1	)

Financial Charges of Joint Ventures

Year ended December 31 (millions of dollars)	2007	2006	2005
Interest on long-term debt	50	67	60
Interest on capital lease obligations	18	19	3
Short-term interest and other financial charges	4	3	1
Deferrals and amortization	3	3	2
	75	92	66

The Company's proportionate share of the interest payments of joint ventures was $45 million in 2007 (2006 – $73 million; 2005 – $62 million).

The Company's proportionate share of interest payments from the capital lease obligations of Bruce Power was $26 million in 2007 (2006 – $20 million; 2005 – $3 million).

NOTE 11    JUNIOR SUBORDINATED NOTES

			2007
Outstanding loan amount (millions of dollars)		Maturity Dates	Outstanding December 31	Effective Interest Rate
TRANSCANADA PIPELINES LIMITED
	U.S. dollars (2007 – US$1,000)	2017	975	6.5%

In April 2007, TCPL issued US$1.0 billion of Junior Subordinated Notes, maturing in 2067 and bearing interest of 6.35 per cent per year until May 15, 2017, when interest will convert to a floating rate, reset quarterly to the three-month LIBOR plus 221 basis points. The Company has the option to defer payment of interest for periods of up to ten years without giving rise to a default and without permitting acceleration of payment under the terms of the Junior Subordinated Notes. The Company would be prohibited from paying dividends during any deferral period. The Junior Subordinated Notes are subordinated in right of payment to existing and future senior indebtedness and are effectively subordinated to all indebtedness and obligations of TCPL. The Junior Subordinated Notes are callable at the Company's option at any time on or after May 15, 2017 at 100 per cent of the principal amount of the Junior Subordinated Notes plus accrued and unpaid interest to the date of redemption. The Junior Subordinated Notes are callable earlier upon the occurrence of certain events and at the Company's option, in whole or in part, at an amount equal to the greater of 100 per cent of the principal amount of the Junior Subordinated Notes plus accrued

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 101

and unpaid interest to the date of redemption and an amount determined by formula in accordance with the terms of the Junior Subordinated Notes. The Junior Subordinated Notes were issued under the U.S. shelf prospectus filed in March 2007.

Sensitivity

A one per cent change in interest rates would have the following effects assuming all other variables were to remain constant:

(millions of dollars)	Increase		Decrease
Effect on fair value of Junior Subordinated Notes	(61	)	66

NOTE 12    DEFERRED AMOUNTS

December 31 (millions of dollars)	2007	2006
Regulatory liabilities	525	386
Fair value of derivative contracts	205	254
Employee benefit plans	196	195
Asset retirement obligations	88	45
Hedging deferrals(1)	–	84
Other	93	65
	1,107	1,029

⁽¹⁾

Changes in GAAP required the Company to record the effective portion and changes in fair value of cash flow and fair value hedges in Other Comprehensive Income and Net Income, respectively, effective January 1, 2007. Prior to this date, the fair value of certain hedges was deferred and recognized in income when the financial instrument had settled.

NOTE 13    REGULATED BUSINESSES

Regulatory assets and liabilities represent future revenues that are expected to be recovered from or refunded to customers in future periods. They stem from the rate-setting process associated with certain costs and revenues, incurred in the current period or in prior periods and the under- or over-collection of revenues in the current or prior periods.

Canadian Regulated Operations

Canadian natural gas transmission services are supplied 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 set typically through a process that involves filing an application with the regulators for a change in rates. Regulated rates are underpinned by the total annual revenue requirement, which comprises 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 subject to a cost-of-service model wherein forecasted costs, including a return on capital, equal the revenues for the upcoming year. To the extent that actual costs are more or less than the forecasted costs, the regulators generally allow the difference to be deferred to a future period and recovered or refunded in revenues at that time. Costs for which the regulator does not allow the difference between actual and forecast to be deferred are included in the determination of net income in the year they are incurred.

The Canadian Mainline, Foothills and TQM pipelines are regulated by the NEB under the National Energy Board Act. At December 31, 2007, the Alberta System was regulated by the EUB primarily under the provisions of the Gas Utilities Act (Alberta) and the Pipeline Act (Alberta). The EUB was reorganized into the AUC and the Energy Resource Conservation Board effective January 1, 2008. The AUC regulates the Alberta System's construction and operation of facilities, and the terms and conditions of services, including rates. The NEB regulates the construction and operation of facilities, and the terms and conditions of services, including rates, for the Company's other Canadian regulated transmission systems.

102 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Canadian Mainline

In February 2007, TCPL reached a five-year tolls settlement with interested stakeholders for 2007 to 2011 on the Canadian Mainline. In May 2007, the NEB approved the application as filed, including TCPL's request that interim tolls for 2007 be made final. The terms of the settlement are effective January 1, 2007, to December 31, 2011.

As part of the settlement, TCPL and its stakeholders agreed that the cost of capital will reflect a rate of return on common equity (ROE) as determined by the NEB's ROE formula, on a deemed common equity ratio of 40 per cent, an increase from 36 per cent. The allowed ROE in 2007 for Canadian Mainline was 8.46 per cent. The remaining capital structure consists of short- and long-term debt following the agreed-upon redemption of the US$460-million Preferred Securities.

The settlement also established the Canadian Mainline's fixed operating, maintenance and administration (OM&A) costs for each year of the five years. Any variance between actual OM&A costs and those agreed to in the settlement will accrue to TCPL from 2007 to 2009. Variances in OM&A costs will be shared equally between TCPL and its customers in 2010 and 2011. All other cost elements of the revenue requirement will be treated on a flow-through basis. The settlement also allows for performance-based incentive arrangements that will provide mutual benefits to both TCPL and its customers.

Alberta System

The Alberta System operated 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 calculating the revenue requirement for all three years, based on the recovery of all cost components and the use of deferral accounts.

OM&A and certain other costs, including foreign exchange on interest payments, uninsured losses and amortization of severance costs, were fixed for each of the three years and any difference between actual and forecast fixed costs will be included in the determination of net income in the year they are incurred. Costs other than those that are fixed are forecast at the beginning of each year and included in calculating the revenue requirement. Any variance between forecasted and actual costs is 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 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 2007 was 8.51 per cent.

Other Canadian Pipelines

In February 2007, the NEB approved TCPL's application to integrate the BC System and Foothills and charge tolls based on the integrated structure. The two systems were integrated effective April 1, 2007, resulting in a transfer of BC System regulatory assets and liabilities to Foothills. The ROE for Foothills, which is based on the NEB-allowed-ROE formula established in the RH-2-94 Multi-Pipeline Cost of Capital proceeding, was 8.46 per cent in 2007 on a deemed equity component of 36 per cent.

The NEB approves pipeline tolls on an annual cost of service basis for Foothills and TQM, similar to the basis it uses to approve tolls on the Canadian Mainline. 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 the 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 calculated and reflected in the subsequent year's tolls.

TQM filed an application with the NEB in November 2007 for approval of a three-year partial negotiated settlement for the years 2007 to 2009. The partial settlement represents agreement on all cost of service matters for the three-year period, with the exception of cost of capital and associated income taxes. In December 2007, TQM filed a cost of capital application with the NEB for the years 2007 and 2008. The application requests approval of an 11 per cent return on deemed common equity of 40 per cent. TQM currently is subject to an NEB ROE formula on deemed common equity of 30 per cent. TQM tolls remain in effect on an interim basis pending a decision on the application. Any adjustments to the interim tolls will be recorded in accordance with the decision.

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, the Natural Gas Policy Act of 1978 and the Energy Project Act of 2005, 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.

ANR

ANR's operations are regulated primarily by the FERC. ANR's natural gas storage and transportation services that are regulated by the FERC also operate under approved tariff rates. ANR Pipeline's rates were established pursuant to a settlement approved by a FERC order issued in February 1998 and became effective in November 1997. These tariffs include maximum and minimum rate levels for services and permit ANR to discount or negotiate rates on a non-discriminatory basis. ANR Storage Company's rates were established pursuant to a settlement approved by the FERC in April 1990 and became effective in June 1990. None of ANR's FERC-regulated operations are required to file for new rates at any time in the future, nor are any of the operations prohibited from filing a case for new rates.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 103

GTN

GTN is regulated by the FERC. Both of GTN's systems, the GTN System and North Baja, operate in accordance with FERC-approved tariffs that establish maximum and minimum rates for various services. The pipelines are permitted to discount or negotiate these rates on a non-discriminatory basis. The GTN System filed a general rate case in June 2006 under the Natural Gas Act of 1938. The GTN System filed a Stipulation and Agreement with the FERC on November 1, 2007, that comprised an uncontested settlement of all aspects of its 2006 rate case. The FERC approved the settlement on January 7, 2008, and GTN's financial results in 2007 reflect the terms of the settlement. In 2008, the GTN System will refund to customers amounts collected above the settlement rates for the period from January 1, 2007 through October 31, 2007. Under the settlement, a five-year moratorium period was set in which the GTN System and the settling parties are prohibited from taking certain actions under the Natural Gas Act of 1938, including any filings. The GTN System is also required to file a rate case within seven years. Rates for capacity on North Baja were established in 2002 in the FERC's initial order certificating construction and operations of North Baja.

Great Lakes

Great Lakes' rates and tariffs are regulated by the FERC. In 2000, Great Lakes negotiated an overall rate settlement with its customers that established the current rates. The settlement expired October 31, 2005, with no requirement to file for new rates at any time in the future, nor is Great Lakes prohibited from filing such a rate case.

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 Section 4 of the Natural Gas Act of 1938, with a proposed effective date of April 1, 2008.

Northern Border

Northern Border and its customers reached a settlement in September 2006 that was approved by the FERC in November 2006. The settlement established maximum long-term mileage-based rates and charges for transportation on Northern Border's system. Beginning January 1, 2007, overall rates were reduced by approximately five per cent from the rates in effect prior to the filing. The settlement provided for seasonal rates, which vary on a monthly basis, for short-term transportation services. It also included a three-year moratorium on filing rate cases and on participants filing challenges to rates, and required that Northern Border file a general rate case within six years. Northern Border was required to provide services under negotiated and discounted rates on a non-discriminatory basis.

104 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Regulatory Assets and Liabilities

Year ended December 31 (millions of dollars)	2007	2006	Remaining Recovery/ Settlement Period
			(years)
Regulatory Assets
Operating and debt-service regulatory assets(1)	85		1
Unrealized losses on derivatives – Canadian Mainline(2)	63	44	1 - 3
Unrealized losses on derivatives – Foothills(2)	33	33	6
Unrealized losses on derivatives – Alberta System(2)	10	7	1 - 5
Foreign exchange on long-term debt principal – Alberta System(3)	34	33	22
Deferred income tax on carrying costs capitalized during construction of utility plant – ANR(4)	20		n/a
Unamortized issue costs on Preferred Securities – Canadian Mainline(5)	19		19
Phase II preliminary expenditures – Foothills(6)	18	20	8
Transitional other benefit obligations(7)	16	18	9
Unamortized post-retirement benefits – ANR(8)	13		4 - 6
Other	25	23	n/a
Total Regulatory Assets (Other Assets)	336	178
Regulatory Liabilities
Operating and debt-service regulatory liabilities(1)	3	70	1
Foreign exchange on long-term debt – Alberta System(9)	168	60	5 - 22
Foreign exchange on long-term debt – Canadian Mainline(9)	61	195	1 - 3
Foreign exchange on long-term debt – Foothills(9)	37	19	6
Foreign exchange gain on redemption of Preferred Securities, net of income tax of $15 million – Canadian Mainline(5)	150		4
Post-retirement benefits other than pension – ANR(10)	38		n/a
Fuel tracker – ANR(11)	29		n/a
Negative salvage – ANR(12)	17		n/a
Post-retirement benefits other than pension – GTN System(13)	–	19	4
Other	22	23	n/a
Total Regulatory Liabilities (Deferred Amounts)	525	386

⁽¹⁾

Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances approved by the regulatory authority for inclusion in the determination of tolls for the immediate following calendar year. In the absence of rate-regulated accounting, GAAP would have required the inclusion of variances resulting in a regulatory asset in the operating results of the year in which the variances were incurred. There is no difference between rate-regulated and GAAP accounting treatments if the variances yield a regulatory liability. Pre-tax operating results would have been $85 million lower in 2007 (2006 – no change) in the absence of rate-regulated accounting.

⁽²⁾

Unrealized losses on derivatives represent the net position of fair value gains and losses on cross-currency and interest-rate swaps, and forward currency contracts which act as economic hedges. The cross-currency swaps pertain to foreign debt instruments associated with the Canadian Mainline, Foothills and Alberta System. 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, GAAP would have required 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 would have been $19 million lower in 2007 (2006 – $1 million lower). The regulatory asset with respect to Foothills 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 of Foothills would have been the same in 2007 and 2006. The regulatory asset related to the Alberta System represents cross-currency swaps on foreign debt instruments and forward foreign currency contracts related to hedging foreign exchange risk inherent in contractual obligations to purchase materials for construction projects. In the absence of rate-regulated accounting, pre-tax operating results of the Alberta System would have been $3 million lower in 2007 (2006 – no change).

⁽³⁾

The foreign exchange on long-term debt principal 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 or loss on

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 105

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.

⁽⁴⁾

Rate-regulated accounting allows the capitalization of both an equity and an interest component for the carrying costs of funds used during the construction of utility assets. The capitalized Allowance for Funds Used During Construction (AFUDC) is depreciated as part of the total depreciable plant after the utility assets are placed in service. Equity AFUDC is not subject to income taxes, therefore, a deferred tax provision is recorded with an offset to a corresponding regulatory asset.

⁽⁵⁾

In July 2007, the Company redeemed the US$460-million 8.25 per cent Preferred Securities that underpinned the Canadian Mainline's investment base. Upon redemption of the securities, there was a realized foreign exchange gain that will flow through, net of income tax, to Canadian Mainline's customers over the five years of the settlement approved by the NEB in May 2007. In addition, the issue costs on the Preferred Securities will be amortized over 20 years beginning January 1, 2007. In the absence of rate-regulated accounting, GAAP would have required the foreign exchange gain and the unamortized issue costs to be included in the operating results of the Canadian Mainline in the year the securities were redeemed. This would have increased/(decreased) pre-tax operating results by $165 million and $(19) million arising from the foreign exchange gain and issue costs, respectively, in 2007.

⁽⁶⁾

Phase II preliminary expenditures are costs incurred by Foothills prior to 1981 related to development of Canadian facilities to deliver Alaskan gas. These costs 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 have required these costs to be expensed in the year incurred, increasing pre-tax operating results by $2 million in 2007 (2006 – $3 million higher).

⁽⁷⁾

The regulatory asset with respect to the annual transitional other benefit obligations is being amortized over 17 years, from January 1, 2000 to 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 $2 million higher in 2007 (2006 – $2 million higher).

⁽⁸⁾

An amount is recovered in ANR's rates for Post-retirement Benefits Other than Pensions (PBOP). A curtailment and special termination benefits charge related to PBOP for a closed group of retirees was recorded as a regulatory asset and is being amortized at a rate of $3 million per year through 2011. In the absence of rate-regulated accounting, pre-tax operating results would have been $3 million higher in 2007.

⁽⁹⁾

Foreign exchange on long-term debt of the Canadian Mainline, the Alberta System and Foothills represents the variance resulting from revaluing foreign currency-denominated debt instruments to the current foreign exchange rate from the historic foreign exchange rate. Foreign exchange gains and 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 of these unrealized gains or losses either on the balance sheet or income statement depending on whether the foreign debt is designated as a hedge of the Company's net investment in foreign assets.

⁽¹⁰⁾

An amount is recovered in ANR's rates for post-employment and post-retirement benefits. This regulatory liability represents the difference between the amount collected in rates and the amount of post-employment and post-retirement benefit expense.

⁽¹¹⁾

ANR's tariff stipulates a fuel tracker mechanism to track over- or under-collections of fuel used and lost and gas unaccounted for (collectively, fuel). The fuel tracker represents the difference between the value of 'in-kind' natural gas retained from shippers and the actual amount of natural gas used for fuel by ANR. Any over- or under-collections are returned to or collected from shippers through a prospective annual adjustment to fuel retention rates. A regulatory asset or liability is established for the difference between ANR's actual fuel use and amounts collected through its fuel rates. Pre-tax operating results are not affected by the fuel tracker mechanism.

⁽¹²⁾

ANR collects in its current rates an allowance for negative salvage related to its offshore transmission and gathering facilities. The allowance for negative salvage is collected as a component of depreciation expense and recorded to a negative salvage account within the reserve for accumulated depreciation. Costs associated with the abandonment of offshore transmission and with gathering facilities are recorded against the negative salvage reserve.

⁽¹³⁾

An amount was recovered for PBOP in the GTN System's rates under a 1996 rate case settlement. This regulatory liability represents the difference between the amount collected in rates and the amount of PBOP expense determined under GAAP. Under the terms of the 2007 settlement, the GTN System's PBOP regulatory liability is deemed to be nil and, as such, has been transferred to other deferred amounts. The December 31, 2006 balance is being amortized over five years.

As prescribed by regulators, the taxes payable method of accounting for income taxes is used for toll-making purposes on Canadian regulated natural gas transmission operations. As permitted by GAAP, this method is also used for accounting purposes, since there is a 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 rates. In the absence of rate-regulated accounting, GAAP would have required the recognition of future income tax liabilities. If the liability method of accounting had been used, additional future income tax liabilities of $1,138 million would have been recorded at December 31, 2007 (2006 – $1,355 million) and would have been recoverable from future revenues. In 2007, reductions in enacted Canadian federal and provincial corporate future income tax rates resulted in a decrease of $123 million to this unrecorded future income tax liability. The liability method of accounting is used for both accounting and toll-making purposes for the U.S. natural gas transmission operations.

106 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Under this method, future income tax assets and liabilities are recognized based on the differences between financial statement carrying amounts and the tax basis of the assets and liabilities. This method is also used for toll-making purposes for the U.S. natural gas transmission operations. As a result, current year's revenues include a tax provision that is calculated based on the liability method of accounting and there is no recognition of a related regulatory asset or liability.

NOTE 14    PREFERRED SECURITIES

In July 2007, TCPL exercised its right to redeem the US$460-million 8.25 per cent preferred securities due 2047. The preferred securities were redeemed for cash at par as part of the tolls settlement on the Canadian Mainline. The foreign exchange gain realized on redemption of the securities will flow through to the Canadian Mainline shippers over a five-year period, pursuant to the settlement.

NOTE 15    NON-CONTROLLING INTERESTS

The Company's non-controlling interests included in the consolidated balance sheet were as follows.

December 31 (millions of dollars)	2007	2006
Non-controlling interest in PipeLines LP	539	287
Other	71	79
	610	366

The Company's non-controlling interests included in the consolidated income statement are as follows.

Year ended December 31 (millions of dollars)	2007	2006	2005
Non-controlling interest in PipeLines LP	65	43	52
Other	10	13	10
	75	56	62

The non-controlling interest in PipeLines LP as at December 31, 2007, represented the 67.9 per cent interest not owned by TCPL (2006 – 86.6 per cent). Other non-controlling interests as at December 31, 2007, included the 38.3-per-cent (2006 – 38.3 per cent) non-controlling interest in Portland held by an unrelated partner.

TCPL received revenues of $2 million from PipeLines LP in 2007 (2006 – $1 million; 2005 – $1 million) and $7 million from Portland in 2007 (2006 – $6 million; 2005 – $6 million) for services it provided.

NOTE 16    PREFERRED SHARES

December 31	Number of Shares	Dividend Rate Per Share	Redemption Price Per Share	2007	2006
	(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.

The issuer may redeem at $50 per share the Series U shares on or after October 15, 2013, and the Series Y shares on or after March 5, 2014.

Dividend Reinvestment and Share Purchase Plan

In 2007, the Board of Directors of TransCanada Corporation (TransCanada) authorized the issuance of common shares from treasury at a discount of two per cent to participants in the TransCanada's Dividend Reinvestment and Share Purchase Plan (DRP). Eligible TCPL preferred shareholders may reinvest their dividends and make optional cash payments to obtain additional TransCanada common shares under the DRP. Commencing with the dividend payable in April 2007, the DRP shares are provided to the participants at a two per cent discount to the average market price in the five days before dividend payment. Previously, TransCanada purchased shares on the open market and provided them to DRP participants at cost. TransCanada reserves the right to alter the discount or return to purchasing shares on the open market at any time.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 107

NOTE 17    COMMON SHARES

		Number of Shares	Amount
		(thousands)	(millions of dollars)
Outstanding at January 1, 2005		480,668	4,632
	Issued for cash or cash equivalent	2,676	80
Outstanding at December 31, 2005 and 2006		483,344	4,712
	Issued for cash or cash equivalent	48,205	1,842
Outstanding at December 31, 2007		531,549	6,554

Common Shares Issued and Outstanding

The Company is authorized to issue an unlimited number of common shares without par value.

Share Capital

In 2007, TCPL issued 48.2 million common shares to TransCanada for proceeds of approximately $1.8 billion. Of this total, $1.5 billion was used towards financing the acquisitions of ANR and an additional interest in Great Lakes.

Restriction on Dividends

Certain terms of the Company's preferred shares, and debt instruments could restrict the Company's ability to declare dividends on preferred and common shares. At December 31, 2007, under the most restrictive provisions, approximately $1.5 billion (2006 – $1.9 billion) was available for the payment of dividends on common shares.

NOTE 18    RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

Risk Management Overview

TCPL has exposure to market, counterparty credit and liquidity risk. The risk management function assists in managing these risks. TCPL's primary risk management objective is to protect earnings and cash flow, and ultimately shareholder value.

Risk management strategies, policies and limits are designed to ensure TCPL's risks and related exposures are in line with the Company's business objectives and risk tolerance. Risks are managed within limits ultimately established by the Company's Board of Directors, implemented by senior management and monitored by risk management personnel. TCPL's Audit Committee oversees how management monitors compliance with risk management policies and procedures, and management's review of the adequacy of the risk management framework. Internal audit personnel assist the Audit Committee in its oversight role by performing regular and ad-hoc reviews of risk management controls and procedures, the results of which are reported to the Audit Committee.

Market Risk

The Company constructs and invests in large infrastructure projects, purchases and sells commodities, issues short- and long-term debt including amounts in foreign currencies, and invests in foreign operations. These activities expose the Company to market risk from changes in commodity prices, foreign exchange rates and interest rates, which affect the Company's earnings and the value of the financial instruments it holds.

The Company uses derivatives as part of its overall risk management policy to manage exposures to market risk that result from these activities.

Contracts used to manage market risk generally consist of the following:

•

Forwards and futures contracts – contractual agreements to purchase or sell a specific financial instrument or commodity at a specified price and date in the future. TCPL enters into foreign exchange and commodity forwards and futures to mitigate the impact of volatility in foreign exchange rates and commodity prices.

•

Swaps – contractual agreements between two parties to exchange streams of payments over time according to specified terms. The Company enters into interest rate, cross-currency and commodity swaps to mitigate the impact of changes in interest rates, foreign exchange rates and commodity prices.

108 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

•

Options – contractual agreements to convey the right, but not the obligation, for the purchaser to buy or sell a specific amount of a financial instrument or commodity at a fixed price, either at a fixed date or at any time within a specified period. The Company enters into option agreements to mitigate the impact of changes in interest rates, foreign exchange rates and commodity prices.

•

Heat rate contracts – contracts for the purchase or sale of power that are priced based on a natural gas index.

Commodity Price Risk

The Company is exposed to commodity price movements as part of its normal business operations, particularly in relation to the prices of power and natural gas. A number of strategies are used to mitigate these exposures, including the following:

•

The Company enters into offsetting or back-to-back physical positions and derivative financial instruments to manage market risk exposures created by certain fixed and variable pricing arrangements at different pricing indices and delivery points.



•

Subject to the Company's overall risk management policies, the Company commits a significant portion of its power supply to medium- or long-term sales contracts, while reserving an amount of unsold supply to maintain operational flexibility in the overall management of its asset portfolio.



•

The Company purchases a portion of the natural gas required for its gas-fired cogeneration plants or enters into heat-rate contracts that base the sales price of electricity on the cost of natural gas, effectively locking in a margin. A significant portion of the electricity needed to fulfill the Company's power requirements is purchased with forward contracts or fulfilled through power generation, thereby reducing the Company's exposure to fluctuating commodity prices.

The Company assesses its commodity contracts and derivative instruments used to manage energy commodity risk to determine the appropriate accounting treatment. Contracts, with the exception of leases, have been assessed to determine whether they meet the definition of a derivative. Certain commodity purchase and sale contracts are derivatives but are not within the scope of CICA Handbook Section 3855 "Financial Instruments – Recognition and Measurement", as they were entered into and continue to be held for the purpose of receipt or delivery in accordance with the Company's normal purchases and normal sales exemption. Certain other contracts are not within the scope of Section 3855 as they are considered to meet other exemptions.

TCPL manages its exposure to seasonal natural gas price spreads in its natural gas storage business by hedging storage capacity with a portfolio of third-party storage capacity leases and proprietary natural gas purchases and sales. By matching purchase and sale volumes, TCPL locks in a margin on a back-to-back basis and thereby effectively eliminates its exposure to natural gas market price fluctuations.

Natural Gas Inventory Price Risk

Effective April 1, 2007, TCPL began valuing its proprietary natural gas inventory held in storage at fair value, as measured by the one-month forward price for natural gas. At December 31, 2007, $190 million of proprietary natural gas inventory was included in Inventories. The amount recorded in 2007 in Revenues for the net change in the fair value of proprietary natural gas held in inventory was insignificant. A gain of $10 million was recorded in 2007 in Revenues for the net change in fair value of the forward proprietary natural gas purchase and sales contracts.

Foreign Exchange and Interest Rate Risk

Foreign exchange and interest rate risk is created by fluctuations in the fair values or cash flows of financial instruments due to changes in foreign exchange rates and/or changes in the market interest rates.

A portion of TCPL's earnings from its Pipelines and Energy operations outside of Canada is generated primarily in U.S. dollars and is subject to currency fluctuations. The performance of the Canadian dollar relative to the U.S. dollar could positively or negatively affect TCPL's earnings. This foreign exchange impact is offset by exposures in certain of TCPL's businesses and by the Company's hedging activities. Due to its growing operations in the U.S., including the acquisitions of ANR and increased ownership in Great Lakes and PipeLines LP, TCPL expects to have a greater exposure to U.S. dollar fluctuations than in prior years.

The Company uses foreign currency and interest rate derivatives to manage the foreign exchange and interest rate risks related to its U.S. dollar-denominated debt and other transactions, as well as to manage the interest rate exposures of the Canadian Mainline, Alberta System and Foothills. Certain of the realized gains and losses on these derivatives are shared with shippers on predetermined terms. These gains and losses are deferred as regulatory assets and liabilities until they are recovered from or paid to the shippers in accordance with the terms of the shipping agreements.

The Company has fixed-rate long-term debt, which subjects it to interest rate price risk, and has floating interest rate debt, which subjects it to interest rate cash flow risk. The Company uses a combination of forwards, interest rate swaps and options to manage its exposure to these risks.

Net Investment in Self-Sustaining Foreign Operations

The Company hedges its net investment in self-sustaining foreign operations on an after-tax basis with U.S. dollar-denominated debt, forward contracts, cross-currency interest rate swaps and options. The Company had designated U.S. dollar-denominated debt with a carrying value of $4.3 billion (US$4.4 billion) and a fair value of $4.4 billion (US$4.5 billion) as a net investment hedge at December 31, 2007. The forwards, swaps and options are recorded at their fair value and are included in Other Assets.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 109

The fair values and notional or principal amount for the derivatives designated as a net investment hedge were as follow:

		2007			2006
Asset/(Liability) December 31 (millions of dollars)		Fair Value		Notional or Principal Amount	Fair Value		Notional or Principal Amount
U.S. dollar cross-currency swaps
	(maturing 2009 to 2014)	77		U.S. 350	58		U.S. 400
U.S. dollar options
	(maturing 2008)	3		U.S. 600	(6	)	U.S. 500
U.S. dollar forward foreign exchange contracts
	(maturing 2008)	(4	)	U.S. 150	(7	)	U.S. 390
		76		U.S. 1,100	45		U.S. 1,290

VaR Analysis

TCPL uses a Value-at-Risk methodology (VaR) to estimate the potential impact resulting from its exposure to market risk. VaR estimates the potential change in pre-tax earnings over a given holding period for a specified confidence level. The VaR number calculated and used by TCPL reflects the 95 per cent probability that the daily change resulting from normal market fluctuations in its liquid positions will not exceed the reported VaR. VaR methodology is a statistically-defined, probability-based approach that takes into consideration market volatilities as well as risk diversification by recognizing offsetting positions and correlations between products and markets. Risks are measured across all products and markets, and risk measures can be aggregated to arrive at a single VaR number.

There is currently no uniform industry methodology for estimating VaR. The use of VaR has limitations because it is based on historical correlations and volatilities in commodity prices, interest rates and foreign exchange rates, and assumes that future price movements will follow a statistical distribution. Although losses are not expected to exceed the statistically estimated VaR on 95 per cent of occasions, losses on the other five per cent of occasions could be substantially greater than the estimated VaR.

TCPL's estimation of VaR includes wholly owned subsidiaries, and incorporates relevant risks associated with each market or business unit. The calculation does not include the Pipelines segment as the rate-regulated nature of the pipeline business reduces the impact of market risks and limits TCPL's ability to manage these risks. The Company's Board of Directors has established a VaR limit, which is monitored on an ongoing basis as part of the Company's risk management policy. TCPL's consolidated VaR was less than $10 million at December 31, 2007.

Counterparty Credit Risk

Counterparty credit risk represents the financial loss that the Company would experience if a counterparty to a financial instrument, in which the Company has an amount owing from the counterparty, failed to meet its obligations in accordance with the terms and conditions of its contracts with the Company.

Counterparty credit risk is mitigated through established credit management techniques, including conducting financial and other assessments to establish and monitor a counterparty's creditworthiness, setting exposure limits, monitoring exposures against these limits, utilizing master netting arrangements and obtaining financial assurances where warranted. In general, financial assurances include guarantees, letters of credit and cash. The Company monitors and manages its concentration of counterparty credit risk on an ongoing basis.

TCPL's maximum counterparty credit exposure at the balance sheet date consists primarily of the carrying amount of non-derivative financial assets as well as the fair value of derivative financial assets.

The Company has contracts for the sale of non-financial items. Many of these contracts do not meet the definition of a financial instrument since the underlying volumes are physically delivered during the Company's normal course of business. Exposure to counterparty credit risk on these non-financial contracts results from the potential of a counterparty defaulting on invoiced amounts owing to TCPL. These invoiced amounts are included in the Accounts Receivable and Other Assets amounts disclosed in the Non-Derivative Financial Instruments Summary table presented later in this Note. Some of these non-financial contracts do meet the definition of a derivative and are recorded at fair value.

The carrying amounts and fair values of financial assets and non-financial derivatives are disclosed in the Non-Derivative Financial Instruments Summary and the Derivative Financial Instruments Summary tables presented later in this Note.

The Company does not have any significant concentrations of counterparty credit risk and the majority of the counterparty credit exposure is with counterparties who are investment grade.

The Company has reached agreements for allowed unsecured claims with certain subsidiaries of Calpine Corporation (Calpine), former shippers on TCPL's pipeline systems that have filed for bankruptcy protection, as discussed in Note 27.

110 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Liquidity Risk

Liquidity risk is the risk that TCPL will not be able to meet its financial obligations as they fall due. The Company's approach to managing liquidity risk is to ensure that it always has sufficient cash and credit facilities to meet its obligations when due, under both normal and stressed conditions, without incurring unacceptable losses or damage to the Company's reputation.

Management typically forecasts cash flows for a period of 12 months to identify financing requirements. These requirements are then addressed through a combination of committed and demand credit facilities and access to capital markets, as discussed in the Capital Management section in this Note.

The following tables detail the remaining contractual maturities for TCPL's non-derivative financial liabilities, including both the principal and interest cash flows at December 31, 2007:

Contractual Repayments of Financial Liabilities

		Payments Due by Period
December 31, 2007 (millions of dollars)	Total	2008	2009 to 2010	2011 to 2012	2013 and Thereafter
Notes payable	55	55	–	–	–
Long-term debt and junior subordinated notes	13,908	556	1,619	2,051	9,682
Long-term debt of joint ventures	903	30	370	164	339
Total contractual repayments	14,866	641	1,989	2,215	10,021

Interest Payments on Financial Liabilities

		Payments Due by Period
December 31, 2007 (millions of dollars)	Total	2008	2009 to 2010	2011 to 2012	2013 and Thereafter
Interest payments on long-term debt and junior subordinated notes	11,566	895	1,636	1,464	7,571
Interest payments on long-term debt of joint ventures	332	55	85	53	139
Total interest payments	11,898	950	1,721	1,517	7,710

Capital Management

The primary objective of capital management is to ensure TCPL's strong credit rating is maintained to support its businesses and maximize shareholder value. This overall objective and policy for managing capital remained unchanged in 2007 from the prior year.

TCPL manages its capital structure in a manner consistent with the risk characteristics of the underlying assets. The Company's management considers its capital structure to consist of net debt, Non-Controlling Interests and Shareholder's Equity. Net debt is comprised of Notes Payable, Long-Term Debt, Junior Subordinated Notes and Preferred Securities less Cash and Cash Equivalents. Net debt only includes obligations that the Company controls and manages. Consequently, it does not include Cash and Cash Equivalents, Notes Payable and Long-Term Debt of TCPL's joint ventures.

The capital structure at December 31, 2007 was as follows:

(millions of dollars)
Notes payable	41
Long-term debt	12,933
Junior subordinated notes	975
Cash and cash equivalents	(333	)
Net debt	13,616
Non-controlling interests	610
Shareholder's equity	10,053
Total equity	10,663
Total capital	24,279

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 111

Fair Values

The fair value of Cash and Cash Equivalents and Notes Payable approximates their carrying amounts due to the short time period to maturity.

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.

Fair values of financial instruments are determined by reference to quoted bid or asking price, as appropriate, in active markets at period-end dates. In the absence of an active market, the Company determines fair value by using valuation techniques that refer to observable market data or estimated market prices. These include comparisons with similar instruments that have observable market prices, option pricing models and other valuation techniques commonly used by market participants. Fair values determined using valuation models require the use of assumptions about the amount and timing of estimated future cash flows and discount rates. In making these assumptions, the Company looks primarily to readily observable external market input factors such as interest rate yield curves, currency rates, and price and rate volatilities as applicable.

The fair value of the Company's Long-Term Debt was estimated based on quoted market prices for the same or similar debt instruments and, when such information was not available, by discounting future payments of interest and principal at estimated interest rates that were made available to the Company at December 31, 2007. The fair value of Preferred Securities was determined using market prices for the same or similar issues.

Fair Value of Long-Term Debt and Other Long-Term Securities

The carrying and fair values of long-term debt and other long-term securities were as follow:

	2007		2006
December 31 (millions of dollars)	Carrying Amount	Fair Value	Carrying Amount	Fair Value
Long-Term Debt
TransCanada PipeLines Limited(1)	8,519	9,400	8,549	9,738
NOVA Gas Transmission Ltd.	1,508	1,877	1,648	2,111
TransCanada PipeLine USA Ltd.	850	850	–	–
ANR Pipeline Company	435	573
Gas Transmission Northwest Corporation	399	383	466	450
TC PipeLines, LP	499	499	463	463
Great Lakes Gas Transmission Limited Partnership	434	519	–	–
Tuscarora Gas Transmission Company	67	81	86	94
Portland Natural Gas Transmission System	205	214	263	265
Other	17	24	28	28
	12,933	14,420	11,503	13,149
Junior Subordinated Notes	975	914
	13,908	15,334	11,503	13,149
Long-Term Debt of Joint Ventures
Northern Border Pipeline Company	311	329	368	363
Iroquois Gas Transmission System, L.P.	169	180	209	230
Great Lakes Gas Transmission Limited Partnership	–	–	262	258
Bruce Power L.P. and Bruce Power A L.P.	243	243	250	249
Trans Québec & Maritimes Pipeline Inc.	165	169	171	177
Other	15	16	18	18
	903	937	1,278	1,295
	14,811	16,271	12,781	14,444
Preferred Securities	–	–	536	532

⁽¹⁾

Carrying amount of Long-Term Debt increased $15 million for fair value adjustments of swap agreements on $150 million and US$200 million of debt.

112 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Non-Derivative Financial Instruments Summary

The carrying and fair values of non-derivative financial instruments were as follow:

December 31, 2007 (millions of dollars)	Carrying Amount	Fair Value
Financial Assets(1)
Cash and cash equivalents	504	504
Accounts receivable and other assets(2)(3)	1,231	1,231
Available-for-sale assets(2)	17	17
	1,752	1,752
Financial Liabilities(1)(3)
Notes payable	55	55
Accounts payable and deferred amounts(4)	1,452	1,452
Long-term debt and junior subordinated notes	13,908	15,334
Long-term debt of joint ventures	903	937
Other long-term liabilities of joint ventures(4)	60	60
	16,378	17,838

⁽¹⁾

Consolidated Net Income in 2007 included unrealized gains or losses of nil for the fair value adjustments to each of these financial instruments.

⁽²⁾

The Consolidated Balance Sheet included financial assets of $1,018 million in Accounts Receivable and $230 million in Other Assets at December 31, 2007.

⁽³⁾

Recorded at amortized cost, except for Long-Term Debt adjusted to fair value as noted in Note 9.

⁽⁴⁾

The Consolidated Balance Sheet included financial liabilities of $1,434 million in Accounts Payable and $78 million in Deferred Amounts at December 31, 2007.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 113

Derivative Financial Instruments Summary

Information for the Company's derivative financial instruments is as follows:

			2007
December 31 (all amounts in millions unless otherwise indicated)			Power		Natural Gas		Foreign Exchange		Interest
Derivative Financial Instruments Held for Trading
Fair Values(1)
	Assets		$55		$43		$11		$23
	Liabilities		$(44	)	$(19	)	$(79	)	$(18	)
Notional Values
	Volumes(2)
		Purchases	3,774		47		–		–
		Sales	4,469		64		–		–
	Canadian dollars		–		–		–		615
	U.S. dollars		–		–		U.S. 484		U.S. 550
	Japanese yen (in billions)		–		–		JPY 9.7		–
	Cross-currency		–		–		227/U.S. 157		–
Unrealized gains/(losses) in the period(3)			$16		$(10	)	$8		$(5	)
Realized (losses)/gains in the period(3)			$(8	)	$47		$39		$5
Maturity dates			2008 - 2016		2008 - 2010		2008 - 2012		2008 - 2016
Derivative Financial Instruments in Hedging Relationships(4)(5)
Fair Values(1)
	Assets		$135		$19		$ –		$2
	Liabilities		$(104	)	$(7	)	$(62	)	$(16	)
Notional Values
	Volumes(2)
		Purchases	7,362		28		–		–
		Sales	16,367		4		–		–
	Canadian dollars		–		–		–		150
	U.S. dollars		–		–		U.S. 113		U.S. 875
	Cross-currency		–		–		136/U.S. 100		–
Realized (losses)/gains in the period(3)			$(29	)	$18		$ –		$3
Maturity dates			2008 - 2013		2008 - 2010		2008 - 2013		2008 - 2013

⁽¹⁾

Fair value is equal to the carrying value of these derivatives.

⁽²⁾

Volumes for power and natural gas derivatives are in gigawatt hours and billion cubic feet, respectively.

⁽³⁾

All realized and unrealized gains and losses are included in Net Income. Realized gains are included in Net Income after the financial instrument has been settled.

⁽⁴⁾

All hedging relationships are designated as cash flow hedges except for $2 million of interest-rate derivative financial instruments designated as fair value hedges.

⁽⁵⁾

Net Income in 2007 included gains of $7 million for the changes in fair value of power and natural gas cash flow hedges that were ineffective in offsetting the change in fair value of their related underlying positions. Net Income in 2007 included a loss of $4 million for the changes in fair value of an interest-rate cash flow hedge that was reclassified as a result of discontinuance of cash flow hedge accounting. The cash flow hedge accounting was discontinued when the anticipated transaction was not probable of occurring by the end of the originally specified time period.

114 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Balance Sheet Presentation of Derivative Financial Instruments

The fair values of the derivative financial instruments in the Company's Balance Sheet were as follow:

December 31 (millions of dollars)		2007
Current
	Other current assets	160
	Accounts payable	(144	)
Long-term
	Other assets	204
	Deferred amounts	(205	)

Derivative Financial Instruments of Joint Ventures

Included in the Balance Sheet Presentation of Derivatives Financial Instruments table above are amounts related to power derivatives used by certain of the Company's joint ventures to manage commodity price risk. The Company's proportionate share of the fair value of these power sales derivatives was $75 million at December 31, 2007. These contracts mature from 2008 to 2013. The Company's proportionate share of the notional sales volumes of power associated with this exposure was 7,300 gigawatt hours (GWh) at December 31, 2007. The Company's proportionate share of the notional purchased volumes of power associated with this exposure was 50 GWh at December 31, 2007.

NOTE 19    INCOME TAXES

Provision for Income Taxes

Year ended December 31 (millions of dollars)	2007	2006	2005
Current
Canada	364	263	499
Foreign	65	37	51
	429	300	550
Future
Canada	8	104	(46	)
Foreign	46	71	106
	54	175	60
	483	475	610

Geographic Components of Income

Year ended December 31 (millions of dollars)	2007	2006	2005
Canada	1,208	1,158	1,315
Foreign	582	444	587
Income from continuing operations before income taxes and non-controlling interests	1,790	1,602	1,902

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 115

Reconciliation of Income Tax Expense

Year ended December 31 (millions of dollars)	2007		2006		2005
Income from continuing operations before income taxes and non-controlling interests	1,790		1,602		1,902
Federal and provincial statutory tax rate	32.1%		32.5%		33.6%
Expected income tax expense	575		521		639
Income tax differential related to regulated operations	69		72		71
(Lower)/higher effective foreign tax rates	(39	)	–		2
Tax rate and legislated changes	(73	)	(33	)	–
Income from equity investments and non-controlling interests	(34	)	(27	)	(29	)
Non-taxable portion of gains on sale of assets	(3	)	–		(68	)
Large corporations tax	–		–		15
Other(1)	(12	)	(58	)	(20	)
Actual income tax expense	483		475		610

⁽¹⁾

Includes income tax benefits of $13 million recorded in 2007 on the resolution of certain income tax matters with taxation authorities and changes in estimates (2006 – $51 million).

Future Income Tax Assets and Liabilities

December 31 (millions of dollars)	2007	2006
Deferred amounts	43	65
Other post-employment benefits	57	45
Unrealized losses on derivatives	22	–
Other	63	53
	185	163
Less: valuation allowance	13	14
Future income tax assets, net of valuation allowance	172	149
Difference in accounting and tax bases of plant, equipment and PPAs	1,073	768
Investments in subsidiaries and partnerships	61	113
Pension benefits	50	59
Unrealized foreign exchange gains on long-term debt	110	39
Unrealized gains on derivatives	27	–
Other	44	46
Future income tax liabilities	1,365	1,025
Net future income tax liabilities	1,193	876

Unremitted Earnings of Foreign Investments

Income taxes have not been provided on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future. Future income tax liabilities would have increased by approximately $72 million at December 31, 2007 (2006 – $72 million) if there had been a provision for these taxes.

Income Tax Payments

Income tax payments of $440 million were made during the year ended December 31, 2007 (2006 – $494 million; 2005 – $531 million).

116 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 20    NOTES PAYABLE

	2007		2006
	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	55	5.0%	467	4.3%

Notes Payable consists of commercial paper outstanding and drawings on bridge and line-of-credit facilities. Total unsecured revolving and demand credit facilities of $2.9 billion were available at December 31, 2007 to support the Company's commercial paper program and for general corporate purposes. These credit facilities include the following:

•

in December 2007, the $1.5 billion committed five-year term syndicated credit facility was increased to $2.0 billion and extended to December 2012. The cost to maintain the credit facility was $2 million in 2007 (2006 – $2 million).



•

at December 31, 2007, a US$300 million five-year, extendible revolving facility was available, which is part of the US$1.0 billion TransCanada PipeLine USA Ltd. credit facility discussed in Note 9.



•

the Company also has in place $600 million of demand lines, which support the issuance of letters of credit and provide additional liquidity. The Company had used approximately $334 million of its total lines of credit for letters of credit at December 31, 2007. When 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.

NOTE 21    ASSET RETIREMENT OBLIGATIONS

The estimated undiscounted cash flows required to settle the asset retirement obligations with respect to the regulated and non-regulated operations in the Pipelines segment were $65 million at December 31, 2007 (2006 – $39 million), calculated using an inflation rate ranging from two to three per cent per annum. The estimated fair value of these liabilities was $25 million at December 31, 2007 (2006 – $9 million) after discounting the estimated cash flows at rates ranging from 5.4 per cent to 8.0 per cent. At December 31, 2007, the expected timing of payment for settlement of the obligations ranged from one to 27 years.

The estimated undiscounted cash flows required to settle the asset retirement obligations with respect to the Energy segment were $216 million at December 31, 2007 (2006 – $162 million), calculated using an inflation rate ranging from two to three per cent per annum. The estimated fair value of this liability was $63 million at December 31, 2007 (2006 – $36 million) after discounting the estimated cash flows at rates ranging from 5.4 per cent to 6.6 per cent. At December 31, 2007, the expected timing of payment for settlement of the obligations ranges from 11 to 32 years.

Reconciliation of Asset Retirement Obligations⁽¹⁾

(millions of dollars)	Pipelines		Energy		Total
Balance at January 1, 2005	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
New obligations and revisions in estimated cash flows	14		25		39
Accretion expense	2		2		4
Balance at December 31, 2007	25		63		88

⁽¹⁾

Asset Retirement Obligations are included in Deferred Amounts.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 117

NOTE 22    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 Price 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 DC Plans and 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 was approximately 14 years at December 31, 2007. Contributions to DC Plans are expensed as incurred.

The Company expensed $8 million in 2007 (2006 – $2 million; 2005 – $2 million) related to retirement savings plans for its U.S. employees.

Total cash payments for employee future benefits, consisting of cash contributed by the Company to the DB Plans and other benefit plans, was $61 million in 2007 (2006 – $104 million; 2005 – $74 million).

The Company measures its accrued benefit obligations and the fair value of plan assets for accounting purposes as at December 31 of each year. The most recent actuarial valuation of the pension plans for funding purposes was as at January 1, 2008, and the next required valuation will be as at January 1, 2009.

		Pension Benefit Plans				Other Benefit Plans
(millions of dollars)		2007		2006		2007		2006
Change in Benefit Obligation
	Benefit obligation – beginning of year	1,378		1,282		132		148
	Current service cost	45		39		2		3
	Interest cost	73		65		7		8
	Employee contributions	4		3		–		–
	Benefits paid	(65	)	(64	)	(7	)	(7	)
	Actuarial (gain)/loss	(22	)	53		8		(2	)
	Foreign exchange rate changes	(16	)	–		(6	)	–
	Plan amendment	–		–		–		(18	)
	Acquisition	65		–		19		–
	Benefit obligation – end of year	1,462		1,378		155		132
Change in Plan Assets
	Plan assets at fair value – beginning of year	1,264		1,096		33		27
	Actual return on plan assets	33		134		2		6
	Employer contributions	46		95		7		7
	Employee contributions	4		3		–		–
	Benefits paid	(65	)	(64	)	(7	)	(7	)
	Foreign exchange rate changes	(17	)	–		(5	)	–
	Acquisition	93		–		–		–
	Plan assets at fair value – end of year	1,358		1,264		30		33
Funded status – plan deficit		(104	)	(114	)	(125	)	(99	)
Unamortized net actuarial loss		299		291		44		39
Unamortized past service costs		28		32		7		(12	)
Accrued benefit asset/(liability), net of valuation allowance of nil		223		209		(74	)	(72	)

118 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The accrued benefit asset/(liability) in the Company's balance sheet was as follows:

	Pension Benefit Plans			Other Benefit Plans
(millions of dollars)	2007	2006		2007		2006
Other Assets	223	230		5		5
Deferred Amounts	–	(21	)	(79	)	(77	)
Total	223	209		(74	)	(72	)

Included in the above benefit obligation and fair value of plan assets at December 31 were the following amounts for plans that are not fully funded:

	Pension Benefit Plans				Other Benefit Plans
(millions of dollars)	2007		2006		2007		2006
Benefit obligation	(1,324	)	(1,359	)	(155	)	(102	)
Plan assets at fair value	1,198		1,243		30		–
Funded status – plan deficit	(126	)	(116	)	(125	)	(102	)

The Company's expected contributions in 2008 are approximately $60 million for the pension benefit plans and approximately $14 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
2008	65	7
2009	68	7
2010	71	8
2011	74	9
2012	78	9
2013 to 2017	447	54

The significant weighted average actuarial assumptions adopted in measuring the Company's benefit obligations at December 31 were as follow:

	Pension Benefit Plans		Other Benefit Plans
	2007	2006	2007	2006
Discount rate	5.30%	5.00%	5.50%	5.20%
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 were as follow:

	Pension Benefit Plans			Other Benefit Plans
	2007	2006	2005	2007	2006	2005
Discount rate	5.05%	5.00%	5.75%	5.20%	5.15%	6.00%
Expected long-term rate of return on plan assets	6.90%	6.90%	6.90%	7.75%	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 the portfolio in aggregate and for each asset class in the portfolio. Assumed projected rates of return are selected after analyzing historical experience and estimating future levels and volatility of returns. Asset class benchmark returns, asset mix and anticipated benefit payments from plan assets are also

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 119

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.

A nine per cent annual rate of increase in the per-capita cost of covered health care benefits was assumed for 2008 measurement purposes. The rate was assumed to decrease gradually to five per cent in 2016 and remain at this level thereafter. A one percentage point change 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	1	(1	)
Effect on post-employment benefit obligation	14	(12	)

The Company's net benefit cost is as follows.

	Pension Benefit Plans						Other Benefit Plans
Year ended December 31 (millions of dollars)	2007		2006		2005		2007		2006		2005
Current service cost	45		39		32		2		3		3
Interest cost	73		65		63		7		8		7
Actual return on plan assets	(33	)	(134	)	(119	)	(2	)	(6	)	(2	)
Actuarial (gain)/loss	(22	)	53		149		8		(2	)	21
Plan amendment	–		–		–		–		(18	)	–
Elements of net benefit cost prior to adjustments to recognize the long-term nature of net benefit cost	63		23		125		15		(15	)	29
Difference between expected and actual return on plan assets	(51	)	63		54		(1	)	4		–
Difference between actuarial (gain)/loss recognized and actual actuarial (gain)/ loss on accrued benefit obligation	47		(27	)	(131	)	(7	)	4		(20	)
Difference between amortization of past service costs and actual plan amendments	4		4		3		–		19		1
Amortization of transitional obligation related to regulated business	–		–		–		2		2		2
Net benefit cost recognized	63		63		51		9		14		12

The Company pension plans' weighted average asset allocations and weighted average target allocations by asset category were as follow:

	Percentage of Plan Assets		Target Allocation
December 31 Asset Category	2007	2006	2007
Debt securities	42%	40%	35% to 60%
Equity securities	58%	60%	40% to 65%
	100%	100%

Debt securities included the Company's debt of $4 million (0.3 per cent of total plan assets) and $4 million (0.3 per cent of total plan assets) at December 31, 2007 and 2006, respectively. Equity securities included the Company's common shares of $6 million (0.4 per cent of total plan assets) and $6 million (0.5 per cent of total plan assets) at December 31, 2007 and 2006, 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.

120 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Employee Future Benefits of Joint Ventures

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 following amounts in this note, including those in the tables, represent TCPL's proportionate share with respect to these plans.

Total cash payments for employee future benefits, consisting of cash contributed by the Company's joint ventures to DB Plans and other benefit plans was $34 million in 2007 (2006 – $25 million; 2005 – $4 million).

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 at January 1, 2008, and the next required valuations will be as at January 1, 2009.

		Pension Benefit Plans				Other Benefit Plans
(millions of dollars)		2007		2006		2007		2006
Change in Benefit Obligation
	Benefit obligation – beginning of year	807		679		169		81
	Current service cost	28		24		10		7
	Interest cost	40		37		8		5
	Employee contributions	5		5		–		–
	Benefits paid	(23	)	(15	)	(2	)	(2	)
	Actuarial (gain)/loss	(34	)	77		(16	)	72
	Foreign exchange rate changes	(3	)	–		–		–
	Acquisition	(31	)	–		(2	)	–
	Plan amendment	–		–		(2	)	6
	Benefit obligation – end of year	789		807		165		169
Change in Plan Assets
	Plan assets at fair value – beginning of year	666		585		–		–
	Actual return on plan assets	(1	)	68		–		–
	Employer contributions	32		23		2		2
	Employee contributions	5		5		–		–
	Benefits paid	(23	)	(15	)	(2	)	(2	)
	Foreign exchange rate changes	(5	)	–		–		–
	Acquisition	(48	)	–		–		–
	Plan assets at fair value – end of year	626		666		–		–
Funded status – plan deficit		(163	)	(141	)	(165	)	(169	)
Unamortized net actuarial loss		169		174		45		66
Unamortized past service costs		–		–		3		6
Accrued benefit asset/(liability), net of valuation allowance of nil		6		33		(117	)	(97	)

The accrued benefit asset/(liability), net of valuation allowance of nil in the Company's balance sheet was as follows:

	Pension Benefit Plans		Other Benefit Plans
(millions of dollars)	2007	2006	2007		2006
Other assets	6	33	–		–
Deferred amounts	–	–	(117	)	(97	)
Total	6	33	(117	)	(97	)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 121

The following amounts were included at December 31 in the above benefit obligation and fair value of plan assets for plans that are not fully funded:

	Pension Benefit Plans				Other Benefit Plans
(millions of dollars)	2007		2006		2007		2006
Benefit obligation	(786	)	(773	)	(165	)	(169	)
Plan assets at fair value	623		609		–		–
Funded status – plan deficit	(163	)	(164	)	(165	)	(169	)

The expected contributions of the Company's joint ventures in 2008 are approximately $31 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
2008	26	3
2009	30	4
2010	33	5
2011	37	5
2012	41	6
2013 to 2017	263	39

The significant weighted average actuarial assumptions adopted in measuring the benefit obligations of the Company's joint ventures at December 31 were as follow:

	Pension Benefit Plans		Other Benefit Plans
	2007	2006	2007	2006
Discount rate	5.25%	5.05%	5.15%	4.95%
Rate of compensation increase	3.50%	3.50%

The significant weighted average actuarial assumptions adopted in measuring the net benefit plan costs of the Company's joint ventures for years ended December 31 were as follow:

	Pension Benefit Plans			Other Benefit Plans
	2007	2006	2005	2007	2006	2005
Discount rate	5.00%	5.25%	6.20%	4.90%	5.15%	6.25%
Expected long-term rate of return on plan assets	7.00%	7.30%	7.40%
Rate of compensation increase	3.50%	3.50%	3.50%

A one percentage point change 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	23	(20	)

122 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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)	2007		2006		2005		2007		2006		2005
Current service cost	28		24		4		10		7		1
Interest cost	40		37		7		8		5		1
Actual return on plan assets	1		(68	)	(18	)	–		–		–
Actuarial (gain)/loss	(34	)	77		17		(16	)	72		2
Plan amendment	–		–		–		(2	)	6		–
Elements of net benefit cost prior to adjustments to recognize the long-term nature of net benefit cost	35		70		10		–		90		4
Difference between expected and actual return on plan assets	(44	)	26		9		–		–		–
Difference between actuarial (gain)/loss recognized and actual actuarial (gain)/loss on accrued benefit obligation	44		(70	)	(16	)	20		(72	)	(3	)
Difference between amortization of past service costs and actual plan amendments	–		–		–		3		(6	)	–
Net benefit cost recognized related to joint ventures	35		26		3		23		12		1

The weighted average asset allocations and weighted average target allocation by asset category in the pension plans of the Company's joint ventures were as follow:

	Percentage of Plan Assets		Target Allocation
December 31 Asset Category	2007	2006	2007
Debt securities	43%	29%	40%
Equity securities	57%	71%	60%
	100%	100%

Debt securities included the Company's debt 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, 2007 and 2006, respectively. Equity securities included the Company's common shares of $3 million (0.5 per cent of total plan assets) and $6 million (1.0 per cent of total plan assets) at December 31, 2007 and 2006, 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 23    CHANGES IN OPERATING WORKING CAPITAL

Year ended December 31 (millions of dollars)	2007		2006		2005
Decrease/(increase) in accounts receivable	49		(186	)	(100	)
Increase in inventories	(6	)	(108	)	(50	)
Decrease/(increase) in other current assets	118		(6	)	(1	)
Increase/(decrease) in accounts payable	64		(41	)	98
(Decrease)/increase in accrued interest	(10	)	41		5
	215		(300	)	(48	)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 123

NOTE 24    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
2008	62	(13	)	49
2009	58	(12	)	46
2010	57	(12	)	45
2011	61	(10	)	51
2012	61	(6	)	55
2013 and thereafter	848	(13	)	835
Total	1,147	(66	)	1,081

The operating lease agreements for premises, services and equipment expire at various dates through 2021, with an option to renew certain lease agreements for one to ten years. The operating lease agreement for the natural gas storage facility expires in 2030. The lessee has the right to terminate the agreement on anniversary dates five years apart commencing in 2010, and the lessor has the right to terminate the agreement on the same schedule commencing in 2015. Net rental expense on operating leases in 2007 was $34 million (2006 – $25 million; 2005 – $17 million).

TCPL's commitments under the Alberta PPAs are considered to be operating leases and a portion of these PPAs have been subleased to third parties under similar terms and conditions. Future payments under these PPAs have been excluded from the above table, as these payments are dependent upon plant availability, among other things. The amount of power purchased under the PPAs in 2007 was $440 million (2006 – $499 million; 2005 – $230 million). The generating capacities and expiry dates of the PPAs are as follow:

	Megawatts	Expiry Date
Sheerness	756	December 31, 2020
Sundance A	560	December 31, 2017
Sundance B	353	December 31, 2020

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 transacted at market prices and in the normal course of business.

Bruce Power

Bruce A has signed commitments to third-party suppliers related to refurbishing and restarting Units 1 and 2 and refurbishing Units 3 and 4 to extend their operating life. TCPL's share of these signed commitments, which extend over the four-year period ending December 31, 2011, are as follow:

Year ended December 31 (millions of dollars)
2008	360
2009	151
2010	69
2011	14
	594

Aboriginal Pipeline Group

On June 18, 2003, the Mackenzie Delta gas producers, the APG and TCPL reached an agreement governing TCPL's role in the Mackenzie Gas Pipeline (MGP) project to build a natural gas pipeline from Inuvik, Northwest Territories, to the northern border of Alberta, where it would connect with the Company's Alberta System. Under the agreement, TCPL agreed to finance the APG for its one-third share of project pre-development costs. These costs are currently forecasted to be between $150 million and $200 million, depending on the pace of project development. As at December 31, 2007, the Company had advanced $137 million of this total.

124 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

TCPL and the other co-venture companies involved in the MGP continue to pursue approval of the proposed project, focusing on the regulatory process and discussions with the Canadian government on the fiscal framework. Project timing is uncertain and is conditional upon resolution of regulatory and fiscal matters. TCPL's ability to recover its investment depends on the successful outcome of the project.

Other Commitments

TCPL is committed to capital expenditures of approximately $1.6 billion related to its share of the construction costs of the Keystone oil pipeline and other pipeline projects.

The Company is committed to capital expenditures of approximately $608 million related to its share of the construction costs of the Halton Hills, Portlands Energy and remaining Cartier Wind projects.

Contingencies

The Canadian Alliance of Pipeline Landowners' Associations (CAPLA) and two individual landowners commenced an action in 2003 against TCPL and Enbridge Inc. under Ontario's Class Proceedings Act, 1992 for damages of $500 million. The damages are alleged to have arisen from the creation of a control zone within 30 metres of a pipeline pursuant to Section 112 of the National Energy Board Act. In November 2006, TCPL and Enbridge Inc. were granted a dismissal of the case but CAPLA appealed the decision. The Ontario Court of Appeal heard the appeal on December 18, 2007, and reserved its 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.

TCPL and its subsidiaries are subject to various legal proceedings and actions arising in the normal course of business. While the final outcome of such legal proceedings and actions cannot be predicted with certainty, it is the opinion of management that the resolution of such proceedings and actions will not have a material impact on the Company's consolidated financial position or results of operations.

Guarantees

TCPL, Cameco Corporation and BPC Generation Infrastructure Trust (BPC) have each severally guaranteed one-third of certain contingent financial obligations of Bruce B related to power sales agreements, operator licenses, a lease agreement and contractor services. The guarantees have terms ranging from one year ending in 2008 to perpetuity.

TCPL and BPC have each severally guaranteed one-half of certain contingent financial obligations related to an agreement with the Ontario Power Authority to refurbish and restart Bruce A power generation units. The guarantees were part of the reorganization of Bruce Power in 2005 and have terms ending in 2019 to 2036. TCPL's share of the potential exposure under these Bruce Power guarantees was estimated at December 31, 2007 to range from $711 million to a maximum of $750 million. The fair value of these guarantees is estimated to be $12 million.

The Company and its partners in certain jointly owned entities have severally and joint and severally guaranteed the performance of these entities related primarily to construction projects, redelivery of natural gas, PPA payments and the payment of liabilities. TCPL's share of the potential exposure under these guarantees was estimated at December 31, 2007 to range from $699 million to a maximum of $1,210 million. For certain of these entities, any payments made by TCPL under these guarantees in excess of its ownership interest are to be reimbursed by its partners. Deferred Amounts includes $7 million for the fair value of these joint and several guarantees.

TCPL has guaranteed a subsidiary's equity undertaking that supports the payment, under certain conditions, of principal and interest on US$75 million of the 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 a shareholder agreement, TCPL and another major multinational company, may be required to severally 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 Company's potential exposure is contingent on the impact any change of law would have on the ability of TransGas to service the debt. There has been no change in applicable law since the issuance of debt in 1995 and, thus, no exposure for TCPL. The debt matures in 2010. The Company has made no provision related to this guarantee.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 125

NOTE 25    RELATED PARTY TRANSACTIONS

The following amounts are included in Due from TransCanada Corporation.

			2007		2006
(outstanding loan amounts in millions of dollars)		Maturity Dates	Outstanding December 31	Interest Rate	Outstanding December 31	Interest Rate
Discount Notes		2008	1,226	4.8	485	4.3
Promissory Notes(1)			181
Credit Facility(2)			(207)	6.0	(7)	6.0
Promissory Notes(3)		2008
	US dollars (2007 – US$370)		(365)	5.6
			835		478

⁽¹⁾

Payable on demand and non-interest bearing.

⁽²⁾

In May 2003, TCPL established a demand revolving credit facility with TransCanada for general corporate purposes at $500 million, or a US dollar equivalent amount, bearing interest at the prime rate per annum or the US base rate per annum.

⁽³⁾

In February 2007, TCPL issued a promissory note to TransCanada for US$700 million bearing interest at LIBOR plus 32.5 basis points to partially finance the acquisitions of ANR and additional interest in Great Lakes. The promissory note was due on or before February 9, 2008. The US$370 million that was outstanding at December 31, 2007 was fully repaid on January 7, 2008.

The following amount is included in Due to TransCanada Corporation.

		2007		2006
(outstanding loan amounts in millions of dollars)	Maturity Date	Outstanding December 31	Interest Rate	Outstanding December 31	Interest Rate
Credit Facility	2009	1,307	5.5	550	5.0

In December 2006, TCPL established a $1 billion, three-year credit facility agreement with TransCanada, bearing interest at TCPL's option at the prime rate or Bankers' Acceptance rate plus 65 basis points. The borrowings under this facility can be used to repay indebtedness, make partner contributions to Bruce Power A, or used for working capital and general corporate purposes. In October 2007, the agreement was amended to increase the amount of the credit facility to $2.5 billion. This agreement matures on December 15, 2009. $1.3 billion was outstanding on this credit facility at December 31, 2007 (2006 – $550 million).

In 2007, Financial Charges included $72 million (2006 – $3 million) of interest expense and $30 million (2006 – $1 million) of interest income as a result of these financing arrangements with TransCanada. At December 31, 2007, Accounts Payable included $5 million of interest payable to TransCanada (2006 – nil), net of $2 million of interest receivable from TransCanada.

NOTE 26    DISCONTINUED OPERATIONS

TCPL had no income from discontinued operations in 2007 (2006 – $28 million; 2005 – nil). The income from discontinued operations in 2006 reflected settlements received from bankruptcy claims related to TCPL's Gas Marketing business, which was divested in 2001.

NOTE 27    SUBSEQUENT EVENTS

Certain subsidiaries of Calpine filed for bankruptcy protection in both Canada and the U.S. in 2005. Portland and Gas Transmission Northwest Corporation (GTNC) have reached agreements with Calpine for allowed unsecured claims of US$125 million and US$192.5 million, respectively, in the Calpine bankruptcy. Creditors will receive shares in the re-organized Calpine and these shares will be subject to market price fluctuations as the new Calpine shares begin to trade. In February 2008, Portland and GTNC received initial distributions of 6.1 million shares and 9.4 million shares, respectively, which are expected to result in a significant increase in TCPL's net earnings in first-quarter 2008.

Claims by NGTL and Foothills Pipe Lines (South B.C.) Ltd. for $31.6 million and $44.4 million, respectively, were received in cash in January 2008 and will be passed on to shippers on these systems.

126 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

EIGHT-YEAR FINANCIAL HIGHLIGHTS

(millions of dollars except where indicated)			2007		2006		2005		2004		2003		2002		2001		2000
Income Statement
Revenues			8,828		7,520		6,124		5,497		5,636		5,225		5,285		4,384
Net income from continuing operations			1,232		1,071		1,230		1,000		823		769		708		663
Net income			1,232		1,099		1,230		1,052		873		769		641		724
Net income/(loss) by segment
		Pipelines	686		560		679		584		625		639		572		613
		Energy	514		452		566		398		217		160		181		95
		Corporate	10		37		(37	)	(4	)	(41	)	(52	)	(67	)	(80	)
	Continuing operations		1,210		1,049		1,208		978		801		747		686		628
	Discontinued operations		–		28		–		52		50		–		(67	)	61
Net income applicable to common shares			1,210		1,077		1,208		1,030		851		747		619		689
Cash Flow Statement
Funds generated from operations			2,603		2,374		1,950		1,701		1,822		1,843		1,625		1,484
Decrease/(increase) in operating working capital			215		(300	)	(48	)	28		93		92		(487	)	437
Net cash provided by operations			2,818		2,074		1,902		1,729		1,915		1,935		1,138		1,921
Capital expenditures and acquisitions			(5,874	)	(2,042	)	(2,071	)	(2,046	)	(965	)	(851	)	(1,082	)	(1,144	)
Disposition of assets			35		23		671		410		–		–		1,170		2,233
Cash dividends paid on common and preferred shares			(725	)	(639	)	(608	)	(574	)	(532	)	(488	)	(440	)	(458	)
Balance Sheet
Assets
Plant, property and equipment
	Pipelines		18,280		17,141		16,528		17,306		16,064		16,158		16,562		16,937
	Energy		5,127		4,302		3,483		1,421		1,368		1,340		1,116		776
	Corporate		45		44		27		37		50		64		66		111
Total assets
	Continuing operations		31,165		26,386		24,113		22,414		20,873		20,416		20,255		20,238
	Discontinued operations		–		–		–		7		11		139		276		5,007
Total assets			31,165		26,386		24,113		22,421		20,884		20,555		20,531		25,245
Capitalization
Long-term debt			12,377		10,887		9,640		9,749		9,516		8,899		9,444		10,008
Junior subordinated notes			975		–		–		–		–		–		–		–
Preferred securities			–		536		536		554		598		944		950		1,208
Non-controlling interests			610		366		394		311		324		288		286		257
Preferred shares			389		389		389		389		389		389		389		389
Common shareholder's equity			9,664		7,618		7,164		6,484		6,044		5,747		5,426		5,211
Per Common Share Data (dollars)

SUPPLEMENTARY INFORMATION 127

Net income – Basic
	Continuing operations	$2.28	$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
		$2.28	$2.23	$2.50	$2.14	$1.77	$1.56	$1.30		$1.45
Net income – Diluted
	Continuing operations	$2.28	$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
		$2.28	$2.23	$2.50	$2.14	$1.77	$1.55	$1.30		$1.45
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		$2.80
Series Y Cumulative First Preferred Shares		$2.80	$2.80	$2.80	$2.80	$2.80	$2.80	$2.80		$2.80
Financial Ratios
Earnings to fixed charges(1)		2.6	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 income from continuing operations before financial charges and income taxes, excluding undistributed income from equity investees by the financial charges incurred by the company (net of capitalized interest).

128 SUPPLEMENTARY INFORMATION

TRANSCANADA PIPELINES LIMITED

RECONCILIATION TO UNITED STATES GAAP

December 31, 2007

AUDITOR'S REPORT ON RECONCILIATION TO UNITED STATES GAAP

To the Board of Directors of TransCanada PipeLines Limited

On February 25, 2008, we reported on the consolidated balance sheets of TransCanada PipeLines Limited as at December 31, 2007 and 2006, and the consolidated statements of income, comprehensive income, accumulated other comprehensive income, shareholders' equity and cash flows for each of the years in the three-year period ended December 31, 2007, which are included in the Annual Report on Form 40-F. In connection with our audits of the aforementioned consolidated financial statements, we also have audited the related supplemental note entitled "Reconciliation to United States GAAP" included in 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 25, 2008

2

TRANSCANADA PIPELINES LIMITED
RECONCILIATION TO UNITED STATES GAAP

The 2007 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 United States (U.S.) GAAP. The effects of these differences on the Company's consolidated financial statements for the year ended December 31, 2007 are provided in the following U.S. GAAP condensed consolidated financial statements which should be read in conjunction with TCPL's 2007 audited consolidated financial statements prepared in accordance with Canadian GAAP. Amounts are stated in Canadian dollars unless otherwise indicated.

Condensed Statement of Consolidated Income and Comprehensive Income in Accordance with U.S. GAAP⁽¹⁾

Year ended December 31 (millions of dollars except per share amounts)		2007		2006		2005
Revenues		7,563		5,997		5,333
Plant operating costs and other		2,405		1,922		1,730
Commodity purchases resold		1,897		1,369		904
Depreciation		1,030		897		924
		5,332		4,188		3,558
		2,231		1,809		1,775
Other (income)/expenses
	Income from equity investments	(365	)	(478	)	(458	)
	Other expenses(2)	896		745		401
	Income taxes	491		472		607
		1,022		739		550
Income from continuing operations — U.S. GAAP		1,209		1,070		1,225
Net income from discontinued operations — U.S. GAAP		—		28		—
Net Income in Accordance with U.S. GAAP		1,209		1,098		1,225
Adjustments affecting comprehensive income under U.S. GAAP
	Foreign currency translation adjustment, net of tax	(271	)	(1	)	(18	)
	Changes in minimum pension liability, net of tax(3)	—		63		(51	)
	Change in funded status of postretirement plan liability, net of tax(3)	(40	)	—		—
	Change in equity investment funded status of postretirement plan liability, net of tax(3)	21		—		—
	Unrealized gain/(loss) on derivatives, net of tax	70		(24	)	(54	)
Comprehensive Income in Accordance with U.S. GAAP(4)		989		1,136		1,102

3

Reconciliation of Income from Continuing Operations

Year ended December 31 (millions of dollars)		2007		2006		2005
Net Income from Continuing Operations in Accordance with Canadian GAAP		1,232		1,071		1,230
U.S. GAAP adjustments
	Unrealized gain on natural gas inventory held in storage(5)	(25	)	—		—
	Tax impact on unrealized gain on natural gas inventory held in storage	8		—		—
	Unrealized gain/(loss) on energy contracts(6)	13		(6	)	(14	)
	Tax impact of unrealized gain/(loss) on energy contracts	(5	)	3		5
	Equity investment gain(7)(8)	—		1		5
	Tax impact of equity investment gain	—		—		(1	)
	Unrealized (loss)/gain on foreign exchange and interest rate derivatives(9)	(3	)	1		1
	Tax impact of (loss)/gain on foreign exchange and interest rate derivatives	1		—		(1	)
	Tax recovery due to a change in tax legislation substantively enacted in Canada(10)	(12	)	—		—
Income from Continuing Operations in Accordance with U.S. GAAP		1,209		1,070		1,225

Condensed Statement of Consolidated Cash Flows in Accordance with U.S. GAAP⁽¹⁾

Year ended December 31 (millions of dollars)	2007		2006		2005
Cash Generated from Operations(11)
Net cash provided by operating activities	2,759		1,885		1,627
Investing Activities
Net cash used in investing activities	(6,197	)	(1,920	)	(1,169	)
Financing Activities
Net cash provided by/(used in) financing activities	3,524		234		(514	)
Effect of Foreign Exchange Rate Changes on Cash and Short-Term Investments	(42	)	7		13
Increase/(Decrease) in Cash and Short-Term Investments	44		206		(43	)
Cash and Short-Term Investments
Beginning of year	289		83		126
Cash and Short-Term Investments
End of year	333		289		83

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

December 31 (millions of dollars)	2007	2006
Current assets(5)	2,601	1,550
Long-term investments(3)(7)(8)	3,568	2,922
Plant, property and equipment	19,225	17,430
Regulatory asset(3)(12)	1,790	2,199
Goodwill	2,521	148
Other assets(3)(7)(14)	1,658	1,572
	31,363	25,821
Current liabilities(5)(13)	2,409	2,623
Deferred amounts and other long-term liabilities(3)(8)	2,465	986
Long-term debt and junior subordinated notes(14)	13,423	10,913
Deferred income taxes(3)(5)(12)	2,707	2,734
Preferred securities	—	536
Non-controlling interests	610	366
Shareholders' equity(3)	9,749	7,663
	31,363	25,821

4

Statement of Accumulated Other Comprehensive Income in Accordance with U.S. GAAP^(1)(15)

(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, 2005	—		(71	)	(26	)	(4	)	(101	)
Changes in minimum pension liability, net of tax recovery of $27(3)	—		—		(51	)	—		(51	)
Unrealized loss on derivatives, net of tax recovery of $28(6)	—		—		—		(54	)	(54	)
Foreign currency translation adjustment, net of tax expense of $21	—		(18	)	—		—		(18	)
Balance at December 31, 2005	—		(89	)	(77	)	(58	)	(224	)
Change in minimum pension liability, net of tax expense of $35(3)	—		—		63		—		63
Reversal of minimum pension liability, due to adoption of SFAS 158(3)	(14	)	—		14		—		—
Change in funded status of postretirement plan liability, net of tax recovery of $35(4)	(78	)	—		—		—		(78	)
Change in equity investment funded status of postretirement plan liability, net of tax recovery of $70(3)	(154	)	—		—		—		(154	)
Unrealized gain on derivatives, net of tax expense of $11(6)	—		—		—		(24	)	(24	)
Foreign currency translation adjustment, net of tax recovery of $1	—		(1	)	—		—		(1	)
Balance at December 31, 2006	(246	)	(90	)	—		(82	)	(418	)
Foreign currency translation adjustment, net of tax expense of $142	—		(271	)	—		—		(271	)
Change in funded status of postretirement plan liability, net of tax recovery of $8(3)	(40	)	—		—		—		(40	)
Change in equity investment funded status of postretirement plan liability, net of tax expense of $11(3)	21		—		—		—		21
Unrealized loss on derivatives, net of tax expense of $42(6)	—		—		—		70		70
Balance at December 31, 2007	(265	)	(361	)	—		(12	)	(638	)

⁽¹⁾

In accordance with U.S. GAAP, the Condensed Statement of Consolidated Income and Comprehensive Income, Condensed Statement of Consolidated Cash Flows, Condensed Balance Sheet and Statement of Accumulated 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 $14 million for the year ended December 31, 2007 (2006 — $9 million; 2005 — $3 million).

5

⁽³⁾

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 as at December 31, 2006. Retrospective application of SFAS No. 158 was 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 other comprehensive income, in the year in which the changes occur. The amounts recognized in the Company's balance sheet as at December 31, 2007 are as follows.

December 31 (millions of dollars)	2007		2006
Non-current assets	20		10
Current liabilities	—		(5	)
Non-current liabilities	(251	)	(220	)
	(231	)	(215	)

Pre-tax amounts recognized in Accumulated Other Comprehensive Income (AOCI) are as follows.

December 31 (millions of dollars)	Pension Benefits 2007	Other Benefits 2007	Total 2007	Pension Benefits 2006	Other Benefits 2006		Total 2006
Net loss	120	15	135	92	14		106
Prior service cost (credit)	12	14	26	11	(4	)	7
	132	29	161	103	10		113

Pre-tax amounts recorded in Other Comprehensive Income were as follows.

December 31 (millions of dollars)	Pension Benefits 2007		Other Benefits 2007		Total 2007
Amortization of net loss from AOCI to net income	(9	)	(1	)	(10	)
Amortization of prior service cost (credit) from AOCI to net income	(1	)	—		(1	)
Funded status adjustment	38		21		59
	28		20		48

The funded status based on the accumulated benefit obligation for all defined benefit pension plans as at December 31, 2007 is as follows.

December 31 (millions of dollars)	2007	2006
Accumulated benefit obligation	1,244	1,167
Fair value of plan assets	1,358	1,264
Funded status — surplus	114	97

Included in the above accumulated benefit obligation and fair value of plan assets as at December 31, 2007 are the following amounts in respect of plans that are not fully funded.

December 31 (millions of dollars)	2007	2006
Accumulated benefit obligation	—	67
Fair value of plan assets	—	65
Funded status — (deficit)	—	(2	)

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 $7 million and $1 million, respectively. The estimated net loss and prior service cost 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 $2 million and $1 million, respectively.

The accumulated benefit obligation for the Company's defined benefit pension plans was $1,244 million at December 31, 2007 (2006 — $1,167 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, 2007 developed by the Company's third party actuary. This yield curve is used to develop

6

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.

⁽⁴⁾

For the year ended December 31, 2007, Comprehensive Income in Accordance with U.S. GAAP was $56 million lower than under Canadian GAAP. In addition to the differences between Canadian and U.S. GAAP net income described in the Reconciliation of Income from Continuing Operations, substantially all of the difference between Comprehensive Income prepared in accordance with Canadian and U.S. GAAP relates to differences in the accounting treatment of energy derivative contracts prior to the adoption of new Canadian standards (Section 3855 "Financial Instruments — Recognition and Measurement" and Section 3865 "Hedges") on January 1, 2007, and for defined benefit pension and other postretirement plans.

⁽⁵⁾

In accordance with Canadian GAAP, natural gas inventory held in storage is recorded at its fair value. Under U.S. GAAP, inventory is recorded at lower of cost or market.

⁽⁶⁾

Relates to gains and losses realized in 2006 on derivative energy contracts for periods before they were documented as hedges for purposes of U.S. GAAP and to differences in accounting with respect to physical energy contracts.

⁽⁷⁾

Under Canadian GAAP, pre-operating costs incurred during the commissioning phase of a new project are deferred until commercial production levels are achieved. After such time, those costs are amortized over the estimated life of the project. Under U.S. GAAP, such costs are expensed as incurred. Certain start-up costs incurred by Bruce Power L.P. (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.

⁽⁸⁾

For U.S. GAAP purposes, the fair value of guarantees recorded as a liability at December 31, 2007 was $12 million (2006 — $17 million) and primarily 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, 2007 was nil (2006 — $1 million; 2005 — $1 million).

⁽⁹⁾

Represents the amortization of certain hedges that became ineffective at different times under Canadian and U.S. GAAP.

⁽¹⁰⁾

In accordance with Canadian GAAP, the Company recorded income tax benefits resulting from substantively enacted Canadian federal income tax legislation. Under US GAAP, the legislation must be fully enacted for income tax adjustments to be recorded.

⁽¹¹⁾

In accordance with U.S. GAAP, all current taxes are included in cash generated from operations.

⁽¹²⁾

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.

⁽¹³⁾

Current liabilities at December 31, 2007 include dividends payable of $189 million (2006 — $162 million) and current taxes payable of $140 million (2006 — $71 million).

⁽¹⁴⁾

In accordance with U.S. GAAP, debt issue costs are recorded as a deferred asset rather than being included in long-term debt as required by Canadian GAAP.

⁽¹⁵⁾

At December 31, 2007, Accumulated Other Comprehensive Income in accordance with U.S. GAAP results in a $265 million higher loss than under Canadian GAAP. The difference relates to the accounting treatment for defined benefit pension and other postretirement plans.

7

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)	2007	2006
Deferred Tax Liabilities
Difference in accounting and tax bases of plant, equipment and power purchase arrangements	1,763	1,478
Taxes on future revenue requirement	433	606
Investments in subsidiaries and partnerships	443	683
Unrealized foreign exchange gains on long-term debt	110	39
Pension Benefit	11	25
Other Comprehensive Income	8	—
Other	95	88
	2,863	2,919
Deferred Tax Assets
Deferred amounts	45	71
Other Post-employment benefits	25	16
Other Comprehensive Income	22	—
Other	77	112
	169	199
Less: Valuation allowance	13	14
	156	185
Net deferred tax liabilities	2,707	2,734

TCPL adopted FASB Financial Interpretation 48, Accounting for Uncertainty in Income Taxes ("FIN 48") on January 1, 2007. The implementation of the provisions under FIN 48 did not have a material impact on the U.S. GAAP financial statements of the Company and no adjustment to the beginning balance of retained earnings was required due to the adoption of FIN 48.

Below is the reconciliation of the annual changes in the total unrecognized tax benefit.

December 31 (millions of dollars)	2007
Unrecognized tax benefits, beginning of year	80
Gross increases — tax positions in prior years	9
Gross decreases — tax positions in prior years	(11	)
Gross increases — current year positions	9
Settlements	(6	)
Lapses of statute of limitations	(11	)
Unrecognized tax benefits, end of year	70

TCPL expects the enactment of certain Canadian Federal tax legislation in the next twelve months. This legislation will result in a favourable income tax adjustment of approximately $12 million. Otherwise, subject to the results of audit examinations by taxing authorities and other legislative amendments, TransCanada does not anticipate further adjustments to the unrecognized tax benefits during the next twelve months that would have a material impact on its financial statements.

TCPL and its subsidiaries are subject to either Canadian federal and provincial income tax, U.S. federal, state and local income tax or the relevant income tax in other international jurisdictions. The Company has substantially concluded all Canadian federal and provincial income tax matters for the years through 2003.

8

Canadian federal income tax returns for years 2004 and 2005 are currently under examination by the Canada Revenue Agency, which has not proposed any significant adjustments. Substantially all material U.S. federal income tax matters have been concluded for years through 2003 and U.S. state and local income tax matters through 2001.

TCPL's continuing practice is to recognize interest and penalties related to income tax uncertainties in income tax expense. Included in net tax expense for the year ended December 31, 2007 was $1 million and nil for interest and penalties respectively. At December 31, 2007, the Company had $14 million and nil accrued for interest and penalties, respectively (December 31, 2006, $13 million and nil, respectively).

Other

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's U.S. GAAP financial statements were not impacted by SFAS No. 155.

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. TransCanada's U.S. GAAP financial statements were not impacted by SFAS No. 156.

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 February 2007, FASB issued SFAS No. 159 "The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115", which allows an entity to choose to measure many financial instruments and certain other items at fair value for fiscal years beginning on or after November 15, 2007. TCPL does not expect a material affect on its financial results as a result of adopting this standard on January 1, 2008.

In December 2007, FASB issued SFAS No. 160 "Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51" and SFAS No. 141R "Business Combinations" both of which are effective for annual periods beginning after December 15, 2008. The first statement requires that third party ownership interests in subsidiaries be presented separately in the equity section of the balance sheet. In addition, the income attributable to the noncontrolling interest will now be included in consolidated net income and will be deducted separately at the bottom of the income statement. The second statement requires that most identifiable assets, liabilities (including obligations for contingent consideration), noncontrolling interests and goodwill be recorded at "full fair value". Also, for step acquisitions, the acquirer will be required to re-measure its noncontrolling equity investment in the acquiree at fair value as of the date control is obtained and recognize any gain or loss in income. The Company is expected to adopt these standards on January 1, 2009.

9

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)	2007		2006		2005
Income
Revenues	1,260		1,450		1,233
Plant operating costs and other	(662	)	(697	)	(508	)
Depreciation	(157	)	(175	)	(173	)
Financial charges and other	(76	)	(100	)	(94	)
Proportionate share of income before income taxes of long-term investments	365		478		458

December 31 (millions of dollars)	2007		2006
Balance Sheet
Current assets	526		446
Plant, property and equipment	4,317		4,177
Other assets	51		198
Current liabilities	(260	)	(445	)
Deferred amounts	(212	)	(235	)
Long-term debt of joint ventures	(909	)	(1,266	)
Deferred income taxes	55		47
Proportionate share of net assets of long-term investments	3,568		2,922

The distributed earnings from long-term investments for the year ended December 31, 2007 were $376 million (2006 — $494 million; 2005 — $371 million). The undistributed earnings from long-term investments for the year ended December 31, 2007 were $821 million (2006 — $836 million; 2005 — $820 million).

10

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, 2007. In 2007, TCPL acquired American Natural Resources Company and ANR Storage Company (collectively, "ANR") and began consolidating the operations of ANR into the Company. Management excluded this business from its evaluation of the effectiveness of TCPL's internal control over financial reporting as of December 31, 2007. The net income attributable to this business represented approximately nine per cent of TCPL's consolidated net income for the year ended December 31, 2007, and their aggregate total assets represented approximately 12 per cent of TCPL's consolidated total assets as of December 31, 2007.

Based on this evaluation, management has concluded that internal control over financial reporting is effective as of December 31, 2007. There are no material weaknesses that have been identified by management in this regard.

KPMG LLP, the independent auditors of TCPL, who have audited the consolidated financial statements of TCPL, have also audited the effectiveness of TCPL's internal control over financial reporting as of December 31, 2007 and have issued the report entitled "Report of Independent Registered Public Accounting Firm".

February 25, 2008

/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

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of TransCanada PipeLines Limited

We have audited TransCanada PipeLines Limited's internal control over financial reporting as of December 31, 2007, 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 and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on 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, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included 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 that 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, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the 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 consolidated financial statements for the years ended December 31, 2007 and 2006, we also have conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our report dated February 25, 2008, expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Chartered Accountants

Calgary, Canada

February 25, 2008

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 Company's internal control over financial reporting. Our report to the shareholder dated February 25, 2008 is expressed in accordance with Canadian reporting standards, which do not require a reference to the audit report on the Company's internal control over financial reporting in the financial statement auditors' report.

In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when there is a change in accounting principles that has a material effect on the comparability of the Company's financial statements, such as the changes described in note 2 to the consolidated financial statements as at December 31, 2007 and for the year then ended. Our report to the shareholder dated February 25, 2008 is expressed in accordance with Canadian reporting standards, which do not require a reference to such changes in accounting principles in the auditors' report when the changes are properly accounted for and adequately disclosed in the financial statements.

/s/ KPMG LLP

Chartered Accountants

Calgary, Canada

February 25, 2008

QuickLinks

CONSOLIDATED AUDITED ANNUAL FINANCIAL STATEMENTS AND MANAGEMENT'S DISCUSSION & ANALYSIS
UNDERTAKING
DISCLOSURE CONTROLS AND PROCEDURES
AUDIT COMMITTEE FINANCIAL EXPERT
CODE OF ETHICS
PRINCIPAL ACCOUNTANT FEES AND SERVICES
OFF-BALANCE SHEET ARRANGEMENTS
TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS
IDENTIFICATION OF THE AUDIT COMMITTEE
FORWARD-LOOKING INFORMATION
SIGNATURES
TABLE OF CONTENTS
TRANSCANADA PIPELINES LIMITED RECONCILIATION TO UNITED STATES GAAP

AUDITOR'S REPORT ON RECONCILIATION TO UNITED STATES GAAP

TRANSCANADA PIPELINES LIMITED RECONCILIATION TO UNITED STATES GAAP

EX-23.1

QuickLinks -- Click here to rapidly navigate through this document

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of TransCanada PipeLines Limited

We consent to the inclusion in this Annual Report on Form 40-F of:

•

our auditors' report dated February 25, 2008 on the consolidated balance sheets of TransCanada PipeLines Limited as at December 31, 2007 and 2006, and the consolidated statements of income, comprehensive income, accumulated other comprehensive income, shareholder's equity and cash flows for each of the years in the three-year period ended December 31, 2007,

•

our Comments by Auditors for United States Readers on Canada — United States Reporting Differences, dated February 25, 2008,

•

our auditors' report on the reconciliation to United States GAAP dated February 25, 2008, and

•

our Report of Independent Registered Public Accounting Firm dated February 25, 2008 on the Company's internal control over financial reporting as of December 31, 2007,

each of which is contained in this annual report on Form 40-F of the Company for the fiscal year ended December 31, 2007.

We also consent to incorporation by reference of the above mentioned audit reports and comments in TransCanada PipeLines Limited's Registration Statement on Form F-9 (Reg. No. 333-145980).

/s/ KPMG LLP

Chartered Accountants

Calgary, Canada

February 25, 2008

QuickLinks

Exhibit 23.1

EX-31.1

QuickLinks -- Click here to rapidly navigate through this document

Exhibit 31.1

Certifications

I, Harold N. Kvisle, certify that:

1.

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



2.

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



3.

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



4.

The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:



(a)

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;



(b)

designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;



(c)

evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;



(d)

disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and



5.

The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):



(a)

all significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and



(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Dated February 28, 2008

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

C-1

QuickLinks

Exhibit 31.1

Certifications

EX-31.2

QuickLinks -- Click here to rapidly navigate through this document

Exhibit 31.2

Certifications

I, Gregory A. Lohnes, certify that:

1.

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



2.

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



3.

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



4.

The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:



(a)

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;



(b)

designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;



(c)

evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and



(d)

disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and



5.

The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):



(a)

all significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and



(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Dated February 28, 2008

/s/  GREGORY A. LOHNES Gregory A. Lohnes
Executive Vice-President and Chief Financial Officer

C-2

QuickLinks

Exhibit 31.2

Certifications

EX-32.1

QuickLinks -- Click here to rapidly navigate through this document

Exhibit 32.1

TRANSCANADA PIPELINES LIMITED

450 - 1^st Street S.W.
Calgary, Alberta, Canada
T2P 5H1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER
UNDER SECTION 906 OF SARBANES-OXLEY ACT OF 2002

I, Harold N. Kvisle, the Chief Executive Officer of TransCanada PipeLines Limited (the "Company"), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify, in connection with the Company's Annual Report as filed on Form 40-F for the fiscal year ending December 31, 2007 with the Securities and Exchange Commission (the "Report"), that:

1.

The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and



2.

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/  HAROLD N. KVISLE Harold N. Kvisle
Chief Executive Officer
February 28, 2008

C-3

QuickLinks

Exhibit 32.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER UNDER SECTION 906 OF SARBANES-OXLEY ACT OF 2002

EX-32.2

QuickLinks -- Click here to rapidly navigate through this document

Exhibit 32.2

TRANSCANADA PIPELINES LIMITED

450 - 1^st Street S.W.
Calgary, Alberta, Canada
T2P 5H1

CERTIFICATION OF CHIEF FINANCIAL OFFICER
UNDER SECTION 906 OF SARBANES-OXLEY ACT 0F 2002

I, Gregory A. Lohnes, the Chief Financial Officer of TransCanada PipeLines Limited (the "Company"), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify, in connection with the Company's Annual Report as filed on Form 40-F for the fiscal year ending December 31, 2007 with the Securities and Exchange Commission (the "Report"), that:

1.

The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and



2.

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/  GREGORY A. LOHNES Gregory A. Lohnes
Chief Financial Officer
February 28, 2008

C-4

QuickLinks

Exhibit 32.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER UNDER SECTION 906 OF SARBANES-OXLEY ACT 0F 2002