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

Form 40-F

o	REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT of 1934
OR
ý	ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2008        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)

TransCanada Northern Border Inc., 13710 FNB Parkway
Omaha, Nebraska, 68154-5200; (877) 290-2772
(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, 2008, 4,000,000 Cumulative Redeemable First Preferred Shares Series U
and 4,000,000 Cumulative Redeemable First Preferred Shares Series Y
were issued and outstanding
All of the Registrant's common shares are owned by TransCanada Corporation

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

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

        The documents (or portions thereof) forming part of this Form 40-F are incorporated by reference into Registration Statement on Form F-9 (File No. 333-154961) under the Securities Act of 1933, as amended.

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

A.    Audited Consolidated Annual Financial Statements

For audited consolidated financial statements, including the report of the independent chartered accountants, see pages 78 through 130 of the TransCanada PipeLines Limited ("TCPL") 2008 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 77 of the TCPL 2008 Management's Discussion and Analysis and Audited Consolidated Financial Statements included herein.

For the purposes of this Report, only pages 2 through 77 and 78 through 130 of the TCPL 2008 Management's Discussion and Analysis and Audited Consolidated Financial Statements shall be deemed incorporated herein by reference and filed, and the balance of such 2008 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 Annual 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 Audited Consolidated Financial Statements on page 78;



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 64 of the TCPL 2008 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.

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 64 of the TCPL 2008 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 President and Chief Executive Officer, Chief Financial Officer, Controller, directors, employees and contractors. The Registrant's codes are available on its website at www.transcanada.com. No waivers have been granted from any provision of the codes during the 2008 fiscal year.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

For information on principal accountant fees and services, see "Corporate Governance — Audit Committee — External Auditor Service Fees" and "Corporate Governance — Audit Committee — Pre-Approval Policies and Procedures" on page 25 of the TCPL 2008 Annual Information Form.

OFF-BALANCE SHEET ARRANGEMENTS

The Registrant has no off-balance sheet arrangements, as defined in this Form, other than the guarantees and commitments described in Note 24 of the Notes to the Audited Consolidated Financial Statements attached to this Form 40-F and incorporated herein by reference.

TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

For information on Tabular Disclosure of Contractual Obligations, see "Contractual Obligations" in Management's Discussion and Analysis on page 50 of the TCPL 2008 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
D.M.G. Stewart

3

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. Forward-looking statements in this document are intended to provide TCPL's shareholders and potential investors with information regarding TCPL and its subsidiaries, including management's assessment of TCPL's and its subsidiaries' future financial and operational plans and outlook. Forward-looking statements in this document may include, among others, statements regarding the anticipated business prospects and financial performance of TCPL and its subsidiaries, expectations or projections about the future, strategies and goals for growth and expansion, expected and future cash flows, costs, schedules, operating and financial results and expected impact of future commitments and contingent liabilities. 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 others, 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 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 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 Commission. 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.

4

SIGNATURES

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

TRANSCANADA PIPELINES LIMITED
Per:	/s/ GREGORY A. LOHNES GREGORY A. LOHNES Executive Vice-President and Chief Financial Officer
	Date: February 26, 2009

DOCUMENTS FILED AS PART OF THIS REPORT

13.1	TCPL's Annual Information Form for the year ended December 31, 2008.
13.2	Management's Discussion and Analysis (included on pages 2 through 77 of the TCPL 2008 Management's Discussion and Analysis and Audited Consolidated Financial Statements).
13.3	2008 Audited Consolidated Financial Statements (included on pages 78 through 130 of the TCPL 2008 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, 2008.
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 23, 2009

TRANSCANADA PIPELINES LIMITED     i

TABLE OF CONTENTS

	Page
PRESENTATION OF INFORMATION	ii
FORWARD-LOOKING INFORMATION	ii
TRANSCANADA PIPELINES LIMITED	1
Corporate Structure	1
Intercorporate Relationships	1
GENERAL DEVELOPMENT OF THE BUSINESS	2
Developments in the Pipelines Business	2
Developments in the Energy Business	5
Financing Activities	8
BUSINESS OF TCPL	9
Pipelines Business	9
Regulation of the Pipeline Business	11
Energy Business	12
GENERAL	14
Employees	14
Social and Environmental Policies	14
Environmental Protection	15
RISK FACTORS	15
Environmental Risk Factors	15
Other Risk Factors	17
DIVIDENDS	17
DESCRIPTION OF CAPITAL STRUCTURE	17
Share Capital	17
Debt	18
CREDIT RATINGS	18
DBRS Limited (DBRS)	19
Moody’s Investors Service, Inc. (Moody’s)	19
Standard & Poor’s (S&P)	19
MARKET FOR SECURITIES	20
Common Shares	20
Series U Preferred Shares and Series Y Preferred Shares	20
DIRECTORS AND OFFICERS	20
Directors	21
Board Committees	22
Officers	23
Conflicts of Interest	23
CORPORATE GOVERNANCE	24
Compliance with Canadian Governance Guidelines	24
AUDIT COMMITTEE	24
Relevant Education and Experience of Members	24
Pre-Approval Policies and Procedures	25
External Auditor Service Fees	25
INDEBTEDNESS OF DIRECTORS AND EXECUTIVE OFFICERS	26
SECURITIES OWNED BY DIRECTORS	26
COMPENSATION OF DIRECTORS	26
DIRECTOR COMPENSATION TABLE	27
RETAINERS AND FEES PAID TO DIRECTORS	27
2008 Retainers and Fees	28
Minimum Share Ownership Guidelines	29
Share Unit Plan for Non-Employee Directors	29
COMPENSATION DISCUSSION AND ANALYSIS	29
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	29
MATERIAL CONTRACTS	30
TRANSFER AGENT AND REGISTRAR	30
INTEREST OF EXPERTS	30
ADDITIONAL INFORMATION	30
GLOSSARY	31
SCHEDULE “A”	A-1
SCHEDULE “B”	B-1
SCHEDULE “C”	C-1
SCHEDULE “D”	D-1
SCHEDULE “E”	E-1
SCHEDULE “F”	F-1

TRANSCANADA PIPELINES LIMITED     ii

PRESENTATION OF INFORMATION

Unless the context indicates otherwise, a reference in this Annual Information Form (“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.

Unless otherwise noted, the information contained in this AIF is given at or for the year ended December 31, 2008 (“Year End”). Amounts are expressed in Canadian dollars unless otherwise indicated. Financial information is presented in accordance with Canadian generally accepted accounting principles.

Certain portions of TCPL’s Management’s Discussion and Analysis dated February 23, 2009 (“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.

The Accounting Standards Board (“AcSB”) of the Canadian Institute of Chartered Accountants has announced that Canadian publicly accountable enterprises are required to adopt International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board, effective January 1, 2011. In June 2008, the Canadian Securities Administrators proposed that Canadian public companies that are United States Securities and Exchange Commission (“SEC”) registrants, such as TCPL, could retain the option to prepare their financial statements under generally accepted accounting principles in the United States (“US GAAP”) instead of IFRS. In November 2008, the SEC issued for public comment a recommendation that, beginning in 2014, United States issuers be required to adopt IFRS using a phased-in approach based on market capitalization.  TCPL is currently considering the impact a conversion to IFRS or US GAAP would have on its accounting systems and financial statements.  For more information on TCPL’s conversion project, see TCPL’s MD&A under “Accounting Changes – International Financial Reporting Standards”.

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.  Forward-looking statements in this document are intended to provide TCPL shareholders and potential investors with information regarding TCPL and its subsidiaries, including management’s assessment of TCPL’s and its subsidiaries’ future financial and operational plans and outlook.  Forward-looking statements in this document may include, among others, statements regarding the anticipated business prospects and financial performance of TCPL and its subsidiaries, expectations or projections about the future, strategies and goals for growth and expansion, expected and future cash flows, costs, schedules, operating and financial results and expected impact of future commitments and contingent liabilities.  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 others, 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 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 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 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.

Intercorporate Relationships

The following diagram presents the name and jurisdiction of incorporation, continuance or formation of TCPL’s principal subsidiaries as at December 31, 2008.  Each of these subsidiaries has total assets that exceeded 10% of the total consolidated assets of TransCanada or revenues that exceeded 10% of the total consolidated revenues of TransCanada as at and for the year ended December 31, 2008.  TCPL owns, directly or indirectly, 100 per cent of the voting shares of each of these subsidiaries.

TRANSCANADA PIPELINES LIMITED     2

The above diagram does not include all of the subsidiaries of TCPL.  The assets and revenues of excluded subsidiaries in the aggregate did not exceed 20% of the total consolidated assets or total consolidated revenues of TCPL as at and for the year ended December 31, 2008.

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.

2008

Pipeline Developments

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

·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 (the “Portland System”) 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 would be subject to market price fluctuations as the new Calpine shares began to trade. In February 2008, the Portland System and GTNC received partial distributions of 6.1 million shares and 9.4 million shares, respectively. Subsequently, these shareholdings were sold into the market.  Claims of Nova Gas Transmission Limited (“NGTL”) and Foothills Pipe Lines (South B.C.) Ltd., both wholly-owned subsidiaries of TransCanada, for $31.6 million and $44.4 million, respectively, were received in cash in January 2008 and were passed on to shippers on these systems.

·March 14, 2008.  TransCanada Keystone Pipeline, LP (“Keystone U.S.”) received a Presidential Permit authorizing the construction, maintenance and operation of facilities at the United States and Canada border for the transportation of crude oil between the two countries.  The Presidential Permit was a significant regulatory approval required to begin construction of the 3,456 kilometre (“km”) pipeline project that will transport crude oil from Alberta to markets in the United States (the “Keystone Oil Pipeline”).  The Presidential Permit was issued following the issuance by the U.S. Department of State of the Final Environmental Impact Statement (“FEIS”) on January 11, 2008 for the construction of the Keystone U.S. pipeline and its Cushing extension.  The FEIS stated the pipeline would result in limited adverse environmental impacts.  Construction of the Keystone Oil Pipeline began in May 2008 in both Canada and the United States.  Commissioning of the segment to Wood River and Patoka is expected to commence in late 2009 with commercial operations to follow in early 2010.  Commissioning of the segment providing service to Cushing is expected to commence in late 2010.

·April 2008.  An expansion to TCPL’s natural gas transmission system in the province of Alberta (the “Alberta System”) in the Fort McMurray area, comprising a total of approximately 150 km, was placed in service on its projected on-stream date.

TRANSCANADA PIPELINES LIMITED     3

·July 16, 2008.  TCPL announced plans to expand and extend the Keystone Oil Pipeline system and provide additional capacity in 2012 of 500,000 barrels per day (“Bbl/d”) from Western Canada to the United States Gulf Coast, near existing terminals in Port Arthur, Texas.  The expansion, when completed, is expected to increase the Keystone Oil Pipeline system from 590,000 Bbl/d to approximately 1.1 million Bbl/d.  Construction of the expansion facilities is expected to commence in 2010 subject to the receipt of the necessary regulatory approvals.

·September 3, 2008.  TCPL acquired Bison Pipeline LLC from Northern Border Pipeline Company (“NBPL”) for US$20 million.  The assets of Bison Pipeline LLC included executed precedent agreements as well as regulatory, environmental and engineering work on the Bison Pipeline Project (“Bison”), a proposed 480 km (298 mile) pipeline from the Powder River Basin in Wyoming to the Northern Border Pipeline system in Morton County, North Dakota.

·September 8, 2008.  TCPL reached a proposed agreement with Canadian Utilities Limited (“ATCO Pipelines”) to provide integrated natural gas transmission service to customers.  If approved by the regulatory authorities, the two companies will combine physical assets under a single rates and services structure with a single commercial interface with customers but with each company separately managing assets within distinct operating territories in the province.  TCPL continues to work with all stakeholders to finalize this agreement.

·October 29, 2008.  TCPL announced that the Keystone Oil Pipeline system successfully conducted that open season for expansion and extension to the United States Gulf Coast by securing additional firm, long-term contracts totaling 380,000 Bbl/d for an average term of approximately 17 years.  With these shipper commitments the Keystone Oil Pipeline system has long-term commitments for 910,000 Bbl/d for an average term of approximately 18 years.  This includes commitments made by shippers to sign transportation service agreements for 35,000 Bbl/d capacity in an open season to be held in 2009.  The commitments represent approximately 83 per cent of the 1.1 million Bbl/d commercial design of the system.

·December 5, 2008.  The Alaska Commissioner of Revenue and Natural Resources issued the AGIA license to TCPL to advance the Alaska Pipeline Project, following on the approval by the Alaska Senate on August 1, 2008 of TCPL’s application for the license.  TCPL has committed under the AGIA to advance the Alaska Pipeline Project through an open season and subsequent United States Federal Energy Regulatory Commission (“FERC”) certification.  TCPL has commenced the engineering, environmental, field and commercial work, and expects to conclude an open season by July 31, 2010.  Under AGIA, the State of Alaska has agreed to reimburse a share of the eligible pre-construction costs to TCPL to a maximum of US$500 million.

·TCPL agreed to increase its equity ownership in Keystone U.S. and TransCanada Keystone Pipeline Limited Partnership (“Keystone Canada”) up to 79.99 per cent from 50 per cent with ConocoPhillips’ equity ownership being reduced concurrently to 20.01 per cent.

·TCPL continued funding of the Mackenzie Valley Aboriginal Pipeline Limited Partnership for its participation in the Mackenzie Gas Pipeline Project, a proposed 1,200 km (746 mile) 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.

Regulatory Matters

·January 2008. Gas Transmission Northwest Corporation (“GTNC”), a wholly-owned subsidiary of TransCanada, filed a Stipulation and Agreement with the 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 were effective retroactive to January 1, 2007.

·March 18, 2008.  TCPL filed an application with the National Energy Board (“NEB”) to increase the interim tolls on its Canadian gas pipeline system (the “Canadian Mainline”) previously approved in December 2007.  This toll increase was a result of a significant decrease in forecasted flows on the Canadian Mainline and was intended to allow TCPL to more accurately meet its 2008 revenue requirement.  On March 28, 2008, the NEB approved the amended interim tolls for transportation service effective April 1, 2008.

·June 17, 2008.  TCPL filed an application with the NEB to establish federal regulation for TCPL’s Alberta System.  The application for a certificate of public convenience and necessity and related approvals was made to recognize that TCPL’s Alberta System was subject to Canadian federal jurisdiction and its operations to regulation by the NEB.  An oral  hearing to discuss this matter began on November 18, 2008 and concluded on November 28, 2008.  A decision on the matter is expected to be issued by the end of February 2009.  Currently, the provincial regulation of the Alberta System precludes TCPL from acquiring, constructing or operating facilities that transport natural gas across Alberta provincial borders.  Federal regulation would enable the Alberta System to extend across provincial borders, thereby providing integrated service to Alberta and British Columbia customers, and northern natural gas producers.

TRANSCANADA PIPELINES LIMITED     4

·June, 2008.  The NEB approved TCPL’s application for additional pumping facilities required to expand the Canadian portion of the Keystone Oil Pipeline project from a nominal capacity of approximately 435,000 Bbl/d to 590,000 Bbl/d to accommodate volumes to be delivered to the Cushing markets, after holding an oral hearing on April 8, 2008.  The hearing and decision followed on an application filed by Keystone Canada with the NEB in November 2007.

·October 10, 2008.  The Alberta Utilities Commission (“AUC”) approved TCPL’s application for a permit to construct the North Central Corridor expansion, at a cost of approximately $925 million.  The expansion comprises a 42-inch, 300 km (186 mile)  natural gas pipeline and associated compression facilities on the northern section of the Alberta System.  Construction on the project began in October 2008.  The decision followed on a non-routine application filed with the Alberta Energy and Utilities Board (“EUB”) on November 20, 2007.

·December 17, 2008.  The AUC approved NGTL’s 2008-2009 Revenue Requirement Settlement Application as filed, in its entirety.  As part of the settlement, fixed costs were established for operation, maintenance and administration costs, return on equity and income taxes.  Any variances between actual costs and those agreed to in the settlement accrue to TCPL, subject to a return on equity and income tax adjustment mechanism, which accounts for variances between actual and settlement rate base and income tax assumptions.  The other cost elements of the settlement are treated on a flow-through basis.  The AUC also approved the 2008 Interim Rates of NGTL on a final basis for the period January 1, 2008 to December 31, 2008.

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

2007

Pipeline Developments

·February 9, 2007. TCPL received approval from the NEB to transfer a section of its Canadian Mainline 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 Oil Pipeline from approximately 435,000 Bbl/d to 590,000 Bbl/d and the construction of a 468 kilometre 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 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 Great Lakes. TCPL subsequently became the operator of NBPL and now operates all three TC PipeLines, LP investments.  The acquisition was financed partly through an offering of 39,470,000 subscription receipts at $38.00 per subscription receipt, which resulted in gross proceeds to TCPL of approximately $1.725 billion including the exercise of an over-allotment option granted to the underwriters.  Upon closing of the acquisition of ANR, the subscription receipts were automatically exchanged, without the payment of any additional consideration by the subscribers, on a one-to-one basis for common shares of TransCanada (“Common Shares”).

·December 2007. ConocoPhillips contributed $207 million to acquire a 50 per cent ownership interest in the Keystone Oil Pipeline.  Affiliates of TCPL will be responsible for constructing and operating the Keystone Oil Pipeline.

Regulatory Matters

·February 2007. TCPL received approval from the NEB to integrate its natural gas pipeline system in southern British Columbia with its natural gas pipeline systems in southern Alberta and southwestern Saskatchewan (collectively, the “Foothills System”) 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.

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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 an additional 49 per cent ownership interest 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 an increase in the deemed common equity ratio to 36 per cent from 33 per cent and incentives for managing costs 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.

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.

2009

·February 19, 2009.  The FERC approved two separate applications filed by TransCanada on December 19, 2008 requesting approval to charge negotiated rates and to proceed with an open season in the spring of 2009 for each of the Zephyr (“Zephyr”) and Chinook (“Chinook”) transmission line projects.  Both projects are proposed 500 kilovolt high voltage direct current transmission projects.  Zephyr is a proposed 1,760 km (1,100 mile) transmission line that would originate in Wyoming, and Chinook is a proposed 1,600 km (1,000 mile) project that would originate in Montana.  Both projects would terminate in Nevada, and it is anticipated that each would deliver 3,000 MW of primarily wind generation resources to markets in the southwestern United States.  Pending successful completion of the open seasons, regulatory work could commence later in 2009.

2008

Energy Developments

·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.  This process was expected to result in a further increase in the total project cost to complete the Unit 1 and 2 restart. 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.

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·February 2008. The potential anchor LNG supplier for the Cacouna LNG project (“Cacouna”) terminal in Québec announced it would no longer be pursuing the development of its LNG supply as originally planned. Although Cacouna received its primary regulatory approvals, project development has been suspended until alternate LNG supply is acquired and the North American market for LNG grows.

·April 2008.  The comprehensive review of costs to complete the Bruce A Units 1 and 2 refurbishment and restart project was completed.  Based on this assessment, the capital cost for the restart and refurbishment of Bruce A Units 1 and 2 is expected to be approximately $3.4 billion, up from an original 2005 cost estimate of $2.75 billion.  TCPL’s share is expected to be approximately $1.7 billion compared to an original estimate of $1.4 billion.

·May 12, 2008.  TCPL announced that the Phoenix, Arizona based utility, Salt River Project, signed a 20 year power purchase agreement to secure 100 per cent of the output from the Coolidge Generating Station (“Coolidge”), a 575 MW simple-cycle natural gas-fired peaking power generation station currently in development to be located 72 km (45 miles) southeast of Phoenix in Coolidge, Arizona.  In December 2008, the Arizona Corporation Commission granted a Certificate of Environmental Compatibility approving Coolidge.  Construction is scheduled to begin in the summer of 2009, and the facility is expected to be commissioned in 2011.

·May 30, 2008.  Portlands Energy Centre, a natural gas-fired combined-cycle power plant near downtown Toronto, Ontario (“Portlands Energy Centre”) went into service in simple-cycle mode capable of delivering 340 MW of power during the summer of 2008.  Portlands Energy Centre, which is 50 per cent owned by TCPL, is currently under construction and is expected to be fully commissioned in combined-cycle mode in first quarter 2009 with delivery capabilities of 550 MW of power.

·July 4, 2008.  Hydro-Québec Distribution notified the Régie the L’énergie that it would exercise its option to extend the suspension of all electricity generation from TCPL’s 550 MW Bécancour cogeneration power plant near Trois-Rivières, Québec (“Bécancour”) throughout 2009.  This followed on TCPL’s agreement with Hydro-Québec Distribution to temporarily suspend all electricity generation from Bécancour during 2008. TCPL will continue to receive payments under the agreement similar to those that would have been received under the normal course of operation.

·July 9, 2008.  TCPL announced that the Kibby Wind Power Project received unanimous final development plan approval from Maine’s Land Use Regulation Commission.  Construction on the project began in July 2008.  The capital cost of the project is expected to be approximately US$320 million with commissioning of the first phase expected to begin in fourth quarter 2009.

·August 26, 2008.  TCPL completed its acquisition of the 2,480 MW Ravenswood Generating Station (“Ravenswood”) located at Queen’s, New York for US$2.9 billion, subject to certain post-closing adjustments.  The acquisition was completed pursuant to a membership interest and stock purchase agreement between KeySpan Corporation, KeySpan Energy Corporation and TransCanada Facility USA, Inc. dated March 31, 2008 (the “Ravenswood Agreement”) whereby TransCanada Facility USA, Inc. agreed to acquire all of the outstanding membership interests of KeySpan-Ravenswood, LLC and all of the outstanding shares of KeySpan Ravenswood Services Corp. from National Grid plc.  KeySpan-Ravenswood, LLC directly or indirectly owned or controlled Ravenswood.  The acquisition was financed through a combination of equity and term debt offerings, funds drawn on a newly established bridge loan facility and cash on hand (see “Financing Activities” below).

·November 22, 2008.  The Carleton wind farm, the third of six phases of a wind energy project contracted by Hydro-Québec Distribution in the Gaspé Region of Québec (the “Cartier Wind Energy Project”), went into service and is capable of generating 109 MW of power.

·In fourth quarter 2008, Bruce Power completed a review of the end of life estimates for Units 3 and 4.  Unit 3 is now expected to be in commercial service until 2011, which provides the benefit of nearly two additional years of generation before the unit commences an expected 36-month refurbishment period.  After the refurbishment period, the end of life estimate for Unit 3 is expected to increase from the originally expected date of 2037 to 2038.  In addition, Unit 4 is now expected to be in commercial service until 2016, providing nearly seven years of generation before the unit commences a similar refurbishment period, after which, the end of life estimate for Unit 4 is expected to increase from the originally expected date of 2036 to 2042.

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Regulatory Matters

·January 11, 2008. The FERC issued its FEIS for the Broadwater LNG project (“Broadwater”).  A joint venture with Shell US Gas & Power LLC, Broadwater is 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, Broadwater’s proposed mitigation measures and the FERC’s recommendations, the project will not result in a significant impact on the environment.

·March 24, 2008.  FERC authorized the construction and operation of Broadwater, subject to the conditions reflected in the authorization.  On April 10, 2008, the New York State Department of State (“NYSDOS”) determined that construction and operation of the project would not be consistent with the state’s coastal zone policies.  As a result of this unfavourable decision, TCPL wrote down $27 million after tax of costs for Broadwater that had been capitalized to March 31, 2008.  On June 6, 2008, Broadwater Energy, LLC filed an appeal with the United States Secretary of Commerce on the decision of the NYSDOS asking the Secretary of Commerce to override the NYSDOS decision on the basis that the project meets the criteria for approval under the Coastal Zone Management Act and applicable regulations.  A decision is expected in early 2009.

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

2007

Energy Developments

·June 2007. Following public hearings in 2006, the Québec government granted a provincial decree approving Cacouna.  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 regasification terminal from 2010 to 2012. This delay resulted from a need to assess impacts of permit conditions, to review the facility design in light of escalating costs and to align the schedule with potential LNG supply facilities.

·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 109 MW Carleton wind farm.

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 Bécancour 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 NYSDOS 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.

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Financing Activities

2009

·January 6, 2009.  TCPL entered into an underwriting agreement with a syndicate of underwriters led by Citigroup Global Markets Inc. and HSBC Securities (USA) Inc. under which the underwriters agreed to purchase from TCPL and sell to the public US$750 million and US$1.25 billion of Senior Unsecured Notes maturing on January 15, 2019 and January 15, 2039, respectively, and bearing interest at 7.125 per cent and 7.625 per cent, respectively.  The offering was completed on January 9, 2009.  The proceeds from these notes are expected to be used to partially fund TCPL’s capital projects, retire maturing debt obligations and for general corporate purposes.  These notes were issued under a US$3.0 billion debt shelf prospectus filed on January 2, 2009.

·February 17, 2009.  TCPL completed the issuance of $300 million and $400 million of Medium-Term Notes maturing on February 14, 2014 and February 17, 2039, respectively, and bearing interest at 5.05 per cent and 8.05 per cent, respectively.  The proceeds from these notes are expected to be used to fund the Alberta System and Canadian Mainline rate bases.  These notes were issued under a $1.5 billion debt shelf prospectus filed in March, 2007.

2008

·May 5, 2008.  TransCanada entered into an underwriting agreement with a syndicate of underwriters led by BMO Nesbitt Burns Inc., RBC Dominion Securities Inc., and TD Securities Inc. under which the underwriters agreed to purchase from TransCanada 30,200,000 Common Shares and sell the Common Shares to the public at a purchase price of $36.50 per Common Share.  The underwriters were also granted an over-allotment option to purchase an additional 4,530,000 Common Shares at the same price.  The offering was completed on May 13, 2008 and together with the full exercise of the over-allotment option by the underwriters, 34,730,000 Common Shares were issued and resulted in gross proceeds to TCPL of approximately $1.27 billion to be used by TCPL to partially fund acquisitions and capital projects of TCPL including, amongst others, the acquisition of Ravenswood, the construction of the Keystone Oil Pipeline, and for general corporate purposes.  These Common Shares were issued under the base shelf prospectus filed in January, 2007.

·June 27, 2008.  TCPL executed an agreement with a syndicate of banks for a US$1.5 billion, committed, unsecured, one-year bridge loan facility, at a floating interest rate based on the London Interbank Offered Rate (“LIBOR”) plus 30 basis points.  The facility is extendible at the option of TCPL for an additional six month term at LIBOR plus 35 basis points.  On August 25, 2008, TCPL utilized US$255 million from this facility to fund a portion of the Ravenswood acquisition and cancelled the remainder of the commitment.  At December 31, 2008, the US$255 million remained outstanding on the facility.

·August 6, 2008.  TCPL entered into an underwriting agreement with a syndicate of underwriters led by Citigroup Global Markets Inc. and J.P. Morgan Securities Inc. under which the underwriters agreed to purchase from TCPL and sell to the public US$850 million and US$650 million of Senior Unsecured Notes maturing on August 15, 2018 and August 15, 2038, respectively, and bearing interest at 6.5 per cent and 7.25 per cent, respectively.  The offering was completed on August 11, 2008.  The proceeds from these notes were used to partially fund the Ravenswood acquisition and for general corporate purposes.  These notes were issued under a US$2.5 billion debt shelf prospectus filed in September, 2007.

·August 20, 2008.  TCPL completed an issuance of $500 million of Medium-Term Notes maturing in  August 2013 and bearing interest at 5.05 per cent.  The proceeds from these notes were used to partially fund the Alberta System’s capital program and for general corporate purposes.  These notes were issued under the debt shelf prospectus filed in March, 2007.

·November 17, 2008.  TransCanada entered into an underwriting agreement with a syndicate of underwriters led by RBC Dominion Securities Inc., BMO Nesbitt Burns Inc., and TD Securities Inc. under which the underwriters agreed to purchase from TransCanada 30,500,000 Common Shares and sell the Common Shares to the public at a purchase price of $33.00 per Common Share.  The underwriters were also granted an over-allotment option to purchase an additional 4,575,000 Common Shares at the same price.  The offering was completed on November 25, 2008 and resulted in gross proceeds to TCPL of approximately $1 billion to be used by TCPL to partially fund its capital projects, including the Keystone Oil Pipeline, for general corporate purposes and to repay short-term indebtedness.  The syndicate of underwriters fully exercised the over-allotment option on December 5, 2008 for additional gross proceeds to TCPL of $151 million.  The Common Shares were issued under the base shelf prospectus filed in July, 2008.

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·In November 2008, TCPL established a US$1.0 billion committed, unsecured bank facility with a syndicate of banks.  The facility bears interest at a floating rate plus a margin.  The facility has an initial term of 364 days with a one-year renewal at the option of the borrower and will support a new commercial paper program dedicated to funding a portion of expenditures for the Keystone Oil Pipeline and for general partnership purposes.  As at December 31, 2008, no draws had been made on this facility

Further information about financing activities can be found in the MD&A under the headings “Short-Term Debt Financing Activities”, “2009 and 2008 Long-Term Debt Financing Activities”, “2007 Long-Term Debt Financing Activities”, “2006 Long-Term Debt Financing Activities”, “2008 Equity Financing Activities” and “2007 Equity Financing Activities”.

BUSINESS OF TCPL

TCPL is a leading North American energy infrastructure company focused on pipelines and energy. At Year End, Pipelines accounted for approximately 54 per cent of revenues and 64 per cent of TCPL’s total assets and Energy accounted for approximately 46 per cent of revenues and 30 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, 2008 and 2007.

Revenues From Operations (millions of dollars)	2008	2007
Pipelines
Canada - Domestic	$2,005	$2,227
Canada - Export(1)	1,123	1,003
United States	1,522	1,482
	4,650	4,712
Energy(2)
Canada – Domestic	2,594	2,792
Canada - Export(1)	2	3
United States	1,373	1,321
	3,969	4,116
Total Revenues(3)	$8,619	$8,828

(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 (36,661 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 Canadian Mainline is a 100 per cent owned 14,101 km (8,762 mile) 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.

·TCPL’s Alberta System is a 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 and with the natural gas pipelines of other companies. The 23,705 km (14,730 mile) system is one of the largest carriers of natural gas in North America.

·Keystone Oil Pipeline is a 3,456 km (2,147 mile) oil pipeline project currently 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. In addition, an expansion to the United States Gulf Coast is under development, which is expected to add

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approximately 2,720 km (1,690 miles) of pipe to the system.  Commissioning of the segment to Wood River and Patoka is expected to begin in late 2009.  Commissioning of the segment to Cushing is expected to begin in late 2010.  The expansion to the United States Gulf Coast is expected to be commissioned in 2012, subject to regulatory approvals. Keystone Oil Pipeline was 62 per cent owned by TCPL as at December 31, 2008 and TCPL has agreed to increase its equity ownership in Keystone U.S. and Keystone Canada up to 79.99 per cent.  In accordance with this agreement, TransCanada will fund 100 per cent of the construction expenditures until the participants’ project capital contributions are aligned with the revised ownership interests.  Certain parties that have made volume commitments to the Keystone Oil Pipeline expansion have an option to acquire up to a combined 15 per cent equity ownership in Keystone U.S. and Keystone Canada by end of first quarter 2009.  If all of the options are exercised, TCPL’s equity ownership would be reduced to 64.99 per cent.

·TCPL’s Foothills System is a 100 per cent owned, 1,241 km (771 mile) natural gas transmission system in Western Canada which 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.

·TransCanada Pipeline Ventures LP, which is 100 per cent owned by TCPL, owns a 161 km (100 mile) pipeline and related facilities that supply natural gas to the oil sands region of northern Alberta as well as a 27 km (17 mile) pipeline that supplies natural gas to a petrochemical complex at Joffre, Alberta.

·TransCanada Québec & Maritimes Pipeline Inc. (“TQM”) is 50 per cent owned by TCPL. TQM is a 572 km (355 mile) 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 (10,563 mile) natural gas transmission system which 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 providing access to diverse sources of North American supply, including Western Canada, and the mid-continent and Rocky Mountain supply regions, and a variety of markets in the Midwestern and northeastern U.S.

·Underground gas storage facilities owned and operated by ANR provide regulated gas storage services to customers on the ANR System and the Great Lakes Gas Transmission System (“Great Lakes System”) in upper Michigan.  In 2008, ANR completed its storage enhancement project and added 14 billion cubic feet (“Bcf”) of storage.  In total, the ANR business unit operates sixteen underground natural gas storage facilities throughout the State of Michigan with total natural gas storage capacity of 250 Bcf.

·The GTN System (“GTN System”) is TCPL’s 100 per cent owned natural gas transmission system which extends 2,174 km (1,351 miles) 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.

·Bison pipeline is a proposed 480 km (298 mile) pipeline from the Powder River Basin in Wyoming to the Northern Border Pipeline System in North Dakota.  The Bison pipeline has shipping commitments for approximately 405 mmcf/d and is expected to be in-service in fourth quarter 2010.  TCPL is continuing to work with prospective Bison shippers to advance this project.

·North Baja is TCPL’s 100 per cent owned natural gas transmission system which extends 129 km (80 miles) 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 System is owned 53.6 per cent by TCPL and 46.4 per cent by TC Pipelines, LP. The 3,404 km (2,115 mile) Great Lakes System connects with the Canadian Mainline at Emerson, Manitoba, and serves markets primarily in Central Canada and the Midwestern U.S. TCPL operates the Great Lakes System 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 Northern Border Pipeline System (“NBPL System”) is 50 per cent owned by TC PipeLines, LP and is a 2,250 km (1,398 mile) natural gas transmission 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 the NBPL System through its 32.1 per cent interest in TC PipeLines, LP.

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·Tuscarora is 100 per cent owned by TC PipeLines, LP and has a 491 km (305 mile) pipeline system transporting natural gas from the GTN System at Malin, Oregon to Wadsworth, Nevada (the “Tuscarora System”) with delivery points in northeastern California and northwestern Nevada.  TCPL operates the Tuscarora System and effectively owns 32.1 per cent of the system through its 32.1 per cent interest in TC PipeLines, LP.

·The Iroquois Gas Transmission System (“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 (414 mile) pipeline system.

·The Portland System is a 474 km (295 mile) 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.

·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 the NBPL System, the remaining 46.4 per cent in the Great Lakes System and 100 per cent of Tuscarora.

·The Palomar pipeline project is a proposed 349 km (217 mile) pipeline extending from the GTN System to the Columbia River northwest of Portland.  In December 2008, Palomar Gas Transmission LLC filed with the FERC for a certificate to build this pipeline, which is a 50/50 joint venture of GTNC and Northwest Natural Gas Co.

International

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

·TransGas is a 344 km (214 mile) natural gas pipeline system which runs from Mariquita in the central region of Colombia to Cali in the southwest of Colombia. TCPL holds a 46.5 per cent ownership interest in this pipeline.

·Gas Pacifico is a 540 km (336 mile) 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 (81 mile) 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”, “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

Effective January 1, 2008, the EUB was reorganized into the Energy Resources Conservation Board and the AUC.  The AUC regulates all the physical and economic aspects of the Alberta System which were previously regulated 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 are subject to approval by the AUC. Under the provisions of the Pipeline Act, the AUC oversees various matters including the economic, orderly and efficient development of pipeline facilities, the operation and abandonment of the facilities and certain related pollution and environmental conservation issues. In addition to

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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.

In June 2008, TCPL filed an application with the NEB seeking a determination that the Alberta System is within Canadian federal jurisdiction and subject to regulation by the NEB.  TCPL also requested approvals to operate the Alberta System under NEB regulation.  A hearing on the application was held in November 2008 and a decision is expected by the end of February 2009.

KEYSTONE OIL PIPELINE

TransCanada is presently constructing the Canadian and U.S. sections of the Keystone Oil Pipeline and expects to place the base facilities into service in late 2009.  The NEB regulates the terms and conditions of service, including rates, and the physical operation of the Canadian portion of the pipeline. NEB approval is also required for facility additions, such as the Canadian portion of the proposed Gulf Coast expansion project.

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.

The FERC also regulates the terms and conditions of service, including rates, on the U.S. portion of the Keystone Oil Pipeline. However, primary approvals for any facility additions to the Keystone Oil Pipeline are obtained from state agencies.

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, 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 10,900 MW of power generation capacity. Power plants and power supply in Canada account for approximately 60 per cent of this total, and power plants in the U.S. account for the balance, being approximately 40 per cent.

TCPL owns and operates the following facilities:

·Ravenswood, located in Queen’s, New York, is a 2,480 MW power plant that consists of multiple units employing steam turbine, combined cycle and combustion turbine technology.  Ravenswood has the capacity to serve approximately 21 per cent of New York City’s peak load.

·TC Hydro, TCPL’s hydroelectric facilities located in New Hampshire, 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.

·Ocean State Power, a 560 MW natural gas-fired, combined-cycle facility in Burrillville, Rhode Island.

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

·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.

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·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.

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

·TCPL has the rights to 100 per cent of the generating capacity of the 560 MW Sundance A coal-fired power generation facility under a Power Purchase Agreement (“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 Sundance facilities are located in south-central Alberta.

·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 PPA, which expires in 2020 (“Sheerness”).

TCPL has interests in the following:

·Two generating stations, Bruce A which currently generates 1,500 MW and is expected to produce an additional 1,500 MW of power when restart of Units 1 and 2 is completed in 2010, and Bruce Power L.P. (“Bruce B”) with approximately 3,200 MW of generating capacity.  Bruce Power is a partnership with generating facilities and offices located on 2,300 acres northwest of Toronto, Ontario on which are housed Bruce A and Bruce B.  TCPL owns 48.9 per cent of Bruce A which has four 750 MW reactors, two of which are currently being refurbished and are expected to restart in 2010.  TCPL owns 31.6 per cent of Bruce B, which has four operating reactors.

·A 60 per cent ownership in CrossAlta, which is an underground natural gas storage facility connected to the Alberta System 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 the Carleton (109 MW), Anse-à-Valleau (101 MW), and Baie-des-Sables (110 MW) wind farms, the first three phases of the Cartier Wind Energy Project, which commenced commercial operation in November 2008, November 2007 and November 2006, respectively.

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

·The Cartier Wind Energy Project consists of six wind projects in the Gaspé region of Québec contracted by Hydro-Québec Distribution representing a total of 740 MW when all six wind projects are complete.  Three of the wind farms are constructed and in service as noted above and the remaining three projects are under planning and development are expected to be constructed through 2012, subject to the necessary approvals. Cartier Wind is 62 per cent owned by TCPL.

·The Portlands Energy Centre, a 550 MW high efficiency, combined-cycle natural gas generation power plant located in Toronto, Ontario is 50 per cent owned by TCPL and is under construction. The plant went into service in simple-cycle mode, capable of delivering 340 MW of electricity in the summer of 2008. It is anticipated to be fully commissioned in its combined-cycle mode, with delivery capabilities of 550 MW of power in the first 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.

·The Coolidge generating station is a simple-cycle, natural gas-fired peaking power generation station under development in Coolidge, Arizona.  Based on optimal operating conditions, TCPL predicts an electrical output of approximately 575 MW from this facility, designed to provide a quick response to peak power demands.  The project has received its required permits, and construction is expected to commence in the third quarter of 2009 with commissioning expected in 2011.  When constructed, the power output will be supplied to Salt River Project Agricultural Improvement and Power District under a 20-year power purchase contract.

·The proposed 132 MW Kibby wind power project is under construction and is expected to include 44 turbines located in Kibby and Skinner townships in Maine.  Construction began in July 2008 and commissioning of the first phase is expected to begin in fourth quarter 2009.

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”, “Energy — Financial Analysis” and “Energy — Opportunities and Developments”.

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GENERAL

Employees

At Year End, TCPL had approximately 3,987 employees, substantially all of whom were employed in Canada and the U.S., as set forth in the following table.

Western Canada	454
Calgary	1,697
Eastern Canada	242
U.S. West Coast	146
U.S. Mid West	478
U.S. Northeast	379
U.S. Southeast/Gulf Coast	246
Houston	342
Mexico and Chile	3
Total	3,987

Social and Environmental Policies

Health, safety and environment (“HS&E”)  is a priority in all of TCPL’s operations and is guided by its HS&E Commitment Statement.  The HS&E Commitment Statement outlines guiding principles for a safe and healthy environment for TCPL’s employees, contractors and the public, and for the protection of the environment.  All employees are held responsible and accountable for HS&E performance. Roles and responsibilities of employees are clearly defined to ensure appropriate financial, human and organizational resources are available to plan, implement and sustain the HS&E management system, and to ensure that each employee understands his or her role in HS&E management system implementation, success and continuous improvement.  TCPL is committed to being an industry leader in conducting its business so that it meets or exceeds all applicable laws and regulations, and minimizes risk to people and the environment.  TCPL is committed to tracking and improving its HS&E performance, and to promoting safety on and off the job, in the belief that all occupational injuries and illnesses are preventable.  TCPL endeavors to do business with companies and contractors that share its perspective on HS&E performance, and to influence them to improve TCPL’s collective performance.  TCPL is committed to respecting the diverse environments and cultures in which it operates, and to supporting open communication with the public, policy makers, scientists and public interest groups with whom we share stewardship of the world we inhabit.

TCPL is committed to ensuring conformance with its internal policies and regulated requirements.  The HS&E Committee of TCPL’s board of directors (the “Board”) monitors conformance with the Company’s HS&E corporate policy through regular reporting.  TCPL’s HS&E management system is modeled on 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 informed regularly of all important HS&E operational issues and initiatives through formal reporting processes.  TCPL’s HS&E management system and performance are assessed by an independent outside firm every three years.  The most recent assessment occurred in November 2006.  The HS&E management system also is subject to ongoing internal review to ensure that it remains effective as circumstances change.

In 2008, employee and contractor health and safety performance continued to be a top priority.  Overall safety rates continue to perform significantly better than most industry benchmarks.  TCPL’s assets were highly reliable in 2008 and there were no incidents that were material to TCPL’s operations.

The safety of the public and integrity of our pipelines is a top priority of TransCanada.  The Company expects to spend approximately $185 million in 2009 for pipeline integrity on its wholly owned pipelines, which is higher than the amount spent in 2008 primarily due to increased levels of in-line pipeline inspection on all systems.  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.  Expenditures on the GTN System are also recovered through a cost recovery mechanism in its rates.  Pipeline safety in 2008 continued to be very good.  TCPL experienced one small-diameter pipeline failure in a remote part of east central Alberta.  The line break resulted in minimal impact with no injuries or property damage.  Spending associated with public safety on the Energy assets is focused primarily on hydro dams and associated equipment, and is consistent with previous years.

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Environmental Protection

TCPL’s facilities are subject to various federal, provincial, state and local statutes and regulations regarding environmental quality and pollution control.  Environmental risks from TCPL’s operating facilities typically include: air emissions, such as nitrogen oxides (“NOx”), particulate matter and greenhouse gases; potential impacts on land, including land reclamation or restoration following construction; the use, storage or release of chemicals or hydrocarbons; the generation, handling and disposal of wastes and hazardous wastes; and water impacts such as uncontrolled water discharge.   Environmental controls including physical design, programs, procedures and processes are in place to effectively manage these risks. TCPL has ongoing inspection programs designed to keep all of our facilities in compliance with environmental requirements and we are confident that our systems are in material compliance with the applicable requirements.

TCPL is not aware of any material 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.

In 2008, TCPL conducted various environmental risk assessments and remediation work, resulting in total costs of approximately $7.0 million for work conducted on TransCanada’s Canadian facilities and US$5.5 million for work conducted on our U.S. facilities.  TCPL also conducted various retirement, reclamation and restoration work in 2008.  Total costs were approximately $7.3 million.

In North America, climate change policy continues to evolve at regional and national levels. In 2008, policies related to industrial greenhouse gas (“GHG”) emissions were in effect in Alberta, British Columbia and Québec and affected TCPL’s assets located in those jurisdictions as discussed below.

In Alberta, the Specified Gas Emitters Regulation (“SGER”), which came into effect in 2007, requires industrial facilities to reduce GHG emissions intensities on an annual basis by 12 per cent from the baseline period, which has been established as the average emissions intensities in 2003, 2004 and 2005. A number of compliance mechanisms are available for those facilities unable to meet this target.  TCPL’s Alberta-based pipe and power facilities are subject to this regulation, as are the Sundance and Sheerness coal-fired power facilities with which TCPL has commercial arrangements. The cost of compliance incurred by TCPL’s Alberta-based facilities related to SGER was approximately $12 million covering the period from July 1, 2007, the date of implementation of the SGER, to December 31, 2007.  Costs for 2008 compliance are estimated to be $28 million and will be finalized when compliance reports are submitted at the end of March 2009.  Compliance costs of the Alberta System pipeline network are recovered through tolls paid by customers.  Compliance costs for the Company’s power generation facilities and interests in Alberta are partially recovered through contracts and the impact of increased operating costs on Alberta power market prices.

The hydrocarbon royalty in Québec is collected by the natural gas distributor on behalf of the Québec Government via a green fund contribution charge on gas consumed. In 2008, the cost to Bécancour was less than $1.0 million as a result of an agreement between TCPL and Hydro-Québec Distribution to temporarily suspend the facility’s power generation. The financial charges are expected to increase substantially in 2010 when the plant returns to service.

British Columbia’s carbon tax, which came into effect in 2008, applies to carbon dioxide emissions arising from fossil fuel combustion. Compliance costs for fuel combustion at the Company’s compressor and meter stations in British Columbia are recovered through tolls paid by customers. Costs related to the carbon tax for 2008 are approximately $1 million.  This cost is expected to increase over the next four years as the tax rate (charge per tonne carbon dioxide) increases by $5 per tonne annually from the initial tax rate of $10 per tonne carbon dioxide.

RISK FACTORS

Environmental Risk Factors

As indicated above, there are multiple environmental risks associated with TCPL’s operating facilities and as a consequence TCPL’s operations are subject to various environmental laws and regulations that establish compliance and remediation obligations. Compliance obligations can result in significant costs associated with installing and maintaining pollution controls, fines and penalties resulting from any failure to comply, and potential limitations on operations. Remediation obligations can result in significant costs associated with the investigation and remediation of contaminated properties (some of which have been designated as Superfund sites by the United States Environmental Protection Agency under the Comprehensive Environmental Response, Compensation and Liability Act), and with damage claims arising out of the contamination of properties or impact on natural resources. It is not possible for us to estimate exactly the amount and timing

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of all future expenditures related to environmental matters due to:

·uncertainties in estimating pollution control and clean up costs, including sites where only preliminary site investigation or agreements have been completed;

·the potential discovery of new sites or additional information at existing sites;

·the uncertainty in quantifying liability under environmental laws that impose joint and several liability on all potentially responsible parties;

·the evolving nature of  environmental laws and regulations, including the interpretation and enforcement thereof; and

·the potential for litigation on existing or discontinued assets.

At December 31, 2008, TCPL had accrued approximately $86 million for compliance and remediation obligations.  TCPL believes that it has considered all necessary contingencies and has established appropriate reserves for environmental liabilities; however there is the risk that unforeseen matters may arise requiring us to set aside additional monies.

In addition to those climate change policies already in force and which are described above under the heading “Environmental Protection”, there are also several federal (Canada and U.S.), regional and provincial initiatives currently in development.  While recent political and economic events may significantly impact the scope and timing of new measures that are put in place, TCPL anticipates that most of the Company’s facilities in Canada and the United States will be captured under future regional and/or federal climate change regulations to manage industrial GHG emissions.  Certain of these initiatives are outlined below.

TCPL expects a number of its facilities will be affected by future Canadian federal climate change regulations.  In April 2007, the Government of Canada released the Regulatory Framework for Air Emissions (“Framework”).  The Framework outlines short-, medium- and long-term objectives for managing both GHG emissions and air pollutants in Canada.  It is not known at this time whether the impacts from the pending regulations will be material as draft regulations have not been released.  The Canadian government has also recently expressed interest in pursuing the development of a North American cap and trade system for GHG emissions.  It is uncertain how the Framework will fit within a North American cap and trade system and what the specific requirements for industrial emitters will be.  In the U.S., climate change is a strategic issue for the new administration and federal policy to manage domestic GHG emissions will be a priority.

At a regional level, seven western states and four Canadian provinces (British Columbia, Manitoba, Ontario and Québec) are focused on the implementation of a cap and trade program under the Western Climate Initiative (“WCI”). In the northeastern U.S., states that are members of the Regional Greenhouse Gas Initiative (“RGGI”) implemented a CO2 cap and trade program for electricity generators effective January 1, 2009. Participants in the Midwestern Greenhouse Gas Reduction Accord, which involves six states and one province (Manitoba), are developing a regional strategy for reducing members’ GHG emissions that will include a multi sector cap and trade mechanism.

At a provincial level, TCPL has assets located in Ontario and Manitoba, where the provincial governments have announced climate change strategies that will impact industrial sources of GHG emissions (as mentioned above, British Columbia, Alberta and Québec already have policies in place). Details of these programs and information about how provincial programs will align with the Canadian government’s climate change policies are still not available.

The Company expects a number of its facilities will be affected by new legislative initiatives in the United States. Under RGGI, both Ravenswood and Ocean State Power generation facilities will be required to submit allowances shortly after December 31, 2011. It is expected that the costs will be recovered from the market and the net impact to TCPL will be minimal. Company assets located in WCI and Midwestern Greenhouse Gas Reduction Accord member states and in California will be covered by measures put in place in these states, however the level of impact is not known at this time as key policy details remain outstanding.

TCPL monitors climate change policy developments and, when warranted, participates in policy discussions in jurisdictions where the Company has operations.  TCPL is also continuing its programs to manage GHG emissions from its facilities and to evaluate new processes and technologies that result in improved efficiencies and lower GHG emission rates.

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Other Risk Factors

A discussion of the Company’s risk factors can be found in the MD&A for the year ended December 31, 2008 under the headings “Pipelines - Opportunities and Developments”, “Pipelines - Business Risks”, “Pipelines – Outlook”, “Energy - Opportunities and Developments”, “Energy - Business Risks”, “Energy – Outlook”, “Corporate – Outlook” 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 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.

	2008	2007	2006
Dividends declared on common shares(1)	$1.49	$1.39	$1.28
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 598,016,657 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 of 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.

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Except as provided by the Canada Business Corporations Act or as referred to below, the holders of the first preferred shares will not have any voting rights nor will they be entitled to receive notice of or to attend shareholders’ meetings unless and until TCPL fails to pay, in the aggregate, six quarterly dividends on the first preferred shares, Series U.

The provisions attaching to the first preferred shares as a class may be modified, amended or varied only with the approval of the holders of the first preferred shares as a class. Any such approval to be given by the holders of the first preferred shares may be given by the affirmative vote of the holders of not less than 66 2¤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, medium term unsecured note debentures and junior subordinated notes with terms to maturity in excess of one year, during the 12 months ended December 31, 2008 and in 2009 up to the date of this AIF.

Date Issued	Issue Price per $1,000 Principal Amount of Notes	Aggregate Issue Price
August 11, 2008	US$999.26(1)	US$849,371,000
August 11, 2008	US$999.62(1)	US$649,753,000
August 20, 2008	$998.69	$499,345,000
January 9, 2009	US$999.77(2)	US$749,827,500
January 9, 2009	US$991.48(2)	US$1,239,350,000
February 17, 2009	$995.29	$389,116,000
February 17, 2009	$997.17	$299,151,000

(1)These notes were issued under the same prospectus supplement.  Notes maturing in 2018 were issued at 99.926% and notes maturing in 2038 were issued at 99.962%.

(2)These notes were issued under the same prospectus supplement.  Notes maturing in 2019 were issued at 99.977% and notes maturing in 2039 were issued at 99.148%.

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 by DBRS Limited (“DBRS”), Moody’s Investors Service, Inc. (“Moody’s”) and Standard and Poor’s (“S&P”):

	DBRS	Moody’s	S&P
Senior Unsecured Debt
Debentures	A	A3	A-
Medium-term Notes	A	A3	A-
Junior Subordinated Notes	BBB (high)	Baa1	BBB
Preferred Shares	Pfd-2 (low)	Baa2	BBB
Commercial Paper	R-1 (low)	-	-
Trend/Rating Outlook	Stable	Stable	Stable

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.

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DBRS Limited (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 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 Investors Service, Inc. (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 A3 rating assigned to TCPL’s senior unsecured 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 Baa rating assigned to TCPL’s junior subordinated debt and preferred shares is the fifth highest of nine rating categories for long-term obligations, with the junior subordinated debt ranking slightly higher within the Baa rating category with a modifier of 1 as opposed to the modifier of 2 on the preferred shares. 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 slightly more 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.

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MARKET FOR SECURITIES

TransCanada holds all of the common shares of TCPL and these are not listed on a public market. During 2008, 66,340,502 common shares of TCPL were issued to TransCanada as set out in the following table:

Date	Number of TCPL Common Shares	Price per TCPL Common Share	Aggregate Issuance Price
December 8, 2008	4,421,212	$33.00	$145,900,000
November 25, 2008	24,518,932	$32.22	$790,000,000
October 31, 2008	1,331,521	$36.80	$49,000,000
August 22, 2008	31,086,142	$40.05	$1,245,000,000
July 31, 2008	1,645,244	$38.90	$64,000,000
April 30, 2008	1,878,581	$36.65	$68,850,000
January 31, 2008	1,458,870	$38.61	$56,327,000

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 and the NYSE for the period indicated:

Common Shares

Month	TSX (TRP)				NYSE (TRP)
	High ($)	Low ($)	Close ($)	Volume Traded	High (US$)	Low (US$)	Close (US$)	Volume Traded
December 2008	34.50	31.53	33.17	43,677,420	27.82	24.97	27.14	5,101,834
November 2008	37.45	30.29	32.70	46,435,859	32.59	23.52	26.37	5,418,243
October 2008	39.26	29.42	36.42	69,562,035	36.33	24.45	30.30	6,675,763
September 2008	40.60	35.95	38.17	49,809,072	37.96	34.01	36.15	3,557,196
August 2008	40.65	38.50	40.27	28,550,772	39.18	35.99	37.97	2,467,304
July 2008	39.99	36.47	39.70	35,668,563	39.29	35.72	38.74	3,765,973
June 2008	40.71	37.79	39.50	34,833,031	40.08	37.39	38.77	2,381,500
May 2008	40.04	36.77	39.16	44,457,100	40.64	35.94	39.38	2,978,200
April 2008	38.90	35.98	36.90	54,718,260	37.70	35.33	36.74	3,467,500
March 2008	40.60	36.97	39.55	28,273,379	41.25	36.38	38.53	2,852,100
February 2008	40.50	38.70	39.54	27,480,832	41.53	38.54	40.09	2,390,000
January 2008	40.97	36.21	39.57	30,366,638	41.31	35.60	39.23	3,438,700

In addition, TCPL’s Cumulative Redeemable First Preferred Shares, Series U (the “Series U Preferred Shares”) and Series Y (the “Series Y Preferred Shares”) are listed on the TSX.  The following table sets forth the reported monthly high and low trading prices and monthly trading volumes of the Series U Preferred Shares and the Series Y Preferred Shares.

Series U Preferred Shares and Series Y Preferred Shares

	Series U (TCA.PR.X)				Series Y (TCA.PR.Y)
Month	High ($)	Low ($)	Close ($)	Volume Traded	High ($)	Low ($)	Close ($)	Volume Traded
December 2008	44.20	38.92	41.66	136,613	41.83	39.31	41.63	109,874
November 2008	46.49	40.00	40.35	60,801	46.00	40.05	41.10	118,067
October 2008	47.41	44.00	44.95	51,869	47.10	42.40	45.49	152,091
September 2008	48.04	46.51	46.99	40,642	48.45	46.50	46.99	143,130
August 2008	48.00	47.00	47.50	31,191	48.90	47.25	47.85	61,989
July 2008	48.50	45.25	47.93	56,240	48.64	46.80	46.80	166,285
June 2008	49.39	48.20	48.50	47,835	49.14	48.03	48.48	173,118
May 2008	49.33	47.76	48.84	39,370	49.34	48.09	48.86	43,593
April 2008	50.34	48.18	48.95	34,870	50.09	48.00	48.30	40,184
March 2008	51.00	49.81	50.19	48,975	51.05	49.80	50.08	29,537
February 2008	51.40	50.00	50.85	41,536	51.24	50.20	51.00	33,462
January 2008	52.00	47.00	50.48	41,152	51.40	49.10	50.30	47,823

DIRECTORS AND OFFICERS

As of February 23, 2009, the directors and officers of TransCanada as a group beneficially owned, or exercised control or direction, directly or indirectly, over an aggregate of 1,401,751 Common Shares of TransCanada. This constitutes less than one per cent of TransCanada’s Common Shares. In addition, officers held exercisable options to acquire an aggregate of 1,777,523 additional Common Shares.  TransCanada collects this information from its directors and officers but otherwise has no direct knowledge of individual holdings of its securities.

TRANSCANADA PIPELINES LIMITED     21

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.  TransCanada will hold its annual meeting of common shareholders on Friday, May 1, 2009, and subject to the election of the thirteen nominees proposed for election to TransCanada’s board of directors, 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 shareholder’s meeting (or resolution of the sole shareholder) or until his or her successor is earlier elected or appointed.

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), Chair, Canwest Global Communications Corp. (communications) and Chair, International Advisory Board for Garda World Consulting & Investigation, a division of Garda World Security Corporation. 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 and Chair of the audit committee, Canadian Public Accountability Board from 2003 to 2009. Director, Toronto-Dominion Bank. Member of the Advisory Committees of the Peterson Institute of International Economics and the Canada Institute at the Woodrow Wilson International Centre. Member of the International Advisory Committee of the Asia Society and a director of the Stephen Leacock Foundation for Children.	1992
E. Linn Draper Lampasas, Texas United States	Director, Alliance Data Systems Corporation (data processing and services), Lead Director, Alpha Natural Resources, Inc. (mining), NorthWestern Corporation (conducting business as NorthWestern Energy) (oil and gas) and Lead Director of Temple-Inland Inc. (materials). Chair, President and Chief Executive Officer of Columbus, Ohio-based American Electric Power Co., Inc. from April 1993 to April 2004.	2005
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 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, Nexen Inc. (oil and gas).  Director, WestJet Airlines Ltd. 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.  Trustee of Yale University since July 1, 2008 and member of the Board of Overseers of the Boston Symphony Orchestra since September 2005.  Director of the MIT Center for Energy and Environmental Policy Research from 1999 to 2007 and Director of National Grid plc from 2000 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

TRANSCANADA PIPELINES LIMITED     22

Name and Place of Residence	Principal Occupation During the Five Preceding Years	Director Since
John A. MacNaughton(2), C.M. Toronto, Ontario Canada	Chair of the Business Development Bank of Canada and of CNSX Markets Inc. (formerly 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). Appointed by the Minister of Human Resources and Social Development as Nominating Committee Chair for the new Canada Employment Insurance Financing Board in 2008.  Founding President and Chief Executive Officer of the Canadian Pension Plan Investment Board from 1999 to 2005.	2006
David P. O’Brien(3) 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, Enerplus Resources Fund 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	Chair and Chief Executive Officer of Boise Cascade, LLC from November 2004 to November 30, 2008.  Director, Boise Inc.	2007(4)
D. Michael G. Stewart Calgary, Alberta Canada	Director, Canadian Energy Services Inc., Pengrowth Corporation and Orleans Energy Ltd.  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; Chairman and 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. MacNaughton was a director of Nortel Networks Corporation and Nortel Networks Limited (either, “Nortel”) when they and certain other subsidiaries filed for creditor protection under the Companies’ Creditors Arrangement Act (Canada) and applicable bankruptcy protection statutes in the U.S. and the United Kingdom on January 14, 2009.  Mr. MacNaughton became a director of Nortel on June 29, 2005.  Nortel was subject to a management cease trade order on April 10, 2006 issued by the Ontario Securities Commission (“OSC”) and other provincial securities regulators.  The cease trade order related to a delay in filing certain of Nortel’s 2005 financial statements.  The order was revoked by the OSC on June 8, 2006 and by the other provincial securities regulators very shortly thereafter.

(3)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.

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

Board Committees

TCPL has four committees of the Board: the Audit Committee, 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:

Audit Committee		Governance Committee		Health, Safety & Environment Committee		Human Resources Committee
Chair:	K.E. Benson	Chair:	W.K. Dobson	Chair:	E.L. Draper	Chair:	W.T. Stephens
Members:	D.H. Burney	Members:	D.H. Burney	Members:	P. Gauthier	Members:	W.K. Dobson
	P. Gauthier		P.L. Joskow		K.L. Hawkins		E.L. Draper
	P.L. Joskow		J.A. MacNaughton		W.T. Stephens		K.L. Hawkins
	J.A. MacNaughton		D.P. O’Brien		D.M.G. Stewart		D.P. O’Brien
	D.M.G. Stewart

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. Information about the audit committee can be found in this AIF under the heading “Audit Committee” and the text of the Audit Committee Charter can be found at Schedule “C” attached to this AIF.

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

TRANSCANADA PIPELINES LIMITED     23

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 TransCanada. 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	Prior to June 2006, Executive Vice-President, Corporate Development 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. Prior to June 2006, Vice-President, Transactions, Power Division, TCPL and concurrently, prior to August 2005, President TransCanada Power Services Ltd., general partner of TransCanada Power, L.P.
Alexander J. Pourbaix	President, Energy	Prior to June 2006, Executive Vice-President, Power.
Sarah E. Raiss	Executive Vice-President, Corporate Services	Executive Vice-President, Corporate Services
Donald M. Wishart	Executive Vice-President, Operations and Engineering	Executive Vice-President, Operations and Engineering.
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.

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.

TRANSCANADA PIPELINES LIMITED     24

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 SEC, and those mandated by the U.S. Sarbanes-Oxley Act of 2002. 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 our 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; 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 Charter of the Audit Committee can be found in Schedule “B” of this AIF and on TransCanada’s website under the Corporate Governance - Board Committees page, at www.transcanada.com.

Relevant Education and Experience of Members

The members of the Audit Committee at Year End were Kevin E. Benson (Chair), Derek H. Burney, Paule Gauthier, Paul L. Joskow, John A. MacNaughton and D. Michael G. Stewart.

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:

Kevin E. Benson

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.

Derek H. Burney

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.

Paule Gauthier

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.

TRANSCANADA PIPELINES LIMITED     25

Paul L. Joskow

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.

John A. MacNaughton

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.

D. Michael G. Stewart

Mr. Stewart earned a Bachelor of Science (Honours) in Geological Science from Queen’s University.  Mr. Stewart has served and continues to serve on the boards of several public companies and other organizations and on the audit committees of certain of those boards.  He has been active in the Canadian energy industry for over 35 years.

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-minimus 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 following table provides information about the fees paid by the Company to KPMG LLP, the external auditor of the TransCanada group of companies, for professional services rendered for the 2008 and 2007 fiscal years.

Fee Category	2008	2007	Description of Fee Category
	(millions of dollars)
Audit Fees	$6.69	$6.27	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	0.08	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	0.14	0.06	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	0.37	0.00	Aggregate fees for products and services other than those reported elsewhere in this table. The nature of these services consisted primarily of advice and training primarily related to compliance with IFRS.
Total	$7.28	$6.40

TRANSCANADA PIPELINES LIMITED     26

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 23, 2009.

Director	TransCanada Common Shares(1)	Deferred Share Units(2)
K. Benson	3,000	19,848
D. Burney	2,124	18,194
W. Dobson	3,000	36,858
E.L. Draper	0	19,681
P. Gauthier	1,000	30,707
K. Hawkins(3)	4,974	46,080
S.B. Jackson	39,000	36,030
P.L. Joskow	5,000	16,456
H. Kvisle(4)(5)	1,091,201	N/A
J. MacNaughton	40,000	14,094
D. O’Brien	19,634	30,707
W. T. Stephens	1,470	5,482
D.M.G. Stewart(6)	10,000	8,341

(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.
(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 1,019,128 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 23, 2009.

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.

TCPL’s director compensation practices are designed to reflect the size and complexity of TCPL and to reinforce the emphasis we place on shareholder value by linking a portion of directors’ compensation to the value of common shares.  As a result,

TRANSCANADA PIPELINES LIMITED     27

directors’ compensation consists of annual retainers and meeting fees paid in cash and in equity-based compensation known as deferred share units (“DSUs”).

The Governance Committee assesses the market competitiveness of our director compensation on an annual basis against publicly traded autonomous Canadian companies in the Comparator Group (as defined in Schedule “F” to this AIF) and a general industry sample of Canadian companies, using an analysis provided by an outside consultant.  Our goal is to provide total compensation to directors that is generally targeted at the median of our peers in both level and form in order to attract and retain qualified individuals.  This goal is reflected in our current compensation paid to directors.  The compensation philosophy for directors’ compensation is different that that for the executive officers discussed in Schedule “F” to this AIF in that it is not based on the performance of the Company.

DIRECTOR COMPENSATION TABLE

The following table sets forth the total compensation paid by TCPL to directors in 2008.

Name (a)	Fees Earned(1) ($) (b)	Share-based Awards(2) ($) (c)	All Other Compensation(3) ($) (d)	Total ($) (e)
K.E. Benson	201,500	-	1,415	202,915
D.H. Burney	194,500	-	1,328	195,828
W.K. Dobson	194,000	-	507	194,507
E.L. Draper	198,500	-	1,413	199,913
P. Gauthier	193,000	-	1,000	194,000
K.L. Hawkins	193,253	-	1,342	194,595
S.B. Jackson(4)	396,000	-	29,174	425,174
P.L. Joskow	190,000	-	525	190,525
J.A. MacNaughton	190,000	-	1,314	191,314
D.P. O’Brien	176,500	-	1,000	177,500
W.T. Stephens	195,247	-	525	195,772
D.M.G. Stewart	183,254	-	507	183,761

(1)Includes all annual Board and committee retainers and meeting fees, including the value of that portion of the Board retainer ($72,000) and the Board Chair retainer ($180,000) required to be paid in DSUs and the value of cash retainers, meeting fees and travel fees elected by the director to be paid in DSUs as described in more detail under the heading “Retainers and Fees Paid to Directors” below.

(2)Directors may be granted share-based awards in the form of DSUs as additional directors’ compensation under the DSU Plan.  There were no DSUs awarded to directors in separate grants in 2008.

(3)Amounts shown reflect value of DSUs credited during the year ended December 31, 2008 as a result of dividend value reinvestment from DSUs received in 2008 based on the quarterly dividend payable per common share of $0.36 on June 30, 2008 and on September 30, 2008, and $0.38 on December 31, 2008.

(4)The Chair was reimbursed for certain office and other expenses of approximately $26,400 in 2008.

RETAINERS AND FEES PAID TO DIRECTORS

Annual board and committee retainers are paid to each director who is not an employee of TCPL in quarterly installments, in arrears, and are pro-rated from the date of the director’s appointment to the Board and the relevant committees.  Each committee chair is entitled to claim a per diem for time spent on committee activities outside of the committee meetings.  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.  The retainers and fees paid to non-employee directors in 2008 are set forth in the following table and reflect changes approved by the Governance Committee effective January 1, 2008.  Directors who are U.S. residents are paid the same amounts as outlined below in U.S. dollars.

TRANSCANADA PIPELINES LIMITED     28

Board Chair retainer	$360,000 per annum ($180,000 in cash + $180,000 value of DSUs)(1)(2)
Board Chair meeting fee	$3,000 per Chaired Board meeting(1)
Board retainer	$142,000 per annum ($70,000 cash + $72,000 value of DSUs)(2)
Committee retainer	$4,500 per annum
Committee Chair retainer	$5,500 per annum
Board and Committee meeting fee	$1,500 per meeting
Committee Chair meeting fee	$1,500 per meeting

(1)The Chair is paid only the Board Chair retainer fee, the Board Chair meeting fee and the travel fee.  The Chair does not receive any other retainers or meeting fees.

(2)The $180,000 portion of the Board Chair retainer paid in DSUs and the $72,000 portion of the Board retainer paid in DSUs are equal to an aggregate of 4,813 DSUs and 1,925 DSUs, respectively, which were granted quarterly, in arrears, based on the closing price of the common shares of TransCanada at the end of each quarter of $39.55, $39.50, $38.17 and $33.17, respectively.

Directors are entitled to direct all or a portion of their cash retainers, meeting fees and travel fees to be paid in DSUs.  In 2008, Mr. Benson, Mr. Burney, Dr. Draper, Mr. Hawkins and Mr. MacNaughton directed all of their retainers, meeting fees and travel fees to be paid in DSUs.  Ms. Gauthier and Mr. O’Brien directed their Board retainers to be paid in DSUs.  In addition, Mr. Jackson directed the cash portion of his Chair retainer as well as his Board Chair meeting fee and travel fees to be paid in DSUs. For further information on the plan for DSUs, see the description under the heading “Share Unit Plan for Non-Employee Directors” below.

2008 Retainers and Fees

The following table sets out the total fees paid in cash and the value of the DSUs awarded or credited for each non-employee director in 2008 as at the date of the grant, unless otherwise stated. Mr. Kvisle, as an employee of TCPL, receives no cash fees or DSUs as a director.

Name	Board Retainer	Committee Retainer	Committee Chair Retainer	Board Meeting Fee	Committee Meeting Fee(1)	Travel Fee	Strategic Planning Sessions	Total Fees Paid in Cash	Total Value of DSUs Credited(2)	Total Cash & Value of DSUs Credited(3)
K.E. Benson(4)	142,000	4,500	5,500	15,000	22,500	10,500	1,500	0	201,500	201,500
D.H. Burney	142,000	9,000	n/a	15,000	16,500	10,500	1,500	0	194,500	194,500
W.K. Dobson	142,000	9,000	5,500	13,500	15,000	7,500	1,500	122,000	72,000	194,000
E.L. Draper(4)	142,000	9,000	5,500	15,000	15,000	10,500	1,500	0	198,500	198,500
P. Gauthier	142,000	9,000	n/a	15,000	16,500	9,000	1,500	51,000	142,000	193,000
K.L. Hawkins(5)	142,000	9,000	1,753	15,000	13,500	10,500	1,500	0	193,253	193,253
S.B. Jackson(6)	360,000	0	n/a	30,000	0	3,000	3,000	0	396,000	396,000
P.L. Joskow(4)	142,000	9,000	n/a	15,000	16,500	6,000	1,500	118,000	72,000	190,000
J.A. MacNaughton	142,000	9,000	n/a	15,000	15,000	7,500	1,500	0	190,000	190,000
D.P. O’Brien	142,000	9,000	n/a	13,500	7,500	3,000	1,500	34,500	142,000	176,500
W.T. Stephens(4)(5)	142,000	9,000	3,747	15,000	13,500	10,500	1,500	123,247	72,000	195,247
D.M.G. Stewart(7)	142,000	5,254	n/a	15,000	16,500	3,000	1,500	111,254	72,000	183,254

(1)Amounts shown represent $1,500 per meeting attended paid to each committee member, including the committee chair, plus $1,500 per meeting attended and chaired paid to committee chairs. This column also includes one training session in relation to International Financial Reporting Standards for the Audit Committee members where all members, including the Chair, were paid $1,500.

(2)Amounts shown include the minimum required amount of Board retainers paid in DSUs ($180,000 value of DSUs for the Chair, $72,000 value of DSUs for other Board members) plus the value of the retainers, meeting fees and travel fees elected to be received in DSUs.

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

(4)Directors who are U.S. residents are paid or credited these amounts, including DSU equivalents, in U.S. dollars.

(5)Mr. Hawkins was Chair of the Human Resources Committee until April 25, 2008, then Mr. Stephens became Chair and Mr. Hawkins became a regular member.  Their committee retainers have been prorated accordingly.

(6)Mr. Jackson’s Board meeting fee includes the fee of $3,000 for each Board meeting he chaired.

(7)Mr. Stewart was appointed to the Audit Committee on November 1, 2008.   Prior to November 1, 2008, Mr. Stewart attended Audit Committee meetings as a guest and was paid committee meeting fees.

TRANSCANADA PIPELINES LIMITED     29

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, or their economic equivalent, equal in value to five times the director’s annual cash portion of their Board retainer. 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 DSUs as described under the heading “Share Unit Plan for Non-Employee Directors” below.

All of the directors have achieved the minimum share ownership.

Share Unit Plan for Non-Employee Directors

The Share Unit Plan for Non-Employee Directors (the “DSU Plan”) was established in 1998.  Pursuant to the DSU Plan, Board members are permitted to elect to receive any portion of their retainers and meeting fees paid in cash (including travel fees) in DSUs.  The DSU Plan also allows the Governance Committee in its discretion, to grant units as additional compensation for directors.

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

COMPENSATION DISCUSSION AND ANALYSIS

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

Executive officers of TCPL also serve as executive officers of TransCanada.  An aggregate remuneration is paid for serving as an executive of TCPL and for service as an executive officer of TransCanada.  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.

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 appealed that decision. The appeal was heard on December 18, 2007.  On April 3, 2008, the Ontario Court of Appeal dismissed CAPLA’s appeal.  The decision of the Ontario Court of Appeal is final and binding as CAPLA did not seek any further appeal within the time frame allowed.

TCPL and its subsidiaries are subject to various other legal proceedings and regulatory actions arising in the normal course of business. While the final outcome of such legal proceedings and regulatory actions cannot be predicted with certainty and there can be no assurance that such matters will be resolved in TCPL’s favour, it is the opinion of TCPL’s management that the resolution of such proceedings and regulatory actions will not have a material impact on TransCanada’s consolidated financial position, results of operations or liquidity.

TRANSCANADA PIPELINES LIMITED     30

MATERIAL CONTRACTS

The Ravenswood Agreement as described in this AIF under the heading “General Development of the Business – Developments in the Energy Business” is available on SEDAR at www.sedar.com under TransCanada’s profile.

The underwriting agreement between TCPL and Citigroup Global Markets Inc., J.P. Morgan Securities Inc., Deutsche Bank Securities Inc., HSBC Securities (USA) Inc., Lazard Capital Markets LLC, Mizuho Securities USA Inc. and SG Americas Securities, LLC, as underwriters, dated August 6, 2008 as described in this AIF under the heading “General Development of the Business – Financing Activities” is available on SEDAR at www.sedar.com under TCPL’s profile.

The underwriting agreement between TCPL and Citigroup Global Markets Inc., HSBC Securities (USA) Inc., Deutsche Bank Securities Inc., J.P. Morgan Securities Inc., Mitsubishi UFJ Securities International plc, Mizuho Securities USA Inc., and SG Americas Securities, LLC, as underwriters, dated January 6, 2009 as described in this AIF under the heading “General Development of the Business – Financing Activities” is available on SEDAR at www.sedar.com under TCPL’s profile.

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

TCPL’s 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.

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     31

  GLOSSARY

AcSB	Accounting Standards Board	Iroquois System	A natural gas pipeline system in New York and Connecticut
AGIA	Alaska Gasline Inducement Act	ISO	International Organization of Standardization
AIF	Annual Information Form of TransCanada PipeLines Limited dated February 23, 2009	Keystone Canada	TransCanada Keystone Pipeline Limited Partnership
Alberta System	A natural gas transmission system throughout the province of Alberta	Keystone Oil Pipeline	A 3,456 km (2,147 mile) oil pipeline project currently under construction that will initially transport crude oil from Hardisty, Alberta to U.S. Midwest markets at Wood River and Patoka in Illinois, and to Cushing, Oklahoma
ANR	American Natural Resources Company and ANR Storage Company	Keystone U.S.	TransCanada Keystone Pipeline, LP
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	LNG	Liquefied Natural Gas
ATCO Pipelines	Canadian Utilities Limited	MD&A	TCPL’s Management’s Discussion and Analysis dated February 23, 2009
AUC	Alberta Utilities Commission	mmcf/d	Million cubic feet per day
Bbl/d	Barrels per day	Moody’s	Moody’s Investors Service, Inc.
Bcf	Billion cubic feet	MW	Megawatts
Bécancour	A power plant near Trois-Rivières, Québec	NBPL	Northern Border Pipeline Company
Bison	The Bison Pipeline Project, a proposed 298-mile pipeline from the Powder River Basin in Wyoming to the NBPL System	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	NGTL	Nova Gas Transmission Limited
Bruce A	Bruce Power A L.P.	North Baja	A natural gas pipeline in southern California
Bruce B	Bruce Power L.P.	NOx	Nitrogen oxides
Cacouna	The Cacouna Energy LNG facility in Cacouna, Québec	NYSDOS	New York Department of State
Calpine	Calpine Corporation	NYSE	New York Stock Exchange
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	Portland System	A natural gas pipeline that runs through Maine and New Hampshire into Massachusetts
CAPLA	Canadian Alliance of Pipeline Landowner’s Association	Portlands Energy Centre	A natural gas-fired combined-cycle power plant near downtown Toronto, Ontario
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	PPA	Power Purchase Arrangement
CO2	Carbon dioxide	Proxy Circular	TransCanada’s Management Proxy Circular dated February 23, 2009
Common Shares	Common shares of TransCanada	Ravenswood	Ravenswood Generating Station
Coolidge	Coolidge Generating Station	Ravenswood Agreement	Membership interest and stock purchase agreement between KeySpan Corporation, TransCanada Facility USA, Inc. and KeySpan Energy Corporation dated March 31, 2008
CSA	Canadian Securities Administrators	RGGI	Regional Greenhouse Gas Initiative
DBRS	DBRS Limited	S&P	Standard and Poor’s
EUB	Alberta Energy and Utilities Board	SEC	United States Securities and Exchange Commission
FEIS	Final Environment Impact Statement	SGER	Specified Gas Emitters Regulation
FERC	Federal Energy Regulatory Commission (USA)	Sheerness	A power plant consisting of two 390 MW coal-fired thermal powered generating units
Framework	The Regulatory Framework for Air Emissions	Sundance	Two coal fired electrical generating facilities which produce 560 MW and 706 MW, respectively
Foothills System	A natural gas pipeline system in southeastern B.C., southern Alberta and southwestern Saskatchewan	TCPL or the Company	TransCanada PipeLines Limited
GHG	Greenhouse gas	TQM	Trans Québec & Maritimes Pipeline Inc.
GTNC	Gas Transmission Northwest Corporation	TransCanada	TransCanada Corporation
GTN System	A natural gas transmission system running from northwestern Idaho, through Washington and Oregon to the California border	TSX	Toronto Stock Exchange
Great Lakes	Great Lakes Gas Transmission Limited Partnership	Tuscarora	Tuscarora Gas Transmission Company
Great Lakes System	A natural gas pipeline system in the north central U.S., roughly parallel to the Canada-U.S. Border	Tuscarora System	A natural gas pipeline that runs from Oregon through northeast California to Reno, Nevada
GUA	Gas Utilities Act (Alberta)	U.S.	United States
HS&E	Health, Safety and Environment	WCI	Western Climate Initiative
IFRS	International Financial Reporting Standards	Year End	December 31, 2008

TRANSCANADA PIPELINES LIMITEDA-1

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     B-1

SCHEDULE “B”

DISCLOSURE OF CORPORATE GOVERNANCE PRACTICES

The Board and the members of TCPL’s management are committed to the highest standards of corporate governance. TCPL’s corporate governance practices comply with the governance rules of the Canadian Securities Administrators (“CSA”), those of the New York Stock Exchange (“NYSE”) applicable to foreign issuers and of the U.S. Securities and Exchange Commission (“SEC”), and those mandated by the United States Sarbanes-Oxley Act of 2002 (“SOX”). As a non-U.S. company, TCPL is not required to comply with most of the NYSE corporate governance listing standards; however, except as summarized on our 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”). At TCPL, we believe that the 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. We believe that 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 based on the annual review conducted by the Governance Committee. The Board is currently comprised of 13 directors, of whom 12 (92%) were determined by the Board in 2008 to be independent directors. Thirteen nominees are being put forward for election at the Meeting, 12 (92%) 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, 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.

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 the oil and gas producer and shipper community; the Governance Committee 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 will absent 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 “Nominees for Election to the Board of Directors” under the headings “Other Public Board Directorships” and “Other Public Board Committee Memberships”. 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.

TRANSCANADA PIPELINES LIMITED     B-2

In 2008, independent directors of the Board met separately after every regularly scheduled meeting. There were eight such meetings during 2008. In addition, all of the directors are available to meet with management as required.

Mr. Jackson has served as the non-executive 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).

Director attendance at Board and committee meetings has been excellent and during 2008, all directors demonstrated a strong commitment to their roles and responsibilities.  The overall attendance rate was 99% at Board meetings and an average of 95% at committee meetings.  Specific attendance statistics are set out with each director’s biography in TransCanada’s Proxy Circular under the heading “Nominees for Election to the Board 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 eight scheduled meetings in 2008. Unscheduled meetings are held from time to time as required; there were two unscheduled meetings of the Board in 2008. There were also two strategic issue sessions and one full-day strategic planning session of the Board held in 2008.

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, including the ability to use independent advisors as necessary. The charter is available on TransCanada’s website at www.transcanada.com and is attached to TCPL’s AIF as 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 compensation discussion and analysis can be found attached to TCPL’s AIF at Schedule “F” under the heading “Compensation Discussion and Analysis”.

Orientation and Continuing Education

New directors are provided with an orientation and education program that includes a directors’ manual containing information about the duties and obligations of directors, the business and operations of TCPL, copies of governance charters, copies of past public filings and documents from recent Board meetings. New directors are given additional historical and financial information, a session on corporate strategy, are provided opportunities to visit TCPL’s facilities and project sites, and are provided with opportunities for meetings and discussions with the executive leadership team and other directors. Briefing sessions are also held for new committee members, as appropriate. The directors’ manual and the director induction and continuing education process are reviewed annually by the Governance Committee. The details of the orientation of each new director are tailored to each director’s individual needs and expressed areas of interest.  In 2008, Audit Committee members received a special tutorial in International Financial Reporting Standards.

TRANSCANADA PIPELINES LIMITED     B-3

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 of TCPL operating facilities and project sites on an annual basis. TCPL encourages continuing education for its directors, periodically suggests programs which may be relevant to the directors and provides funding for director education where appropriate. All Canadian directors are members of the Canadian Institute of Corporate Directors which provides another source of director education.

Board Access to Senior Management

Board members have complete access to the Company’s management, subject to reasonable advance notice to the Company and reasonable efforts to avoid disruption to the Company’s management, business and operations.  The Board encourages management to include key managers in Board meetings who can share their expertise with respect to matters before the Board.  This also enables the Board to gain exposure to key managers with future potential in the Company.

Ethical Business Conduct

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

The Board has also adopted a code of business ethics for directors which incorporates as its basis, principles of good conduct and highly ethical behaviour. TCPL has adopted a code of business ethics for its employees and separate codes applicable to its CEO, Chief Financial Officer and Controller, all of which are 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 2008. TCPL’s codes of business ethics may be viewed on TransCanada’s website at www.transcanada.com.

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 TCPL’s long-term strategy and ongoing business operations. 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 regularly assesses the skill set of current board members against a list of potentially desirable skills and experience to be sought when recruiting new directors to the Board.

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 attached to TCPL’s AIF at Schedule “D” under the heading “Board Committees and Their Charters - Governance Committee”.

TRANSCANADA PIPELINES LIMITED     B-4

Compensation

The Governance Committee, which is composed entirely of independent directors, 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 “Compensation Discussion and Analysis”.

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

Information relating to compensation consulting services provided by Towers Perrin during the 2008 financial year can be found in TCPL’s AIF at Schedule “F” under the heading “Compensation Discussion and Analysis — The Role of the External Compensation Consultant”.

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 at 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 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. The Governance Committee monitors and discusses external assessments of Board governance and regularly monitors the literature on evolving best practice in corporate governance.

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.

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Majority Voting for Directors

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

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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;

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

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(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;

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(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;

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(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, but at least every five years;

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 partners, employees and former partners and employees of the present and former 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;

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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;

(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 partners, employees and former partners and 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 United States securities law and applicable rules of any stock exchange on which the Company’s shares are listed.  Each member of the Audit Committee shall be financially literate and at least one member shall have accounting or related financial management expertise (as those terms are defined from time to time under the requirements or guidelines for audit committee service under securities laws and the applicable rules of any stock exchange on which the Company’s securities are listed for trading or, if it is not so defined as that term is interpreted by the Board in its business judgment).

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

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earlier appointed or until they cease to be Directors of the Company.

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)ensure the Committee has sufficient information to permit it to properly discharge its duties and responsibilities;

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

(e)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.

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.

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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 and set and pay the compensation for 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.

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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 which is published on TransCanada’s website at www.transcanada.com.

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. After 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.

AUDIT COMMITTEE

Chair:  K.E. Benson

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

This committee is comprised of six independent directors and is mandated to assist the Board in monitoring, among other things, the integrity of the financial statements of TCPL, the compliance by TCPL with legal and regulatory requirements, and the independence and performance of TCPL’s internal and external auditors. The committee is also mandated to review and recommend to the Board approval of TCPL’s audited annual and unaudited interim consolidated financial statements and related management discussion and analysis, and other corporate disclosure documents including information circulars, the annual information form, all financial statements in prospectuses and other offering memoranda, any financial statements required by regulatory authorities and all prospectuses and documents which may be 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 “A” of this Proxy Circular) is contained in TCPL’s Annual Information Form for the year ending December 31, 2008 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

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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 2008 (seven regularly scheduled, one special and one training session in relation to International Financial Reporting Standards (IFRS)).

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 also oversees the risk management activities of TCPL.  The committee monitors, reviews with management and makes recommendations related to TCPL’s risk management programs and policies on an ongoing basis.

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).

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 three meetings of the Governance Committee in 2008.

HUMAN RESOURCES COMMITTEE

Chair:  W.T. Stephens

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

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 Chief Executive Officer 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 and reviews the CEO’s objectives on an annual basis. The committee approves all longer-term compensation including stock options and 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 is also responsible for the review of the executive share ownership levels.

There were four meetings of the Human Resources Committee in 2008.

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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 independent directors 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 2008.

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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.

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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

e)employment contracts, termination and other special arrangements with executive officers, or other employee groups if such action is likely to have a subsequent material1 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.

1For 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.

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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.

E.Business and Risk Management

The Board has the responsibility to:

i)take 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

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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

A.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.

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SCHEDULE “F”

COMPENSATION DISCUSSION AND ANALYSIS

The following information is excerpted from TransCanada’s Proxy Circular.  Unless as otherwise defined in this Schedule “F”, all capitalized terms used from herein shall have the same meaning ascribed to them in TransCanada’s Proxy Circular.

This section explains how our executive compensation program is designed and operated with respect to our President and CEO (referred to as “CEO” in the narrative discussion in this section and under the section entitled “Executive Compensation Tables”), Chief Financial Officer (“CFO”), and the three other most highly compensated executives included in this reported financial year (collectively referred to as our “Executive Officers”).  This section also identifies the objectives and material elements of compensation awarded to the Executive Officers and the reasons supporting such awards.  For a complete understanding of our executive compensation program, this Compensation Discussion and Analysis should be read in conjunction with the Summary Compensation Table and other executive compensation-related disclosure included in this Schedule “F”.

SUMMARY FOR 2008

The Human Resources Committee of the Board of Directors (the “HR Committee”) utilizes a pay-for-performance philosophy to determine market competitive Total Direct Compensation for our Executive Officers that is commensurate with results generated by the Company for its shareholders.  Total Direct Compensation represents the combined value of fixed compensation and performance-based variable incentive compensation.  To attract and retain top talent, fixed compensation is generally targeted at the median of our comparator market and performance recognition occurs through the delivery of variable short and longer-term incentive compensation.

In evaluating 2008 corporate performance, the HR Committee considered a number of qualitative and quantitative factors including financial results, the quality of earnings, execution of on-going projects and transactions, safety, operational performance and progress on key growth initiatives.  For 2008, the HR Committee determined the overall corporate performance rating to be “above target”.  This rating did not trigger any specific awards but rather served to provide general context for the HR Committee’s subsequent review of the Executive Officers’ individual performance.  The Total Direct Compensation decisions made by the HR Committee in 2009 following the assessment of performance in 2008 are noted in the section “Compensation Decisions Made for 2008 — Total Direct Compensation Awards”, below.

Additionally, the 2006 performance share unit grant vested on December 31, 2008.  The HR Committee considered the results achieved against the pre-established three-year performance objectives for that grant and determined that 100% of outstanding units would vest for payment.  This represents a level of performance that is “at target”.  More information regarding the 2006 performance share unit grant is noted in the section “Compensation Decisions Made for 2008 — Mid-term Incentive Performance”, below.

COMPENSATION PHILOSOPHY

TransCanada’s executive compensation program has the following objectives:

·to provide a compensation package that proportionally rewards individual contributions in light of overall business results;

·to be competitive in level and form with the external market;

·to align executives’ interests with shareholders and customers; and

·to support the attraction, engagement and retention of executives.

Market Benchmarking

Market competitive compensation is a key objective of the executive compensation program.  During compensation deliberations, the HR Committee considers comparable market data from Canadian-based energy 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”).

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The composition of the Comparator Group is reviewed annually by the HR Committee for its on-going business relevance to TransCanada.  An overview of the 2008 characteristics of the Comparator Group, as compared to TransCanada’s 2008 characteristics, 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)	$8.8 billion	$7.7 billion	$15.3 billion
MARKET CAPITALIZATION(2)	$19.2 billion	$14.7 billion	$26.4 billion
ASSETS(1)	$30.3 billion	$13.5 billion	$21.6 billion
EMPLOYEES(1)	Approximately 3,600	2,795	5,397

(1)Revenue, assets and number of employees reflect 2007 information.

(2)Market Capitalization value noted is calculated as at December 31, 2008 by multiplying the monthly closing price by the quarterly common shares outstanding for the most recently available quarter.

The members of the Compensation Comparator Group for 2008 were as follows:

Alliance Pipeline Ltd.	Fortis Inc.
ATCO Ltd. & Canadian Utilities Limited	Husky Energy Inc.
BP Canada Energy Company	Imperial Oil Ltd.
Canadian Natural Resources Ltd.	Kinder Morgan Canada Inc.
Chevron Texaco Canada Resources	Nexen Inc.
ConocoPhillips Canada Resources Ltd.	Petro-Canada
Devon Canada Corporation	Shell Canada Ltd.
Emera Inc.	Spectra Energy
Enbridge Inc. / Enbridge Pipelines Inc.	Suncor Energy Inc.
EnCana Corporation	Syncrude Canada Ltd.
EPCOR Utilities Inc.	Talisman Energy Inc.
ExxonMobil Canada	TransAlta Corporation

The compensation data from the Comparator Group (the “Comparator Market Data”) provides the initial reference point for the HR Committee.  The annual Total Direct Compensation value an Executive Officer is awarded will vary based on an assessment of their individual performance (as described below) and in accordance with the following guidelines:

IF PERFORMANCE		TOTAL DIRECT COMPENSATION
meets objectives	à	will be comparable to median Total Direct Compensation market data
exceeds objectives	à	will be comparable to above-median market data(1)
falls short of objectives	à	market positioning will be adjusted downward from the previous year(2)

(1)The degree to which an Executive Officer’s Total Direct Compensation value is positioned above the median is relative to his or her assessed individual performance level.

(2)The degree to which the pay is adjusted downward is also relative to individual performance. The adjustment is typically made through variable rather than fixed compensation.

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COMPENSATION DECISION-MAKING PROCESS

The Role of the HR Committee

The HR Committee approves, or recommends for approval, all remuneration to be awarded through the executive compensation program to the Executive Officers.  The HR Committee directs management to gather information on its behalf, and provide initial analysis and commentary.  The HR Committee reviews this material along with other information received from external advisors in its deliberations before considering or rendering decisions.  The HR Committee has full discretion to adopt or alter management recommendations or to consult its own external advisors.

The HR 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 HR Committee’s ability to effectively carry out its responsibilities. Examples of processes that the HR Committee uses include:

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

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

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

·using a two-step review process where items are provided for the HR Committee’s initial review at a meeting prior to the approval meeting.

The Role of Management

Executive management plays an important role in our executive compensation decision-making process, due to their direct involvement in and knowledge of the business goals, strategies, experiences and performance of the Company and its various key business areas.  The HR Committee engages in active discussions with the CEO concerning the determination of performance objectives, including individual goals and initiatives for Executive Officers who directly report to the CEO.  Further discussions consider whether, and to what extent, criteria for the previous year have been achieved for those individuals.  The CEO may also provide a self-assessment of his own individual performance objectives and/or results achieved, if requested by the HR Committee.

The CEO makes recommendations to the HR Committee regarding the level and form of compensation awards for his direct reports.  The CEO does not engage in discussions with the HR Committee regarding his own Total Direct Compensation.  Human Resources management provides the HR Committee and the Chair of the Board with relevant market data and other information as requested, in order to support the HR Committee’s deliberations regarding the CEO’s Total Direct Compensation and subsequent recommendation to the Board.

The Role of the External Compensation Consultant

The HR Committee engages the services of an individual consultant (the “Consultant”) from Towers Perrin to provide executive compensation consulting services.  The mandate of the Consultant is to provide an assessment of management’s proposals relating to the compensation of the Executive Officers, attend all HR Committee meetings (unless otherwise requested by the HR Committee Chair), and, at the request of the HR Committee Chair, provide data, analysis or opinion on compensation-related matters under consideration by the HR Committee.

In 2008, the Consultant provided services to the HR Committee in accordance with this mandate and attended portions of all HR Committee meetings, as requested by the Chair of the HR Committee. The fees paid to Towers Perrin in 2008 for the Consultant’s services to the HR Committee were approximately $81,000. The performance of the Consultant is reviewed and the engagement is approved by the HR Committee on an annual basis.

Under the mandate, the Consultant could also provide advice to management on significant changes to compensation philosophy or programs, or other compensation matters of the Company if the work was directed or approved by the Chair of the HR Committee. These additional services were not provided by the Consultant to TransCanada in 2008. In 2008, other consultants employed by Towers Perrin provided 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 $2.1 million. All service fees and related expenses paid to Towers Perrin, including those for the services of the Consultant, are reviewed by the HR Committee.

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Performance Assessment

For Executive Officers, the HR Committee intentionally uses a compensation program premised on the sound judgment and absolute discretion of the HR Committee.  The HR Committee is of the view that formulas and weightings applied to forward-looking annual and longer-term performance objectives may lead to unintended consequences for compensation purposes.  For this reason, there are no pre-established weightings applied to objectives or formulaic calculations used to determine compensation awards for Executive Officers.

The HR Committee’s comprehensive assessment of the overall business performance of TransCanada, including corporate performance against objectives (both quantitative and qualitative), business circumstances and, where appropriate, relative performance against peers, provides the context for individual Executive Officer evaluations for all direct compensation awards.

Corporate Performance

TransCanada’s Board approves annual corporate objectives aligned with achieving the annual results required to deliver on TransCanada’s key longer-term strategies for growth and value creation.  These quantitative and qualitative objectives are captured, at a high level, in a corporate objectives summary document which is utilized by the HR Committee as a reference for compensation decision-making.  The corporate objectives summary includes specific corporate financial objectives and captures the general qualitative objectives for key business areas.

At the end of each year, the HR Committee reviews the results achieved and discusses them with management.  For the purposes of Total Direct Compensation deliberations, the HR Committee then determines an overall rating for actual corporate performance relative to an expected level of performance.  This overall corporate performance rating provides general context for the HR Committee’s review of individual performance by the Executive Officers.

A summary of the 2008 corporate performance results are noted in the section “Compensation Decisions Made for 2008 — Overall Corporate Performance”, below.

Individual Performance

The HR Committee approves annual individual performance objectives for the Executive Officers that are intended to align with the corporate objectives and reflect “key performance areas” for each executive relative to their specific role.  As with the corporate objectives, individual Executive Officer’s performance objectives may include a combination of quantitative and qualitative measures with no pre-determined weightings.

The HR Committee, in consultation with the CEO, reviews the achievements and overall contribution of each individual Executive Officer who reports to the CEO.  The Board Chair and HR Committee have in-camera discussions to complete an independent assessment of the performance of the CEO.  The HR Committee then determines an overall individual performance rating for each individual Executive Officer and considers this rating in determining Total Direct Compensation.

Internal Equity and Retention Value

Executive Officer pay relative to other executives (“internal equity”) is generally considered in establishing compensation levels.  The difference between the CEO’s compensation, the compensation of the Presidents and that of the other Executive Officers reflects, in part, the difference in their relative responsibilities.  The CEO’s responsibility for the management and oversight of the enterprise is greater than each of the President’s respective business area portfolios.  However, the Presidents’ responsibilities are greater than those of other Executive Officers.  As a result, the compensation level for our CEO is higher than for our Presidents, who in turn, have higher compensation levels than other Executive Officers.

The HR Committee also considers the retentive potential of its compensation decisions.  Retention of the Executive Officers is critical to business continuity and succession planning.

Previously Awarded Compensation

The HR Committee approves or recommends compensation awards which are not contingent on the number, term or current value of other outstanding compensation previously awarded to the individual.  The HR Committee believes that reducing or limiting current stock option grants, performance share units or other forms of compensation because of prior gains realized by an Executive Officer would unfairly penalize the officer and reduce the motivation for continued high achievement.  Similarly, the HR Committee does not purposefully increase long-term incentive award values in a given year to offset less-than-expected returns from previous grants.

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During the annual Total Direct Compensation deliberations, the HR Committee is provided with summaries of the three-year history of each Executive Officer’s previously awarded Total Direct Compensation.  These summaries help the HR Committee to track changes in an Executive Officer’s Total Direct Compensation from year to year and to remain aware of the historical compensation for each individual.

To ensure that the Company’s longer-term compensation programs are effective in delivering on the objectives of the compensation philosophy, the HR Committee annually reviews modeled compensation scenarios for the Executive Officers that illustrate the impact of various future corporate performance outcomes on previously awarded and outstanding compensation  (i.e., “wealth accumulation analysis”).  Following their review of this material in 2008, the HR Committee found that the 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 and delivered the intended differentiation of compensation value based on performance.

Share Ownership Guidelines

In support of the Company’s compensation philosophy, the HR Committee believes that executives can more effectively represent the interests of shareholders if they have a considerable investment in the common shares of TransCanada, or their economic equivalent.  The HR Committee has instituted share ownership guidelines (the “Guidelines”) which encourage executives to achieve an ownership level in the Company that the HR Committee views as significant in relation to each executive’s base salary.

The level of ownership can be achieved through the purchase of common shares, by participation in the TransCanada Dividend Reinvestment Plan or through unvested performance share units. The Guidelines require that at least 50% of the ownership level be in “actual shares” (i.e., TransCanada common shares or units of any TransCanada sponsored limited partnership).  Unvested performance share units only count to a maximum of 50% of the ownership level.

Executives generally have five years to meet their 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 HR Committee receives annual updates on executive ownership levels and conformity with the Guidelines.  The following table sets out the Guideline ownership levels for the Executive Officers relative to their base salary as of December 31, 2008 and the 20-day volume-weighted average closing price of TransCanada’s common shares at year end which was $32.97:

			ACTUAL GUIDELINE OWNERSHIP VALUE AS AT DECEMBER 31, 2008
Name	Minimum Ownership Level(1)	Minimum Ownership Value ($)	Value from Performance Share Unit Plan Grants(2) ($)	Value from Common Shares or LP Units ($)	Total Value ($)	Multiple of Base Salary
H.N. Kvisle(3)	3 x	3,750,000	1,875,000	2,357,619	4,232,619	3.4
G.A. Lohnes	2 x	860,000	430,000	439,292	869,292	2.0
R.K. Girling	2 x	1,400,000	700,000	730,022	1,430,022	2.0
A.J. Pourbaix	2 x	1,400,000	700,000	691,612	1,391,612	2.0
D.M. Wishart	2 x	1,100,000	550,000	1,135,619	1,685,619	3.1

(1)Minimum ownership requirement is a multiple of base salary depending on the role of the executive. Other select executives of TransCanada have a minimum ownership requirement of either one-time or two-times base salary.

(2)Under the Guidelines, the value from unvested units from the performance share unit plan is counted only to a maximum of 50% of the minimum ownership requirement.

(3)Mr. Kvisle, Director, President and Chief Executive Officer, held 71,508 common shares as of TransCanada as of December 31, 2008.

The HR Committee annually reviews a summary of ownership levels under the Guidelines and in 2008, noted that all Executive Officers had met their minimum ownership requirements. Once an executive is deemed to have reached the minimum ownership requirement, the HR Committee uses discretion in the maintenance of this level in the event of subsequent share price fluctuations.

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ELEMENTS OF COMPENSATION

Total Direct Compensation represents the combined value of fixed compensation and performance-based variable incentive compensation.  Once determined, the value of Total Direct Compensation is allocated to four direct compensation elements: base salary, short-term incentive in the form of an annual cash bonus, mid-term incentives in the form of performance share units and long-term incentives in the form of stock options.

The allocation of Total Direct Compensation value to these different compensation elements is not based on a formula, but rather is intended to reflect market practices as well as the HR Committee’s discretionary assessment of an Executive Officer’s past contribution and ability to contribute to future short, medium and long-term business results.

Overview of Compensation Elements

Component of Total Direct Compensation	Type of Compensation	Element	Form	Performance Period
FIXED	Annual	Base salary	Cash	1 year
	Annual	Short-term incentive	Annual cash bonus	1 year
VARIABLE	Longer-term	Medium-term incentives	Performance share units	Up to 3 years with vesting at end of term
		Long-term incentives	Stock options	Vesting 33 1/3% each year for 3 years with a 7 year term

Base Salary

Base salary is the fixed portion of Total Direct Compensation and is designed to provide income certainty and to attract and retain executives.  Base salaries for Executive Officers are reviewed annually and typically are positioned to align with the median of the Comparator Market Data.  Variances from the median are determined by the HR Committee and may be based on individual performance, the scope of the executive’s role within TransCanada, retention considerations and/or material differences in an Executive Officer’s responsibilities compared with similar roles in the Comparator Group.

Short-term Incentives

The annual cash bonus is a short-term incentive that is intended to reward each Executive Officer for their yearly individual contribution and performance of personal objectives in the context of overall annual corporate performance.  Target payout values are not pre-established by the HR Committee but consideration is given to Comparator Market Data when determining the payout amount. The annual cash bonus is designed to motivate executives to annually achieve personal business objectives, to be accountable for their relative contribution to the Company’s performance, as well as to attract and retain executives.

Mid-term Incentives

Mid-term incentive compensation is provided through the granting of performance share units. This incentive arrangement is designed to motivate executives to achieve mid-term corporate objectives, align their interests with those of our shareholders and to attract and retain executives.

Executives receive a provisional grant of notional share units that is based on an allocated value of Total Direct Compensation divided by the price of TransCanada’s common shares at the time of grant. During the three year grant term, granted share units accrue an amount equal to the aggregate value of quarterly dividends per common share declared and paid by TransCanada which is then reinvested in participants’ accounts as additional share units.  The vesting of these additional share units is subject to the same performance criteria as those units from the original grant.

The number of units that vest for payout is subject to the attainment of three-year corporate business performance objectives set by the HR Committee at the time of grant. The performance measures that will be used by the HR Committee to determine the vesting of the 2008 grant are:

·TransCanada’s absolute total shareholder return (“TSR”);

·relative TSR as compared to specified companies with which TransCanada may compete for capital;

·funds generated from operations per share; and

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·earnings per share.

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 HR Committee uses judgment and discretion to assess overall performance in the context of the stated criteria and business circumstances surrounding the performance achieved.

At the end of the grant term, actual results are compared against the performance objectives and participant unit totals are adjusted as follows, based on this assessment:

PERFORMANCE LEVEL		UNITS VESTING(1)
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

(1)If the actual performance achievement is determined by the HR Committee to align at a point between threshold and target, or target and maximum levels, the HR Committee will determine the number of units that vest on a pro-rata basis.

The resulting total vested units are then valued based on the price of TransCanada’s common shares at the time of vesting. Executive Officers receive a cash payment, less statutory withholdings, for the total value of the vested units at the end of the grant term.

Long-term Incentives

Long-term incentive compensation is provided through the granting of stock options. This incentive arrangement is designed to motivate executives to achieve longer-term sustainable business results, align their interests with those of our shareholders and to attract and retain executives.  Participants benefit only if the market value of TransCanada’s common shares at the time of stock option exercise is greater than the exercise price of the stock options at the time of grant. Unless otherwise specified by the HR Committee at the time of grant, stock options 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.

Stock Option Plan Information

Stock Option Granting Process

Generally, stock option grants are determined as part of the annual deliberation regarding Total Direct Compensation.  The CEO makes recommendations to the HR Committee regarding individual stock option awards for all recipients.  The CEO does not engage in discussions with the HR Committee regarding his own stock option grants.  Human Resources management provides the HR Committee and the Chair of the Board with relevant market data and other information in order to support the HR Committee’s deliberation regarding the CEO’s stock option grant recommendation to the Board.

The HR Committee reviews the appropriateness of the stock option grant recommendations from the CEO for all eligible employees and accepts or adjusts these recommendations.  The HR Committee is responsible for approving all individual stock option grants, including, on rare occasions, grants that are awarded outside the annual compensation deliberation process for such things as promotions or new hires.  The HR Committee is also responsible for recommending to the Board for their approval any stock option grants for the CEO.

The HR Committee approves or recommends compensation awards, including stock option grants, which are not contingent on the number, term or current value of other outstanding compensation previously awarded to the individual.

Stock Option Plan Amendments

The HR Committee has the authority to suspend or discontinue the stock option plan at any time without shareholder approval.  The HR Committee may also make certain amendments to the plan without shareholder approval, including such items as setting the vesting date of a given grant and changing the expiry date of an outstanding stock option which does not entail an extension beyond the original expiry date.  No amendments can be made to the stock option plan that adversely affect the rights of any option holder regarding any previously granted options without the consent of the option holder.

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Management does not have a right to amend, suspend or discontinue the stock option plan.  The stock option plan also provides that certain amendments be approved by the shareholders of TransCanada as provided by the rules of the Toronto Stock Exchange (“TSX”). Among other things, shareholder approval is required to increase the number of shares available for issuance under the stock option plan, to lower the exercise price of a previously granted option, to cancel and reissue an option and to extend the expiry date of an option beyond its original expiry date.  In 2008, the HR Committee approved various minor changes to improve the administrative efficiency of the stock option plan which did not require shareholder approval.

Other Compensation

Executive Officers receive other benefits that the Company believes are reasonable and consistent with its overall executive compensation program.  These benefits, which are based on competitive market practices, support the attraction and retention of Executive Officers.  Benefits include a defined benefit pension plan (as described below), traditional health and welfare programs and executive perquisites.

Our perquisite policy provides a limited number of perquisites to our Executive Officers.  The Company normally gives each officer a specified dollar amount (also known as an allowance) which is received as a lump-sum cash payment and can be used for any purpose at the discretion of the Executive Officer.  In 2008 the dollar amount of this allowance was $4,500 for each of the Executive Officers including the CEO.  Executive Officers are also provided with memberships to a limited number of luncheon and/or recreation clubs.

Executive Officers who work at the Company’s head office are eligible for a company-paid reserve parking stall which in 2008 was valued at $5,352.  They also receive either an annual car allowance valued at $18,000, or a similarly-valued capital allowance towards a leased vehicle and reimbursement of associated operating expenses.  Any non-policy perquisites are outlined in the discussion following the Summary Compensation Table (below).

COMPENSATION DECISIONS MADE FOR 2008

Overall Corporate Performance

For the purposes of Total Direct Compensation deliberations, the HR Committee reviewed the 2008 corporate performance results, including the information noted below. The HR Committee used this information to determine an overall rating to provide general context for the review of individual performance by the Executive Officers.

The following outlines key financial results and common share statistics for 2008.  All values are expressed in Canadian dollars:

Key Financial Results (millions of dollars)	2008	2007
Net Income	$1,440	$1,223
Comparable Earnings(1)	$1,279	$1,100
Funds Generated From Operations(1)	$3,021	$2,621
Common Share Statistics	2008	2007
Net Income Per Share - Basic	$2.53	$2.31
Comparable Earnings Per Share - Basic(1)	$2.25	$2.08
Funds Generated From Operations Per Share - Basic(1)	$5.30	$4.95
Dividends Declared Per Share	$1.44	$1.36
Basic Common Shares Outstanding (millions) Average for the period	570	530
End of period	616	540
TSR (1 year)	(15.1%)	3.3%
TSR (3 year)	0.8%	51.5%

(1)Refer to the “Non-GAAP Measures” section of the 2008 Management Discussion & Analysis disclosure document for a further discussion of comparable earnings, comparable earnings per share and funds generated from operations.

Net income was $1.4 billion in 2008 or $2.53 per share which was an increase of approximately nine per cent on a per share basis compared to 2007.  Comparable earnings for 2008 were $1.3 billion or $2.25 per share which was an increase of

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approximately eight per cent on a per share basis compared to 2007. Total funds generated from operations were $3.0 billion in 2008 or $5.30 per share which was an increase of approximately seven per cent on a per share basis compared to 2007.

Other notable accomplishments reviewed by the HR Committee included:

·Pipeline development achievements including significant advancement on the engineering, procurement and construction activities for the initial phase of the Keystone Oil Pipeline as well as the granting by the Alaska Commissioner of Revenue and Natural Resources of a license to TransCanada under the Alaska Gasline Inducement Act to advance the Alaska Pipeline project through an open season and subsequent Federal Energy Regulatory Commission certification;

·The acquisition by TransCanada of all the outstanding membership interests of the 2,480 MW Ravenswood Generating Facility in New York City from National Grid for US$2.8 billion, subject to certain post-closing adjustments; and

·The successful public offerings throughout 2008 of just under 65.3 million common shares that generated proceeds of approximately $2.4 billion that will be used to partially fund acquisitions and capital projects of the Company including, amongst others, the acquisition of the Ravenswood Generating Facility, the construction of the Keystone Oil Pipeline, for general corporate purposes and to repay short-term indebtedness.

Further information regarding TransCanada’s corporate financial and business performance can be found in the “2008 Management Discussion and Analysis” disclosure document.

The HR Committee noted that although one-year and three-year TSR results were below expected levels, TransCanada’s financial performance was strong in 2008 and demonstrated the Company’s ability to generate significant earnings and cash flow during uncertain economic times.  The cash flow generated by the Company’s operating assets, along with recently completed debt and common share issuances, means TransCanada is well positioned to fund its sizable capital program.  The HR Committee agreed that looking forward, TransCanada should be in a position to generate strong, long-term financial returns for shareholders as a result of the growing portfolio of high-quality energy infrastructure assets, proven project development and execution capabilities and the Company’s strong financial position.

After considering these performance results, the HR Committee determined that overall corporate performance in 2008 was “above target” and that this rating would serve to provide context for the 2009 review of compensation for the Executive Officers. Individual performance of the Executive Officers is assessed based on the individual Executive Officer’s contribution to the overall corporate performance level, relative to their specific role. There are no specific weightings or formulas used in the assessment of individual performance of the Executive Officers.

Although the Company demonstrated strong financial performance in 2008, the uncertainties in the global economy and volatility in the world stock markets present challenges for many companies, including TransCanada. In consideration of these market conditions, our HR Committee decided to use the following guiding principles during their 2009 Total Direct Compensation deliberations:

·no increases in base salaries for the Executive Officers;

·2008 annual bonus payments that are reflective of each Executive Officer’s contribution to TransCanada’s strong overall corporate performance for the year; and

·no increase in overall long-term incentive value, except in cases where an increase is deemed warranted by the HR Committee.

In addition, the HR Committee approved 2009 corporate performance objectives that continue to focus on achieving the annual results required to deliver on TransCanada’s key longer-term strategies for growth and value creation.

Mid-term Incentive Performance

The 2006 performance share unit grant vested on December 31, 2008.  As noted in the section above entitled, “Overview of Compensation Elements — Mid-term Incentives”, the plan provides for payouts from zero to 150% of units based on the HR Committee’s assessment of performance over the course of the three-year grant term.  Based on the following results, the HR Committee determined a final performance rating of “at target” which meant that 100% of each participant’s total performance share units were vested for payout:

·absolute TSR over the course of the grant term was below target performance;

·TransCanada’s relative TSR performance was below target;

·results for funds generated from operations were significantly above target; and

·earnings per share performance was significantly above target.

More information regarding the performance share unit payout for the Named Executive Officers can be found in the “Value Vested During the Year” table, below.

TRANSCANADA PIPELINES LIMITED   F-10

Total Direct Compensation Awards

The following tables outline the compensation awarded to the Executive Officers in 2009 and 2008 for overall performance in 2008 and 2007 respectively, as determined by the HR Committee during the annual deliberations regarding Total Direct Compensation.  This information is supplemental to that which is required in the Summary Compensation Table.

		FIXED COMPENSATION ($)		VARIABLE COMPENSATION ($)						TOTAL DIRECT COMPENSATION (TDC) ($)
Name	Year Of Award(1)	Annual Base Salary (2)	% Change	Annual Cash Bonus (3)	% Change	Performance Share Unit Grant	% Change	Stock Option Grant	% Change	TDC	% Change
H.N. Kvisle	2009	1,250,000	0%	1,850,000	19%	3,040,000	1%	960,000	(4%)	7,100,000	4%
	2008	1,250,000		1,550,000		3,000,000		1,000,000		6,800,000
G.A. Lohnes	2009	430,000	0%	550,000	12%	584,000	7%	216,000	18%	1,780,000	8%
	2008	430,000		490,000		547,500		182,500		1,650,000
R.K Girling	2009	700,000	0%	950,000	6%	1,520,000	1%	480,000	(4%)	3,650,000	1%
	2008	700,000		900,000		1,500,000		500,000		3,600,000
A.J. Pourbaix	2009	700,000	0%	900,000	0%	1,520,000	1%	480,000	(4%)	3,600,000	0%
	2008	700,000		900,000		1,500,000		500,000		3,600,000
D.M. Wishart	2009	550,000	0%	600,000	9%	1,014,000	13%	336,000	12%	2,500,000	9%
	2008	550,000		550,000		900,000		300,000		2,300,000

(1)The year when compensation is awarded following the assessment of performance from the prior year (e.g., 2009 Total Direct Compensation awards are made following an assessment of the performance results achieved in 2008).

(2)This column represents the annual base salary rate that is effective as at April 1 of the noted year.

(3)The total lump-sum cash award made for performance attributable to the prior year, and paid in the first quarter of the noted year.

Total Direct Compensation Pay Mix

The following table provides the “pay mix” of the Total Direct Compensation awarded in 2009 and 2008 for each of the Executive Officers.  “Pay mix” is the resulting relative value of each compensation element following the allocation of Total Direct Compensation value.  It is expressed as percentage of Total Direct Compensation.

Name	Year of Award(1)	% of TDC from Annual Base Salary(2)	% of TDC from Annual Cash Bonus (3)	% of TDC from Performance Share Unit Grant	% of TDC from Stock Option Grant
H.N. Kvisle	2009	18	26	42	14
	2008	18	23	44	15
G.A. Lohnes	2009	24	31	33	12
	2008	26	30	33	11
R.K Girling	2009	19	26	42	13
	2008	19	25	42	14
A.J. Pourbaix	2009	19	25	43	13
	2008	19	25	42	14
D.M. Wishart	2009	22	24	41	13
	2008	24	24	39	13

(1)The year when compensation is awarded as a result of performance assessed from the prior year (e.g., 2009 Total Direct Compensation awards are pursuant to performance results achieved in 2008).

(2)This column represents the annual base salary rate that is effective as at April 1 of the noted year.

(3)The total lump-sum cash award made for performance attributable to the prior year, and paid in the first quarter of the noted year.

TRANSCANADA PIPELINES LIMITED    F-11

PERFORMANCE GRAPH

The following chart compares TransCanada’s five-year cumulative TSR to the S&P/TSX composite index (assuming reinvestment of dividends and considering a $100 investment on December 31, 2003 in TransCanada’s common shares).

	Dec. 31, 2003	Dec. 31, 2004	Dec. 31, 2005	Dec. 31, 2006	Dec. 31, 2007	Dec. 31, 2008	Compound  Annual Growth
TransCanada	100.0	111.5	142.3	163.5	168.9	143.4	7.5	%
TSX	100.0	114.5	142.1	166.6	183.0	122.6	4.2	%

As noted above, the HR Committee considers a number of factors and performance elements when determining compensation for the Executive Officers.  Although TSR is one performance measure that is reviewed, it is not the only consideration in executive compensation deliberations.  As a result, a direct correlation between TSR over a given period and executive compensation levels is not anticipated.

EXECUTIVE COMPENSATION TABLES

All compensation values disclosed in this section, unless otherwise noted, are expressed in Canadian dollars and are generally derived from compensation plans and programs that are described in detail under the section “Compensation Discussion and Analysis” or from retirement arrangements reported under the section “Pension and Retirement Benefits” in this Proxy Circular.

The Executive Officers 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.

SUMMARY COMPENSATION TABLE

The following table outlines the summary of compensation received by the Executive Officers during or for the 2008, 2007, and 2006 financial years:

					Non-equity Incentive Plan  Compensation
Name and Principal Position	Year	Salary(4)  ($)	Share- based Awards(5)  ($)	Option- based  Awards(6) ($)	Annual  Incentive  Plans(7)($)	Long-term  Incentive Plans(8)($)	Pension Value(9) ($)	All Other Compensation(10) ($)	Total  Compensation ($)
(a)	(b)	(c)	(d)	(e)	(f1)	(f2)	(g)	(h)	(i)
H.N. Kvisle	2008	1,237,503	3,000,000	1,000,000	1,850,000	702,000	753,000	12,354	8,554,857
President &	2007	1,175,001	2,378,696	771,304	1,550,000	663,000	1,324,000	11,708	7,873,709
Chief Executive   Officer	2006	1,100,004	1,917,500	782,500	1,500,000	619,125	713,000	11,000	6,643,129
G.A. Lohnes	2008	415,008	547,500	182,500	550,000	79,200	349,000	110,682	2,233,890

TRANSCANADA PIPELINES LIMITED    F-12

Executive Vice-	2007	362,508	422,878	137,122	490,000	104,742	181,000	158,061	1,856,311
President & Chief   Financial Officer	2006(1)	318,829	141,164	186,320	320,001	97,810	626,000	267,429	1,957,553
R.K. Girling	2008	682,506	1,500,000	500,000	950,000	396,000	352,000	6,796	4,387,302
President, Pipelines	2007	602,502	1,261,088	408,912	900,000	408,220	594,000	5,979	4,180,702
	2006(2)	498,346	618,300	566,700	700,000	381,206	384,000	28,192	3,176,744
A.J. Pourbaix	2008	682,506	1,500,000	500,000	900,000	255,600	343,000	66,796	4,247,902
President, Energy	2007	602,502	1,261,088	408,912,	900,000	241,400	575,000	61,479	4,050,381
	2006(3)	494,172	618,300	566,700	700,000	225,425	393,000	71,065	3,068,662
D.M. Wishart	2008	537,507	900,000	300,000	600,000	180,000	277,000	26,354	2,820,861
Executive Vice-	2007	475,005	755,143	244,857	550,000	204,220	467,000	46,708	2,742,934
President, Operations   & Engineering	2006	395,007	327,850	172,150	500,000	190,706	154,000	24,942	1,764,655

(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. With the exception of the values noted in column (f2) and column (g), the compensation Mr. Lohnes received during his tenure as President and Chief Executive Officer of Great Lakes was provided in U.S. dollars (or equivalent value) but has been expressed here in Canadian dollars based on the Bank of Canada’s average annual exchange rate for 2006 of 1.134.

(2)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.

(3)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.

(4)This column reflects actual base salary earnings during the noted financial year. Base salary rates are reviewed annually as part of Total Direct Compensation deliberation and changes, if any, are typically effective April 1.

(5)This column shows the Total Direct Compensation value that was allocated to performance share units.  The number of share units awarded is created by taking the value noted and dividing it by the valuation price at the time of grant, namely $39.87 for 2008, $40.45 for 2007 and $36.60 for 2006.  The valuation price is based on the volume-weighted average trading price of TransCanada’s common shares during the five trading days immediately prior to and including the grant date.

(6)This column shows the total compensation value of stock options granted to the Executive Officers during each of the financial years noted. Only executive level employees received grants from the Stock Option Plan in 2008.  For 2008, the exercise price of a stock option granted to Canadian executives was $39.75, which represented the closing market price of TransCanada common shares on the TSX for the last trading day immediately preceding the award date of the option.

In conjunction with a corporate restructuring, there was a special grant of stock options made to certain Executive Officers in June 2006 that was in addition to those granted earlier in the year during the annual determination of Total Direct Compensation. Specifically, Mr. Lohnes received an additional 50,000 options with a compensation value of $142,500, Mr. Girling and Mr. Pourbaix each received an additional 100,000 options with a compensation value of $285,000.

(7)Amounts referred to in this column are paid as annual cash bonuses and are attributable to the noted financial year. These payments are generally made by March 15 following the completion of the financial year.

(8)This column contains the value awarded from a grandfathered dividend–value plan under which grants are no longer made. The HR Committee determined an annual unit value of $1.44 per unit for 2008, $1.36 per unit for 2007 and $1.27 per unit for 2006 be awarded for all outstanding units held under the plan.  Further information regarding this plan is noted in the narrative discussion for the Summary Compensation Table, below.

(9)This column includes the annual compensatory value from the defined benefit pension plan.  This value, along with further explanation regarding the plan can be found in column (e) of the Defined Benefit Pension Plan Table below.

(10)The value in this column includes all other compensation not reported in any other column of the table for each of the Executive Officers and includes the following:

·      The value of perquisites provided to Mr. Lohnes in 2007 was $47,891 which exceeded 10% of his total salary for that year and has therefore been included in this column.  Aside from this exception, the perquisites values for each Executive Officer for all other financial years is less than $50,000 and 10% of total salary and, as such, are not included in this column.  For information, the average annual value for perquisites provided to the Executive Officers in 2008 was $28,810.  All perquisites provided to the Executive Officers have a direct cost to the Company and are valued on this basis.

·      A tax equalization payment was made to Mr. Lohnes in 2006 of US$124,842 and is included in this column. This payment is disclosed here in Canadian dollars based on the Bank of Canada’s average annual exchange rate for 2006 of 1.134.

·      Included in this column is a one-time special tax-protected cash payment of $200,000 made to Mr. Lohnes as part of his repatriation to Canada. This value was 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, $41,557 for 2007 and $41,557 for 2008.

·      Included in this column are payments made to 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; Mr. Pourbaix - $60,000 for 2008, $55,500 for 2007 and $59,250 for 2006; and Mr. Wishart - $21,000 for 2008, $42,000 for 2007 and $21,000 for 2006.

TRANSCANADA PIPELINES LIMITED    F-13

·      This column includes TransCanada’s contribution under the 401K pension plan for Mr. Lohnes in the amount of US$8,792 for 2006.  This payment is disclosed here in Canadian dollars based on the Bank of Canada’s average annual exchange rate for 2006 of 1.134.

·      TransCanada’s contributions under the Employee Stock Savings Plan made on behalf of the Executive Officer for the noted financial year is included in this column, specifically:

o      Mr. Kvisle - $12,354 for 2008, $11,708 for 2007 and $11,000 for 2006;

o      Mr. Lohnes - $4,125  for 2008, $3,613 for 2007, and $1,133 for 2006;

o      Mr. Girling - $6,796 for 2008, $5,979 for 2007 and $4,942 for 2006;

o      Mr. Pourbaix - $6,796 for 2008, $5,979 for 2007 and $4,892 for 2006; and

o      Mr. Wishart - $5,354 for 2008, $4,708 for 2007 and $3,942 for 2006.

·      Included in this column is the value of payments made in a particular financial year in the event an Executive Officer elected to receive a cash payment in lieu of vacation entitlement from the previous year.

Stock Option Valuation

The value disclosed in column (e) in the Summary Compensation Table, above, reflects the HR Committee’s view of the grant date fair value of the stock option award.  The amount noted for 2008 is based on a grant date fair value of $5.96 per stock option or 15% of the exercise price of $39.75.  The amount noted for 2007 is based on a grant date fair value of $3.81 per stock option or 10% of the exercise price of $38.10.  The amount noted for 2006 is based on a grant date fair value of $3.13 per stock option or 8.89% of the exercise price of $35.23.

In arriving at these values, the HR Committee considered a range of valuation approaches and assumptions, and ultimately used their discretion in arriving at grant date fair values they deemed to be fair and reasonable for compensation purposes. For accounting purposes, the grant date fair values determined for these awards were $3.97 per stock option for 2008, $4.22 per stock option for 2007 and $3.61 per stock option for 2006.

Non-equity Long-term Incentive Plan

The values contained in column (f2) in the Summary Compensation Table, above, reflect the value awarded from a grandfathered dividend-value plan under which grants are no longer made. Although no longer considered part of the current executive compensation program, annual awards on outstanding grants from this plan continue to be made and disclosed as compensation for the Executive Officers.  Prior to the discontinuance of the plan in 2003, one unit from the dividend-value plan was granted in tandem with each granted stock option and expired ten years from the date of grant.

Each dividend-value plan unit provides the holder with the right to receive an annual unit value, as determined by the HR Committee, in its discretion. The maximum annual unit value is equal to the dividends declared on one TransCanada common share in a given year.  For 2008, the HR Committee determined that $1.44 per unit was to be awarded for all outstanding units held under the dividend-value plan.

Recent Dividend-Value Plan Amendments

In December 2008, the HR Committee approved amendments to the dividend-value plan that provided for payment of all previously awarded but deferred annual unit value.  These lump sum payments represented the total value deferred from multiple years of annual unit value awards, including the value disclosed in column (f2) in the Summary Compensation Table, above, for 2006 and 2007.  As such, these payments are not reported in the Summary Compensation Table but are provided here for information:

Name	Total Units  Outstanding (#)	Total Deferred Value  as at 31-Dec-08 and paid in Jan-09 ($)
H.N. Kvisle	487,500	3,775,238
G.A. Lohnes	55,000	419,195
R.K. Girling	250,000	1,981,950
A.J. Pourbaix	160,000	1,221,340
D.M. Wishart	125,000	984,425

These payments included all annual unit value awarded up to and including the 2007 financial year.  The annual unit value awarded for 2008 was paid to each Executive Officer as a separate payment in February, 2009 and is disclosed in column (f2) in the Summary Compensation Table, above, for 2008.

TRANSCANADA PIPELINES LIMITED    F-14

INCENTIVE PLAN AWARDS – OUTSTANDING OPTION-BASED AND SHARE-BASED AWARDS

The following table outlines all option-based and share-based awards previously awarded to the Executive Officers that are outstanding at the end of the most recently completed financial year.

	OPTION-BASED AWARDS				SHARE-BASED AWARDS
Name	Number of  Securities  Underlying  Unexercised  Options  (#)	Option Exercise Price ($)	Option Expiration Date	Value of Unexercised In-The-Money Options(1) ($)	Number of Shares or Units of Shares that have not Vested(2) (#)	Market or Payout Value of Share-based Awards that have not Vested(3) ($)
(a)	(b)	(c)	(d)	(e)	(f)	(g)
H.N. Kvisle	200,000	22.33	24-Feb-10	2,168,000	140,337.032	2,327,490
	165,000	26.85	23-Feb-11	1,042,800
	42,500	18.01	27-Feb-11	644,300
	150,000	21.43	25-Feb-12	1,761,000
	160,000	30.09	28-Feb-12	492,800
	250,000	35.23	27-Feb-13	0
	202,442	38.10	22-Feb-14	0
	167,715	39.75	25-Feb-15	0
G.A. Lohnes	10,500	30.09	28-Feb-12	32,340	25,314.903	419,848
	14,000	35.23	27-Feb-13	0
	50,000	33.08	12-Jun-13	4,500
	35,990	38.10	22-Feb-14	0
	30,608	39.75	25-Feb-15	0
R.K. Girling	80,000	22.33	24-Feb-10	867,200	72,062.626	1,195,159
	60,000	26.85	23-Feb-11	379,200
	65,000	21.43	25-Feb-12	763,100
	60,000	30.09	28-Feb-12	184,800
	90,000	35.23	27-Feb-13	0
	100,000	33.08	12-Jun-13	9,000
	107,326	38.10	22-Feb-14	0
	83,857	39.75	25-Feb-15	0
A.J. Pourbaix	20,000	20.58	1-Mar-09	251,800	72,062.626	1,195,159
	60,000	26.85	23-Feb-11	379,200
	60,000	30.09	28-Feb-12	184,800
	90,000	35.23	27-Feb-13	0
	100,000	33.08	12-Jun-13	9,000
	107,326	38.10	22-Feb-14	0
	83,857	39.75	25-Feb-15	0
D.M. Wishart	20,000	20.58	1-Mar-09	251,800	43,197.713	716,434
	35,000	18.01	27-Feb-11	530,600
	30,000	21.43	25-Feb-12	352,200
	40,000	22.33	24-Feb-10	433,600
	40,000	26.85	23-Feb-11	252,800
	40,000	30.09	28-Feb-12	123,200
	55,000	35.23	27-Feb-13	0
	64,267	38.10	22-Feb-14	0
	50,314	39.75	25-Feb-15	0

(1)Calculated on outstanding vested and unvested stock options and based on the difference between the noted exercise price for the grant and the 2008 year-end closing price on the TSX for common shares of $33.17.

TRANSCANADA PIPELINES LIMITED    F-15

(2)The number of units represents those from both the original grant and those added during the grant term as a result of dividend value reinvestment, from all outstanding grants under the performance share unit plan as at December 31, 2008.

(3)TransCanada’s performance share unit plan uses three-year objectives for the various performance measures.  Additionally, there is no absolute formula applied to the performance results that is used to determine the final payout.  Given that these conditions do not allow an interim calculation of performance results, the values noted in this column represent the minimum payout value from the plan that is greater than zero.  This minimum payout value is calculated by taking 50% of the total units reported in column (f) and multiplying those by the 2008 year-end closing price on the TSX for common shares of $33.17.

INCENTIVE PLAN AWARDS – VALUE VESTED DURING THE YEAR

The following table outlines the aggregate value of all option-based and share-based awards previously made to the Executive Officers that vested during the most recently completed financial year.  It also includes the aggregate value from non-equity incentive plan awards that were earned by the Executive Officers during the most recently completed financial year.

Name	Option-based Awards – Value  Vested During the Year  ($)	Share-based Awards – Value  Vested During the Year  ($)	Non-equity Incentive Plan  Compensation – Value Earned  During the Year(2)($)
(a)	(b)	(c)	(d)
H.N. Kvisle	1,049,382	1,933,090	2,552,000
G.A. Lohnes(1)	205,912	125,495	629,200
R.K. Girling	596,594	623,327	1,346,000
A.J. Pourbaix	596,594	623,327	1,155,600
D.M. Wishart	258,135	330,516	780,000

(1)At the time of grant, Mr. Lohnes was President of Great Lakes and his performance share unit grant was under the U.S. plan.  The payment value noted under column (c) for Mr. Lohnes is expressed in U.S. dollars and was paid in Canadian dollars exchanged at par.

(2)The value noted is this column is the aggregate value from both the annual cash bonus payment and the dividend-value plan annual payment that are attributable to this financial year.  The annual cash bonus value is denoted in column (f1), “Annual Incentive Plans” while the dividend–value plan payment is denoted in column (f2), “Long-term Incentive Plans” in the Summary Compensation Table, above.

Option-based Awards – Value Vested During the Year

The value noted in column (b) of the Value Vested During the Year table, above, is the aggregate value from outstanding stock options that vested during the financial year.  The value represents the total dollar value that would have been realized if the stock options had been exercised on the vesting date.  The following table provides grant-by-grant details on the calculation of this total value:

Supplemental Table – Value of Outstanding Options Calculated at Vesting

Name	Grant Date	Total Number of Securities Under Options Granted (#)	Option Exercise Price ($)	Number of Options  that Vested from the  Grant during the  Financial Year(1)(#)	Share Price on  Vesting Date(2) ($)	Value at Vesting  ($)
H.N. Kvisle	22-Feb-07	202,442	38.10	67,481	39.75	111,344
	27-Feb-06	250,000	35.23	83,333	39.92	390,832
	28-Feb-05	160,000	30.09	53,334	40.35	547,207
G.A. Lohnes	22-Feb-07	35,990	38.10	11,997	39.75	19,795
	27-Feb-06	14,000	35.23	4,667	39.92	21,888
	12-Jun-06	50,000	33.08	16,667	38.83	95,835
	28-Feb-05	20,000	30.09	6,666	40.35	68,393
R.K. Girling	22-Feb-07	107,326	38.10	35,775	39.75	59,029
	27-Feb-06	90,000	35.23	30,000	39.92	140,700
	12-Jun-06	100,000	33.08	33,333	38.83	191,665
	28-Feb-05	60,000	30.09	20,000	40.35	205,200
A.J. Pourbaix	22-Feb-07	107,326	38.10	35,775	39.75	59,029
	27-Feb-06	90,000	35.23	30,000	39.92	140,700
	12-Jun-06	100,000	33.08	33,333	38.83	191,665
	28-Feb-05	60,000	30.09	20,000	40.35	205,200
D.M. Wishart	22-Feb-07	64,267	38.10	21,422	39.75	35,346

TRANSCANADA PIPELINES LIMITED    F-16

Name	Grant Date	Total Number of Securities Under Options Granted (#)	Option Exercise Price ($)	Number of Options that Vested from the Grant during the Financial Year(1) (#)	Share Price on Vesting Date(2) ($)	Value at Vesting  ($)
	27-Feb-06	55,000	35.23	18,333	39.92	85,982
	28-Feb-05	40,000	30.09	13,334	40.35	136,807

(1)TransCanada employee stock options vest one-third on each anniversary of the grant date for a period of three years.

(2)The share price noted is the closing price for TransCanada Common Shares on the TSX for the later of the vesting date or the first full trading day following that date.

Share-based Awards – Value Vested During the Year

The value noted in column (c) of the Value Vested During the Year table above is the value paid to the Executive Officers upon the vesting of the 2006 grant of performance share units.  The noted value in this table is calculated as follows:

Total Units as
of the Vesting
Date(1) X Valuation
Price(2) at
Vesting Date + Total Units as
of the Vesting
Date(1) X Final
Dividend
value(3)  X Performance
Multiplier as
determined by the
HR Committee

(1)The total number of units at the vesting date includes those both from the original grant and those accumulated by dividend-value reinvestment throughout the grant term.

(2)The Valuation Price equals the volume-weighted average trading price of TransCanada’s common shares during the five trading days immediately prior to and including the vesting date.

(3)The Final Dividend value is the dividend per common share that has been declared as of Q4 of the vesting year but which has not been paid at the vesting date.

For information, the following table reconciles the performance share unit payment value that is noted in column (c) of the Value Vested During the Year table.

Supplemental Table – Payment Value of 2006 Performance Share Unit Grant

Name	Vesting Date	Total Units at Vesting (2) (#)	Value of Total Units  at Vesting (3)($)	Value of Final Dividend(4) ($)	Total Payment Value(5) ($)
(i)	(ii)	(iii)	(iv)	(v)	(vi)
H.N. Kvisle	31-Dec-08	57,981.116	1,912,217	20,873	1,933,090
G.A Lohnes(1)	31-Dec-08	3,764.112	124,140	1,355	125,495
R.K. Girling	31-Dec-08	18,696.075	616,597	6,731	623,327
A.J. Pourbaix	31-Dec-08	18,696.075	616,597	6,731	623,327
D.M. Wishart	31-Dec-08	9,913.487	326,947	3,569	330,516

(1)At the time of grant, Mr. Lohnes was President of Great Lakes and his performance share unit grant was under the U.S. plan.  The payment values noted for Mr. Lohnes are expressed in U.S. dollars and were paid in Canadian dollars exchanged at par.

(2)The total units at vesting include those units from the original grant and those from dividend reinvestment activity up to Q3 of 2008.

(3)Units noted in column (iii) were valued at $32.98 per unit based on the five day volume-weighted closing price of common shares on the TSX at December 31, 2008.

(4)The value noted is the declared dividend for Q4 2008 of $0.36 multiplied by the number of units noted in column (iii).

(5)Based on the HR Committee’s assessment of the performance achieved against objectives, 100% of the total units became vested for payment as of the Vesting Date noted.  As such, the value in this column represents the sum of the values from columns (iv) and (v).  This value was paid to the Executive Officers in February 2009.

EQUITY COMPENSATION PLAN INFORMATION

The stock option plan is the only compensation arrangement under which equity securities of TransCanada have been authorized for issuance.  Stock options may be granted to employees of TransCanada as approved by the HR Committee as described under the section, “Elements of Compensation – Long-Term Incentives” above.  The following provides key information regarding the stock option plan:

TRANSCANADA PIPELINES LIMITED    F-17

·The stock option plan was first approved by shareholders in 1995;

·As at February 23, 2009, there were approximately:

o9,332,794 common shares issuable upon the exercise of outstanding stock options; this represents 1.5% of issued and outstanding common shares;

o3,158,829 common shares remaining available for issuance; this represents 0.5% of issued and outstanding common shares;

o17,918,427 common shares have been issued upon the exercise of stock options, representing 2.9% 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 March 1, 2009 to February 23, 2016.

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.  Additionally, 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.  Other than these plan provisions, there are no additional restrictions on the number of stock options that may be granted to insiders.  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.

For more information regarding amendments to the stock option plan and vesting information, refer to the sections entitled, “Elements of Compensation – Long-Term Incentives and Stock Option Plan Information”, above.  The actions currently prescribed for outstanding stock option grants after specific employment events are described below under the section, “Termination and Change of Control Benefits – Separation Arrangements”, below.

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, 2008.

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	8,501,007	29.10	4,188,117
Equity compensation plans not   approved by security holders	Nil	Nil	Nil
TOTAL	8,501,007	29.10	4,188,117

PENSION AND RETIREMENT BENEFITS FOR EXECUTIVES

Effective January 1, 2008, TransCanada’s retirement program was amended to allow new employees and existing employees with less than ten years of service with TransCanada the choice to either participate in the defined benefit pension plan or receive an annual Company contribution to a savings account under the new savings plan.  Eligible employees who elect to participate in the 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.  However, participation in the defined benefit pension plan is mandatory for all employees once they have ten years of service with the Company.

All of the Executive Officers participate in the defined benefit pension plan.

TRANSCANADA PIPELINES LIMITED    F-18

Defined Benefit Pension Plan

The defined benefit pension plan consists of a base pension plan and a supplemental pension plan for eligible employees.

Base Pension Plan

All of our Canadian employees with ten years of service and those with less than ten years of service who have elected to participate in the defined benefit pension plan (the “Pension Plan Employees”), including the Executive Officers, participate in the base pension plan, which is now solely a non-contributory defined benefit pension plan.

The normal retirement age under our base 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 ten years 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 for the base pension plan is:

1.25% of an employee’s	plus	1.75% of an employee’s	multiplied by	Credited Service(4)
Highest Average Earnings(1)		Highest Average Earnings
up to the Final Average(2)		above the Final Average
YMPE(3)		YMPE

(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 the annual cash bonus up to a pre-established maximum amount as outlined in the plan text for the defined benefit pension plan.  Pensionable Earnings do not include 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 Average Earnings calculation plus the two previous years.

(3)“YMPE” means Year’s Maximum Pensionable Earnings under the Canada/Québec Pension Plan.

(4)“Credited Service” means the employee’s years of credited pensionable service in the defined benefit pension plan.

Registered defined benefit pension plans are subject to a maximum annual benefit accrual under the Income Tax Act (Canada), which is currently $2,444 for each year of Credited Service, with the result that benefits cannot be earned in the base pension plan on compensation above approximately $153,000 per annum.

Supplemental Pension Plan

All of our Pension Plan Employees, including the Executive Officers, who have Pensionable Earnings over the Income Tax Act (Canada) ceiling of approximately $153,000, participate in the Company’s non-contributory defined benefit supplemental pension plan. Approximately 600 employees currently participate in the supplemental pension plan.

The defined benefit pension plan uses a hold harmless approach, where the maximum amount allowable under the Income Tax Act (Canada) will be paid from the base pension plan and the remainder is paid from the supplemental pension plan.  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 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 defined benefit pension plan.

Generally, neither the base pension plan nor the supplemental pension plan provide for the recognition of past service. However, pursuant to the provisions of the supplemental pension plan, the HR Committee has exercised its discretion to grant additional years of Credited Service to executive employees from time to time.

TRANSCANADA PIPELINES LIMITED    F-19

All Pension Plan Employees, including the 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 employee’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 employees, a monthly pension payable for life with payments to the employee’s estate guaranteed for the balance of ten years if the employee dies within ten 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.  Forms of optional pension payment include: increasing the percentage of the pension value that continues after death, adding a guarantee period to the pension and, under the base pension plan only, transferring the lump sum commuted value of the pension to a locked-in retirement account up to certain limits.

Accrued Pension Obligations

As at December 31, 2008, TransCanada’s accrued obligation for the supplemental pension plan was approximately $178.0 million. The 2008 current service costs and interest costs of the supplemental pension plan were approximately $5.5 and $11.0 million, respectively, for a total of $16.5 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 2008 Consolidated Financial Statements which are available on the Company’s website at www.transcanada.com and filed on SEDAR at www.sedar.com.

Defined Benefit Pension Plan Table

		Annual Benefits Payable  (c)
Name   (a)	Number of Years of Credited  Service  (b)	At Year End(4) ($) (c1)	At Age 65(5) ($) (c2)	Accrued  Obligation  Start of  Year(6)  ($)  (d)	Compensatory  Change(7) ($) (e)	Non- Compensatory  Change(8) ($) (f)		Accrued  Obligation at  Year End(6) ($) (g)
H.N. Kvisle(1)	18.33	707,000	1,095,000	9,047,000	753,000	(1,138,000	)	8,662,000
G.A. Lohnes(2)	15.33	134,000	244,000	1,906,000	349,000	(472,000	)	1,783,000
R.K. Girling(3)	13.00	197,000	486,000	2,447,000	352,000	(753,000	)	2,046,000
A.J. Pourbaix(3)	13.00	195,000	531,000	2,343,000	343,000	(863,000	)	1,823,000
D.M. Wishart	11.59	143,000	278,000	2,006,000	277,000	(409,000	)	1,874,000

(1)In 2002, the HR Committee approved an arrangement with Mr. Kvisle to grant him additional Credited Service in recognition of his accomplishments to date and to retain his services into the future.  The arrangement resulted in him receiving five years of additional Credited 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 Service on the date of the anniversary of his employment.  All such additional service will not exceed ten additional years of Credited 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 base 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 annual cash bonus up to the pre-established maximum amount as outlined in the plan text for the defined benefit pension plan.

(3)In 2004, the HR Committee also approved arrangements for Mr. Girling and Mr. Pourbaix to obtain additional Credited Service in recognition of their high potential and to retain their services into the future. Subject to Mr. Girling and Mr. Pourbaix maintaining continuous employment with TransCanada until September 8, 2007, each received an additional three years of Credited 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).

(4)Column (c1) shows the annual lifetime benefit and is based on the years of Credited Service in column (b) and the actual Pensionable Earnings history as of December 31, 2008.

(5)Column (c2) shows the annual lifetime benefit at age 65 based on the years of Credited Service at age 65 and the actual Pensionable Earnings history as of December 31, 2008.

(6)Column (e) shows the compensatory change in the accrued obligation and includes the service cost to TransCanada in 2008, plus compensation changes that were higher or lower than the salary assumption, and plan changes.

(7)Column (f) shows the non-compensatory change in the accrued obligation and includes the interest on the accrued obligation at the start of the year and changes in assumptions in the year.

TRANSCANADA PIPELINES LIMITED    F-20

(8)The accrued obligation is the reported value of the pension obligations at December 31, 2007, shown in column (d), and December 31, 2008, shown in column (e), using actuarial assumptions and methods that are consistent with those used for calculating pension obligations as disclosed in the TransCanada’s 2007 and 2008 consolidated financial statements.  As the assumptions reflect TransCanada’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.

TERMINATION AND CHANGE OF CONTROL BENEFITS

Separation Arrangements

Separation agreements with the Executive Officers (each, a “Separation Agreement”) outline the terms and conditions applicable in the event of an Executive Officer’s separation from TransCanada due to retirement, termination (with or without cause), resignation, disability or death. The following table summarizes the material terms and provisions that apply under the noted separation events:

TYPE OF COMPENSATION			SEPARATION EVENT
	RESIGNATION(1)	TERMINATION  WITHOUT CAUSE(2)	TERMINATION  WITH CAUSE	RETIREMENT	DEATH
Base Salary	Payments cease	Severance allowance includes a lump-sum payment of annual base salary as of the separation date multiplied by the notice period(3)	Payments cease	Payments cease	Payments cease
Annual Bonus	Not paid	Equals the Average Bonus(4) pro-rated by the number of months in the current year prior to the separation date Severance allowance includes the Average Bonus(4) multiplied by the notice period(3)	Not paid	Equals the Average Bonus(4) pro-rated by the number of months in the year prior to the separation date	Equals the Average Bonus(4) pro-rated by the number of months in the year prior to the separation date
Performance Share Units	All outstanding units are forfeited	Granted value paid out on a pro rata basis	All outstanding units are forfeited	Granted value paid out on a pro rata basis	Granted value paid out on a pro rata basis
Stock Options	Vested options must be exercised by six months following separation	Vested options must be exercised by the later of the last day of the notice period or six months following separation	Vested options must be exercised by six months following separation	All outstanding options vest and become exercisable; must be exercised by three years following retirement(5)	All outstanding options vest and become exercisable; must be exercised by the first anniversary of death(5)
Benefits	Coverage ceases or, if eligible, Retiree Benefits(6) commence	Coverage continues during notice period (or equivalent lump-sum payout is made) and if eligible, service credit for the notice period(3) for Retiree Benefits(6)	Coverage ceases or, if eligible, Retiree Benefits(6) commence	Retiree Benefits(6) commence	Coverage ceases or, if eligible, Retiree Benefits(6) commence
Pension	Paid as a commuted value or monthly benefit	Paid as a commuted value or monthly benefit(7)	Paid as a commuted value or monthly benefit	Paid as a commuted value or monthly benefit	Paid as a commuted value or monthly benefit
Perquisites	Payments cease	A lump-sum cash payment equal to the monthly corporate cost of the perquisite package multiplied by the notice period(3)	Payments cease	Payments cease	Payments cease
Other	---	Outplacement services	---	---	---

(1)Does not include resignation as a result of constructive dismissal of the Executive Officer.

(2)Includes treatment afforded to an Executive Officer in the event of an Executive Officer’s resignation owing to constructive dismissal.

(3)The notice period for the CEO is three years.  For all other Executive Officers, the notice period is two years.

TRANSCANADA PIPELINES LIMITED    F-21

(4)The Average Bonus is equal to the average of the annual bonus amounts paid to the Executive Officer for the three-years preceding the separation date.

(5)The exercise provisions noted pertain to stock options granted after January 1, 2003.  For stock options granted prior to that date, all outstanding stock options must be exercised within six months following the date of retirement or death.

(6)All employees are eligible for Retiree Benefits, if at the separation date, they are age 55 or over with ten or more years of continuous service. These benefits include:

·      a health spending account which can be used to pay for eligible health and dental expenses and/or to purchase private health insurance;

·      a security plan, which provides a safety net in case of significant medical expenses; and

·      life insurance, which provides a death benefit of $10,000 to a designated beneficiary.

All other coverage, including the employee stock plan, spousal and dependent life insurance, accident insurance, disability and payment of provincial health care premiums, end at the date of separation.

(7)Credited Service for the applicable notice period is provided at the end of the notice period.

TransCanada may elect to require Executive Officers to comply with a non-competition provision in the Separation Agreements for a period of 12 months from the Executive Officer’s separation date.  If TransCanada makes this election, a payment will be made to the Executive Officer of an amount equal to the annual base salary as of the separation date plus the Average Bonus.

Change of Control Arrangements

Under the Separation Agreements, a change of control is defined as including (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 all separation payments under the Separation Agreements. However, in the month following the one year anniversary after a change of control, Mr. Kvisle may provide notice of his intention to leave TransCanada and in that event, he would receive all the same entitlements as if he had been terminated without cause.

The following table summarizes additional terms and provisions applicable to Executive Officers under the Separation Agreements in the event of a change of control.

Performance Share Units	If the Executive Officer’s separation date is within two years of a change of control, all unvested performance share units are deemed vested and are paid out as a single, lump-sum cash payment.
Stock Options	Following a change of control, there is an acceleration of stock option vesting. If, for any reason, the Company is unable to implement this vesting acceleration (e.g., the Company’s shares cease to trade), the Company will pay the Executive Officer a cash payment. This payment would be equal to the net amount of compensation the Executive Officer would have received if they had, on the date of a change of control, exercised all vested options and unvested options for which vesting would have been accelerated.
Pension	If the Executive Officer’s separation date is within two years of a change of control, a pensionable service credit for the applicable notice period is provided at the date of separation rather than at the end of the notice period.

Separation Payments

The following table provides a calculation of the separation payments that would have been made to the Executive Officers under the noted separation events with and without a deemed change of control.  All payments are calculated assuming the date of separation was, and if applicable, a change of control occurred on December 31, 2008. The disclosed values represent payments made pursuant to the terms of the Separation Agreements and do not include certain values that would be provided under normal course, specifically the value of pension benefits normally provided following resignation and the value of Retiree Benefits.

	WITHOUT A  CHANGE OF CONTROL			WITH A CHANGE OF  CONTROL
Name	Payment Made in the Event of Termination with Cause(1) ($)	Payment Made in the Event of Termination Without Cause(2)(3)(4) ($)	Payment Made in the Event of Retirement or Death ($)	Payment Made in the Event of Termination Without Cause Following a Change of Control(3)(5) ($)
(a)	(b)	(c)	(e)	(g)
H.N. Kvisle	6,108,900	21,535,867	12,077,788	24,296,907
G.A. Lohnes	35,340	2,729,782	966,167	3,110,863
R.K. Girling	2,200,300	7,951,481	4,867,352	9,016,323
A.J. Pourbaix	821,800	6,535,981	3,488,852	7,600,823
D.M. Wishart	1,944,200	5,932,472	3,561,478	6,596,256

(1)Also constitutes treatment afforded an Executive Officer in the event of an Executive Officer’s resignation without constructive dismissal.

TRANSCANADA PIPELINES LIMITED    F-22

(2)Also constitutes treatment afforded an Executive Officer in the event of an Executive Officer’s resignation owing to constructive dismissal.

(3)In the event TransCanada elects to require an Executive Officer to comply with a non-competition provision as contained in the Separation Agreements, the Executive Officers would receive the following compensatory lump sum payments: Mr. Kvisle – $2,700,004; Mr. Lohnes – $769,421; Messrs. Girling and Pourbaix - $1,400,008; and Mr. Wishart - $1,033,341.

(4)Also constitutes treatment afforded an Executive Officer in the event of an Executive Officer’s resignation owing to constructive dismissal where separation date is within two years from the date of the change of control.

The aggregate value of perquisites for each Executive Officer is less than $50,000 or 10% of salary and as such, has been excluded from the separation payment calculations. As applicable to the provisions for certain separation events, the values from share-based compensation incorporate the following assumptions:

·applicable payments from outstanding performance share unit grants inclusive of additional units from dividend reinvestment up to and including the last quarter of 2008 and assuming a value of $32.98 per unit which is the five-day volume-weighted average closing share price on the TSX of TransCanada’s common shares as of December 31, 2008, calculated per the terms of the plan; and

·the value of vested in-the-money stock options, assumed exercised as at the separation date and using an exercise price of $33.17 which is based on the closing share price on the TSX of TransCanada’s common shares on December 31, 2008.

The HR Committee annually reviews severance payment amounts for each of the Executive Officers as calculated under the Separation Agreements.  The data provided to the HR Committee represents the total value to be paid to the Executive Officer in the event of termination without cause, both with and without a deemed change of control as well as the additional payment that could be made under the non-competition provision.

Financial
Highlights

Year ended December 31 (millions of dollars)	2004	2005		2006		2007	2008
Income
Comparable Earnings(1)	791	838		923		1,087	1,259
Net income applicable to common shares	1,030	1,208		1,077		1,210	1,420
Cash Flow
Funds generated from operations	1,701	1,950		2,374		2,603	2,992
(Increase)/decrease in operating working capital	28	(48	)	(300	)	215	(188	)
Net cash provided by continuing operations	1,729	1,902		2,074		2,818	2,804
Capital expenditures and acquisitions	2,046	2,071		2,042		5,874	6,363
Balance Sheet
Total assets	22,421	24,113		26,386		31,737	40,935
Long-term debt	9,749	9,640		10,887		12,377	15,368
Junior subordinated notes	–	–		–		975	1,213
Common shareholders' equity	6,484	7,164		7,618		9,664	12,574
(1)  Non-GAAP measure that does not have any standardized meaning prescribed by generally accepted accounting principles. For more information on non-GAAP measures see page 11 in the Management's Discussion and Analysis of the 2008 Annual Report.

TRANSCANADA PIPELINES LIMITED 1

TABLE OF CONTENTS

TCPL OVERVIEW		4
TCPL'S STRATEGY		5
CONSOLIDATED FINANCIAL REVIEW
	Selected Three Year Consolidated Financial Data	7
	Highlights	8
	Segment Results	9
	Results of Operations	10
FORWARD-LOOKING INFORMATION		10
NON-GAAP MEASURES		11
OUTLOOK		11
PIPELINES
	Highlights	14
	Results	15
	Financial Analysis	16
	Opportunities and Developments	18
	Business Risks	21
	Outlook	23
	Natural Gas Throughput Volumes	25
ENERGY
	Highlights	28
	Results	28
	Power Plants – Nominal Generating Capacity and Fuel Type	29
	Financial Analysis	30
	Opportunities and Developments	40
	Business Risks	41
	Outlook	43
CORPORATE
	Results	43
	Financial Results	44
	Outlook	44
DISCONTINUED OPERATIONS		45
LIQUIDITY AND CAPITAL RESOURCES
	Summarized Cash Flow	45
	Highlights	45
CONTRACTUAL OBLIGATIONS
	Contractual Obligations	50
	Principal Repayments	51
	Interest Payments	51
	Purchase Obligations	52

2 MANAGEMENT'S DISCUSSION AND ANALYSIS

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
	Financial Risks and Financial Instruments	54
	Other Risks	61
CONTROLS AND PROCEDURES		64
SIGNIFICANT ACCOUNTING POLICIES AND CRITICAL ACCOUNTING ESTIMATES		65
ACCOUNTING CHANGES		68
SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA		70
FOURTH QUARTER 2008 HIGHLIGHTS		72
SHARE INFORMATION		74
OTHER INFORMATION		74
GLOSSARY OF TERMS		75

MANAGEMENT'S DISCUSSION AND ANALYSIS 3

The Management's Discussion and Analysis (MD&A) dated February 23, 2009 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, 2008, which are prepared in accordance with Canadian generally accepted accounting principles (GAAP). This MD&A covers TCPL's financial position and operations as at and for the year ended December 31, 2008. 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 2008 Annual Report.

TCPL OVERVIEW

In 2008, TCPL celebrated the 50th anniversary of the completion of its original pipeline from Alberta to Ontario and Québec. Fifty years of experience has established TCPL as a significant player in the development and operation of North American energy infrastructure, including natural gas and oil pipelines, power generation plants, and natural gas storage facilities.

TCPL has invested approximately $24 billion in capital projects in the last nine years, and currently has more than $40 billion in total assets. The Company is currently executing an $18 billion capital program and most of the projects are expected to be completed by 2012. Over the longer term, TCPL intends to continue to pursue and develop its substantial portfolio of large-scale infrastructure projects. TCPL is committed to maintaining the financial strength required to build the energy infrastructure needed to serve increased energy demand, respond to shifting energy supply-demand dynamics and replace aging North American infrastructure.

Pipelines Assets

The TCPL network of more than 59,000 kilometres (km) (36,661 miles) of wholly owned and 7,800 km (4,847 miles) of partially owned natural gas pipelines connect virtually every major natural gas supply basin and market, transporting 20 per cent of the natural gas consumed in North America. TCPL's natural gas pipelines link gas supplies from Western Canada, the United States (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, northeastern British Columbia (B.C.) and U.S. shale gas, and offshore liquefied natural gas (LNG) imports, to growing markets.

TCPL's Alberta System gathered 66 per cent of the natural gas produced in Western Canada or 15 per cent of total North American production in 2008. 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. 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, Iroquois, Portland, TQM, Northern Border and Tuscarora. Certain of these pipeline systems are held through the Company's 32.1 per cent interest in TC PipeLines, LP (PipeLines LP).

ANR was acquired in February 2007. ANR transports natural gas from producing fields located primarily in Oklahoma, Texas, Louisiana and the Gulf of Mexico to markets located in Wisconsin, Michigan, Illinois, Ohio and Indiana. It 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 to a variety of end-user markets in the midwestern and northeastern U.S. ANR owns and operates 250 billion cubic feet (Bcf) of regulated natural gas storage capacity in Michigan.

In addition, the Company has agreed to increase its ownership interest up to 79.99 per cent in each of TransCanada Keystone Pipeline Limited Partnership and TransCanada Keystone Pipeline, LP (collectively, Keystone partnerships). TCPL has partnered with ConocoPhillips, a global, integrated oil and gas producer and refiner to build the Keystone crude oil pipeline. Currently under construction, the Keystone pipeline will transport 1.1 million barrels per day (Bbl/d) of crude oil from Hardisty, Alberta to U.S. Midwest markets at Wood River and Patoka in Illinois, and at Cushing, Oklahoma, and to U.S. Gulf Coast markets. The pipeline is supported by long-term contracts with strong counterparties and provides a low-cost shipping option. While the current economic slowdown and low oil price environment have eased the pace of

4 MANAGEMENT'S DISCUSSION AND ANALYSIS

oil sands project activity, developments in the medium to long term in Alberta will provide attractive opportunities for further additions to crude oil transmission infrastructure.

Energy Assets

TCPL's Energy business has grown from 754 megawatts (MW) in 1999 to more than 10,900 MW in 2008. The Company's diverse power generation portfolio of primarily low-cost, baseload or long-term contracted facilities comprises a total of 19 plants in Alberta, Eastern Canada, New England, and New York City. The accompanying graph illustrates each fuel source as a percentage of the Company's overall Energy portfolio:

TCPL has developed a significant non-regulated natural gas storage business in Alberta where the Company 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.

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 it has or can develop significant competitive advantage. Since 2000, TCPL's key strategies continue to evolve with the Company's growth and development and its changing business environment. TCPL's corporate strategy integrates five fundamental value-creating activities:

1.

Maximize the full-life value of TCPL's infrastructure assets and commercial positions

2.

Cultivate a focused portfolio of high quality development options

3.

Commercially develop and physically execute new asset investment programs

4.

Maximize TCPL's competitive strengths

5.

Maximize TCPL's financial strength and reputation

These strategies are defined by an integrated set of activities and performance objectives:

Maximize the full-life value of TCPL's infrastructure assets and commercial positions

TCPL relies on a low-risk business model to maximize the full-life value of existing assets and positions that generate predictable, sustainable streams of cash flows and earnings. In the Company's Pipelines business, the natural gas pipeline network connects traditional and emerging basins to growing markets offering effective service and competitive rates. TCPL's Energy business supplies growing power markets through long-term power purchase agreements, and low-cost baseload generation. The Company's activities in gas, nuclear, wind and hydro energy sources demonstrate its commitment to a sustainable energy future. TCPL continues to make its long-term commercial and physical asset operations a priority. The Company attempts to maximize the life and value of its assets by focusing on sustainable business initiatives derived from engaging in market and regulatory developments, combined with an accretive capital investment program.

Cultivate a focused portfolio of high quality development options

The Company's core western and eastern regions are the primary focus of growth initiatives in the Pipelines and Energy businesses. Consideration is given to new markets with good fundamentals where TCPL has or can develop competitive strengths. There is a continued focus on low-cost, baseload power assets as well as on power and natural gas storage assets supported by firm, long-term contracts with reputable counterparties. Greenfield development and acquisition of power generation, power transmission and natural gas storage are considered if they meet the Company's investment

MANAGEMENT'S DISCUSSION AND ANALYSIS 5

standards. Greenfield and brownfield pipeline projects are being pursued to diversify the Pipelines business and add incremental value to existing assets. Key areas of focus include greenfield development options to connect the Company's natural gas pipelines to northern gas reserves and emerging Canadian and U.S. shale gas supplies, and transporting crude oil from the Alberta oil sands. Other possible growth opportunities include acquiring natural gas and oil transmission assets that complement TCPL's existing assets, acquiring partners' interests in associated pipelines and acquiring stand-alone transmission enterprises in new regions of North America.

Commercially develop and physically execute new asset investment programs

TCPL's current $18 billion capital program is expected to begin generating revenue over the next four years beginning in 2009. The Company is committed to completing the projects in its capital programs on time and on budget to deliver service to its customers and returns to its shareholders. Its large portfolio of projects is characterized by highly contracted, long-term revenue streams and limited exposure to capital cost risks. These are key features of TCPL's model for managing construction risks and improving the return realized from new investment programs. This strategy will be applied to Pipelines and Energy growth opportunities that address North America's emerging energy infrastructure needs.

Maximize TCPL's competitive strengths

TCPL will use its competitive strengths to achieve responsible, profitable operations and growth. In the Pipelines and Energy infrastructure businesses, size and scale of operations must be large enough to compete effectively and offer recognized value to customers. The Company believes its competitive strengths include the discipline it applies in operations, governance and project, financial and risk management, and its ability to obtain capital at suitable terms. TCPL strives to provide customers with safe, low-cost, reliable and responsible service by such means as improved efficiencies, operational reliability and enhanced environmental and safety performance. The Company also strives to maintain constructive relationships with its key stakeholder groups. Utilizing these strengths is the responsibility of all employees, and all employees contribute to the success of the Company. To maximize the quality, capability and contribution of the Company's employees, management encourages and supports its employees' innovative thinking, development and leadership.

Maximize TCPL's financial strength and reputation

TCPL continues to value its reputation for financial strength based on a history of predictable, growing earnings and cash flow. The Company continues to communicate its financial performance to current and prospective debt and equity holders, while making its management of risks transparent. TCPL strives to maintain access to low-cost capital in all market environments to enable it to capture growth opportunities and improve its financial performance.

6 MANAGEMENT'S DISCUSSION AND ANALYSIS

CONSOLIDATED FINANCIAL REVIEW

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

		2008		2007	2006
Income Statement
Revenues		8,619		8,828	7,520
Net income applicable to common shares
	Continuing operations	1,420		1,210	1,049
	Discontinued operations	–		–	28
		1,420		1,210	1,077
Comparable earnings(1)		1,259		1,087	923
Per Common Share Data
Net income – basic and diluted
	Continuing operations	$2.59		$2.33	$2.17
	Discontinued operations	–		–	0.06
		$2.59		$2.33	$2.23
Summarized Cash Flow
Funds generated from operations(1)		2,992		2,603	2,374
(Increase)/decrease in operating working capital		(188	)	215	(300	)
Net cash provided by operations		2,804		2,818	2,074
Balance Sheet
Total assets		40,935		31,737	26,386
Total long-term liabilities		20,422		17,832	15,014

⁽¹⁾

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 was $1,420 million in 2008 compared to net income applicable to common shares of $1,210 million in 2007.

Comparable Earnings

•

TCPL's comparable earnings of $1,259 million in 2008 excluded $152 million of gains from bankruptcy settlements with certain subsidiaries of Calpine Corporation (Calpine), proceeds of $10 million from a lawsuit settlement, a $27 million writedown of costs for the Broadwater LNG project (Broadwater) and $26 million of favourable income tax adjustments. Comparable earnings of $1,087 million in 2007 excluded favourable income tax adjustments of $102 million, a gain of $14 million on the sale of land and $7 million of net unrealized gains from changes in the fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts.

Cash from Operations

•

Net cash provided by operations was $2,804 million in 2008, a decrease of $14 million from 2007.



•

Funds generated from operations were $2,992 million in 2008, an increase of $389 million or 15 per cent from 2007.

Investing Activities

•

TCPL invested $6.4 billion in its Pipelines and Energy businesses in 2008, including the following:



•

the acquisition of the Ravenswood facility in August 2008 for US$2.9 billion, subject to certain post-closing adjustments;



•

capital expenditures of $1.8 billion for Pipelines projects, including Keystone and North Central Corridor; and



•

capital expenditures of $1.3 billion for Energy projects, including the Bruce A restart of Units 1 and 2, and construction of Portlands Energy, Halton Hills, Kibby Wind and Cartier Wind.

Financing Activities

•

In 2008, TCPL issued $2.2 billion of long-term debt (net of issue costs) and $2.4 billion of common shares, comprised primarily of the following:



•

in 2008, the issuance of 66.3 million common shares to TransCanada Corporation (TransCanada), resulting in gross proceeds of approximately $2.4 billion;



•

in August 2008, the issuance of US$1.5 billion of Senior Unsecured Notes; and



•

in August 2008, the issuance of $500 million of Medium-Term Notes.



•

In February 2009, the Company issued $700 million of Medium-Term Notes.



•

In January 2009, the Company issued US$2.0 billion of Senior Unsecured Notes.



•

In November 2008, TCPL established a new US$1.0 billion committed bank facility.



•

In June 2008, the Company entered into an agreement for a US$1.5 billion one-year bridge loan facility. In August 2008, the Company drew US$255 million and cancelled the remainder of the commitment.

Balance Sheet

•

Total assets increased by $9.2 billion to $40.9 billion in 2008 compared to 2007, primarily due to the acquisition of the Ravenswood facility, investments in Energy and Pipelines capital projects, and the effect of a stronger U.S. dollar.



•

TCPL's shareholders' equity increased by $2.9 billion to $13.0 billion in 2008 compared to the previous year.

Dividend

•

On February 2, 2009, TCPL's Board of Directors declared a dividend for the quarter ending March 31, 2009 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, 2009. 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.

8 MANAGEMENT'S DISCUSSION AND ANALYSIS

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

			2008		2007		2006
Pipelines
	Comparable earnings		740		686		529
	Specific items (net of tax):
		Calpine bankruptcy settlements	152		–		–
		GTN lawsuit settlement	10		–		–
		Bankruptcy settlement with Mirant	–		–		18
		Gain on sale of Northern Border Partners, L.P. interest	–		–		13
	Net earnings		902		686		560
Energy
	Comparable earnings		641		459		429
	Specific items (net of tax, where applicable):
		Writedown of Broadwater costs	(27	)	–		–
		Gain on sale of land	–		14		–
		Fair value adjustments of natural gas storage inventory and forward contracts	–		7		–
		Income tax reassessments and adjustments	–		34		23
	Net earnings		614		514		452
Corporate
	Comparable expenses		(122	)	(58	)	(35	)
	Specific item:
		Income tax reassessments and adjustments	26		68		72
	Net (expenses)/earnings		(96	)	10		37
Net Income Applicable to Common Shares
	Continuing operations(1)		1,420		1,210		1,049
	Discontinued operations		–		–		28
Net Income Applicable to Common Shares			1,420		1,210		1,077
Comparable Earnings(1)			1,259		1,087		923
Net Income Per Common Share – Basic
	Continuing operations		$2.59		$2.33		$2.17
	Discontinued operations		–		–		0.06
			$2.59		$2.33		$2.23

(1) Comparable Earnings		1,259		1,087	923
	Specific items (net of tax, where applicable):
	Calpine bankruptcy settlements	152		–	–
	GTN lawsuit settlement	10		–	–
	Writedown of Broadwater costs	(27	)	–	–
	Gain on sale of land	–		14	–
	Fair value adjustments of natural gas storage inventory and forward contracts	–		7	–
	Bankruptcy settlement with Mirant	–		–	18
	Gain on sale of Northern Border Partners, L.P. interest	–		–	13
	Income tax reassessments and adjustments	26		102	95
	Net Income Applicable to Common Shares from Continuing Operations	1,420		1,210	1,049

MANAGEMENT'S DISCUSSION AND ANALYSIS 9

RESULTS OF OPERATIONS

Net income applicable to common shares and net income applicable to common shares from continuing operations (net earnings) were $1,420 million in 2008 compared to $1,210 million in 2007. Net income applicable to common shares and net earnings in 2006 were $1,077 million and $1,049 million, respectively. 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 income applicable to common shares in 2008 included $152 million of after-tax gains on shares received by the GTN System and Portland from the Calpine bankruptcy settlements, $10 million after tax of GTN System lawsuit settlement proceeds and a $27 million after-tax writedown of costs previously capitalized for Broadwater. Net income applicable to common shares in 2008 also included $26 million of favourable income tax adjustments from an internal restructuring and realization of losses. Net income applicable to common shares in 2007 included $102 million ($68 million in Corporate and $34 million in Energy) of favourable income tax adjustments recorded in 2007 relating to changes in Canadian federal and provincial corporate income tax legislation, the resolution of certain tax matters and an internal restructuring. Net income applicable to common shares in 2007 also included an after-tax gain of $14 million on the sale of land and $7 million after tax of net unrealized gains resulting from changes in the fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts. Net earnings in 2006 included $95 million of favourable income tax adjustments, proceeds from 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.

Excluding the above-noted items, comparable earnings for 2008, 2007 and 2006 were $1,259 million, $1,087 million and $923 million, respectively. Comparable earnings in 2008 increased $172 million compared to 2007 due to higher earnings in the Energy and Pipelines businesses, partially offset by an increase in net expenses in Corporate. Pipelines' earnings increased in 2008 compared to 2007 primarily due to a full year of earnings in 2008 from ANR. Energy's earnings from Western Power, Eastern Power and Bruce A and Bruce B (collectively, Bruce Power) operations increased in 2008 compared to 2007 primarily due to higher realized prices. Corporate net expenses in 2008 increased from 2007 primarily due to unrealized losses from the changes in the fair value of derivatives, which are used to manage TCPL's exposure to rising interest rates but do not qualify for hedge accounting, and higher financial charges.

Comparable earnings increased $164 million in 2007 compared to 2006 primarily due to additional earnings from the acquisition of ANR in February 2007, a full year of earnings in 2007 from the Bécancour and Edson facilities, and positive impacts from rate case settlements for the GTN System and Canadian Mainline. These increases were partially offset by a lower contribution from Bruce Power in 2007.

Results in 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. Forward-looking statements in this document are intended to provide TCPL shareholders and potential investors with information regarding TCPL and its subsidiaries, including management's assessment of TCPL's and its subsidiaries' future financial and operational plans and outlook. Forward-looking statements in this document may include, among others, statements regarding the anticipated business prospects and financial performance of TCPL and its subsidiaries, expectations or projections about the future, strategies and goals for growth and expansion, expected and future cash flows, costs, schedules, operating and financial results and expected impact of future commitments and contingent liabilities. 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 others, 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 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 sectors, construction and completion of capital projects, labour, equipment and material costs, access to capital markets,

10 MANAGEMENT'S DISCUSSION AND ANALYSIS

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 the "Pipelines", "Energy" and "Risk Management and Financial Instruments" sections in this MD&A, 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 Canadian 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 these non-GAAP measures to improve its ability to compare financial results among reporting periods and to enhance its understanding of operating performance, liquidity and ability to generate funds to finance operations. These 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.

Management uses comparable earnings/(expenses) to better evaluate trends in the Company's underlying operations. Comparable earnings comprise net income applicable to common shares from continuing operations adjusted for specific items that are significant, but are not reflective of the Company's underlying operations in the year. Specific items are subjective, however, management uses its judgement and informed decision-making when identifying items to be excluded in calculating comparable earnings, some of which may recur. Specific items may include but are not limited to certain income tax refunds and adjustments, gains or losses on sales of assets, legal and bankruptcy settlements, and certain fair value adjustments. The Segment Results table in this MD&A presents a reconciliation of comparable earnings to net income applicable to common shares from continuing operations.

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 Summarized Cash Flow table 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 income is presented in the "Energy" section of this MD&A.

OUTLOOK

TCPL's corporate strategy is underpinned by a long-term focus on growing its Pipelines and Energy businesses in a disciplined and measured manner. In 2009 and beyond, TCPL expects its net earnings and cash flow, combined with a strong balance sheet and proven access to capital markets, to provide the financial strength TCPL will need to complete its current capital expenditure program and continue to pursue other long-term growth opportunities and create additional value for its shareholders in the same disciplined and measured manner utilized in developing its current capital expenditure program. TCPL believes this prudence is especially important in the economic environment that currently exists in North America. In 2009, the Company will continue to implement its strategy and grow the Pipelines and Energy businesses as discussed in the "TCPL's Strategy" section of this MD&A.

The current economic slowdown is not expected to have a significant impact on TCPL's near-term earnings as the majority of TCPL's operations are underpinned by either long-term contracts or earn a regulated return. In addition, TCPL's continued focus on risk management is expected to further lessen the negative impact of the current economic slowdown to TCPL.

The Company's results in 2009 may be affected positively or negatively by a number of factors and developments as discussed throughout this MD&A, including without limitation, the factors and developments discussed in the "Forward-Looking Information", "Pipelines – Business Risks" and "Energy – Business Risks" sections. Refer to the "Pipelines – Outlook", "Energy – Outlook" and "Corporate – Outlook" sections of this MD&A for further discussion of outlook.

MANAGEMENT'S DISCUSSION AND ANALYSIS 11

CANADIAN MAINLINE   Owned 100 per cent by TCPL, the Canadian Mainline is a 14,101 km (8,762 miles) 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 23,705 km (14,730 miles) 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 and with the natural gas pipelines of other companies.

12 MANAGEMENT'S DISCUSSION AND ANALYSIS

ANR   Owned 100 per cent by TCPL, ANR is a 17,000 km (10,563 miles) transmission system that 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 providing 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 250 Bcf.

GTN SYSTEM   Owned 100 per cent by TCPL, the GTN System is a 2,174 km (1,351 miles) 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 (771 miles) 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.

NORTH BAJA   Owned 100 per cent by TCPL, the North Baja natural gas transmission system extends 129 km (80 miles) 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.

VENTURES LP   Owned 100 per cent by TCPL, Ventures LP is comprised of a 161 km (100 miles) pipeline and related facilities that supply natural gas to the oil sands region near Fort McMurray, Alberta as well as a 27 km (17 miles) pipeline that supplies natural gas to a petrochemical complex at Joffre, Alberta.

TAMAZUNCHALE   Owned 100 per cent by TCPL, the 130 km (81 miles) 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.

TUSCARORA   Owned 100 per cent by PipeLines LP, Tuscarora is a 491 km (305 miles) 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 effectively owns 32.1 per cent of the system through its 32.1 per cent interest in PipeLines LP.

NORTHERN BORDER   Owned 50 per cent by PipeLines LP, the 2,250 km (1,398 miles) 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.

GREAT LAKES   Owned 53.6 per cent by TCPL and 46.4 per cent by PipeLines LP, the 3,404 km (2,115 miles) 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, which it has through its 32.1 per cent interest in PipeLines LP.

IROQUOIS   Owned 44.5 per cent by TCPL, the 666 km (414 miles) Iroquois pipeline system connects with the Canadian Mainline near Waddington, New York, and delivers natural gas to customers in the northeastern U.S.

TQM   Owned 50 per cent by TCPL, TQM is a 572 km (355 miles) 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.

PORTLAND   Owned 61.7 per cent by TCPL, Portland is a 474 km (295 miles) 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.

MANAGEMENT'S DISCUSSION AND ANALYSIS 13

BISON   The Bison pipeline project is a proposed 480 km (298 miles) pipeline from the Powder River Basin in Wyoming to the Northern Border system in North Dakota.

KEYSTONE   Keystone is an oil pipeline consisting of 3,456 km (2,147 miles) of pipe under construction that will initially transport crude oil from Hardisty, Alberta to U.S. Midwest markets at Wood River and Patoka in Illinois, and to Cushing, Oklahoma. In addition, an expansion to the U.S. Gulf Coast is under development, which is expected to add approximately 2,720 km (1,690 miles) of pipe to the system. Commissioning of the segment to Wood River and Patoka is expected to begin in late 2009. Commissioning of the segment to Cushing is expected to begin in late 2010. The expansion to the U.S. Gulf Coast is expected to be commissioned in 2012, subject to regulatory approvals. In 2008, TCPL agreed to increase its ownership interest in Keystone up to 79.99 per cent. At December 31, 2008, TCPL owned 62 per cent of Keystone.

TRANSGAS   Owned 46.5 per cent by TCPL, TransGas is a 344 km (214 miles) natural gas pipeline system extending from Mariquita in the central region of Colombia to Cali in southwestern Colombia.

GAS PACIFICO/INNERGY   Owned 30 per cent by TCPL, Gas Pacifico is a 540 km (336 miles) 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.

PIPELINES – HIGHLIGHTS

•

Net income from Pipelines was $902 million in 2008, an increase of $216 million from $686 million in 2007. Comparable earnings from Pipelines were $740 million in 2008, an increase of $54 million from $686 million in 2007.

•

The Keystone partnerships began building the portion of the Keystone pipeline that will deliver oil to markets in the U.S. Midwest and to Cushing, Oklahoma, and secured shipping commitments for a future expansion to serve markets on the U.S. Gulf Coast.

•

TCPL began construction of the North Central Corridor expansion at a cost of approximately $925 million following approval from the Alberta Utilities Commission (AUC).

•

TCPL received approval from the AUC for the Alberta System's 2008-2009 Revenue Requirement Settlement.

•

TCPL filed an application with the National Energy Board (NEB) to establish federal jurisdiction over the Alberta System. A decision is expected in first quarter 2009.

•

ANR completed the second phase of its storage enhancement project (STEP 2008), which added 14 Bcf of storage capacity.

•

TCPL was awarded a license from the State of Alaska to construct the Alaska Pipeline Project under the Alaska Gasline Inducement Act (AGIA).

14 MANAGEMENT'S DISCUSSION AND ANALYSIS

PIPELINES RESULTS
Year ended December 31 (millions of dollars)

		2008		2007		2006
Wholly Owned Pipelines
	Canadian Mainline	278		273		239
	Alberta System	145		138		136
	ANR(1)	132		104		n/a
	GTN	65		58		46
	Foothills	24		26		27
		644		599		448
Other Pipelines
	Great Lakes(2)	44		47		44
	PipeLines LP(3)	25		18		4
	Iroquois	18		15		15
	Tamazunchale(4)	16		10		2
	Other(5)	34		46		51
	Northern Development	(9	)	(7	)	(5	)
	General, administrative, support costs and other	(32	)	(42	)	(30	)
		96		87		81
Comparable Earnings(6)		740		686		529
Calpine bankruptcy settlements(7)		152		–		–
GTN lawsuit settlement		10		–		–
Bankruptcy settlement with Mirant		–		–		18
Gain on sale of Northern Border Partners, L.P. interest		–		–		13
Net Earnings		902		686		560

⁽¹⁾

ANR's results include earnings from the date of acquisition of February 22, 2007.

⁽²⁾

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 that date.

⁽³⁾

PipeLines LP's results include TCPL's effective ownership of an additional 14.9 per cent interest in Great Lakes since February 22, 2007 as a result of PipeLines LP's acquisition of a 46.4 per cent interest in Great Lakes and TCPL's 32.1 per cent interest in PipeLines LP. Prior to this date, TCPL had a 13.4 per cent ownership interest in PipeLines LP.

⁽⁴⁾

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

⁽⁵⁾

Other includes results of Portland, Ventures LP, TQM, TransGas and Gas Pacifico/INNERGY.

⁽⁶⁾

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

⁽⁷⁾

GTN and Portland received shares of Calpine with an initial after-tax value of $95 million and $38 million (TCPL's share), respectively, from the bankruptcy settlements with Calpine. These shares were subsequently sold for an additional after-tax gain of $19 million.

Net earnings from the Pipelines business were $902 million in 2008 compared to $686 million in 2007 and $560 million in 2006. Comparable earnings from the Pipelines business of $740 million in 2008 excluded the $152 million after-tax ($279 million pre-tax) gains received by Portland and the GTN System from the bankruptcy settlements with Calpine and $10 million after-tax ($17 million pre-tax) proceeds received by GTN from a lawsuit settlement with a software supplier. The $54 million increase in comparable earnings in 2008 from 2007 was primarily due to a full year of earnings from ANR, the Alberta System rate settlement and higher earnings for the Canadian Mainline. Comparable earnings in 2006 were $529 million and excluded an $18 million bankruptcy settlement with

MANAGEMENT'S DISCUSSION AND ANALYSIS 15

Mirant and a $13 million gain on sale of TCPL's general partner interest in Northern Border Partners, L.P. The increase in comparable earnings in 2007 compared to 2006 was primarily due to the acquisitions of ANR and additional interest in Great Lakes, higher earnings as a result of rate settlements for Canadian Mainline and the GTN System, and an increased ownership in PipeLines LP.

PIPELINES – FINANCIAL ANALYSIS

Canadian Mainline

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

The Canadian Mainline currently operates under a five-year tolls settlement effective from 2007 to 2011. The cost of capital reflects an ROE as determined by the NEB's ROE formula on deemed common equity of 40 per cent. The remaining capital structure consists of short- and long-term debt, following the agreed upon redemption of the US$460 million 8.25 per cent Preferred Securities in 2007.

The settlement also established certain elements of the Canadian Mainline's fixed operating, maintenance and administration (OM&A) costs for each of the five years. The variance between actual and agreed-upon OM&A costs accrues entirely to TCPL from 2007 to 2009, and will be shared equally between TCPL and its customers in 2010 and 2011. All other cost elements of the revenue requirement are treated on a flow-through basis. The settlement also allows for performance-based incentive arrangements that the Company believes are mutually beneficial to both TCPL and its customers.

Net earnings of $278 million in 2008 were $5 million higher than $273 million in 2007 primarily due to higher performance-based incentives earned and increased OM&A cost savings and an ROE of 8.71 per cent in 2008, as determined by the NEB, compared to 8.46 per cent in 2007. These increases were partially offset by a lower average investment base.

Net earnings of $273 million in 2007 were $34 million higher than $239 million in 2006. The increase primarily reflected the positive impact of the increase in deemed common equity ratio to 40 per cent from 36 per cent as a result of the Canadian Mainline tolls settlement, performance-based incentives earned and OM&A cost savings. These increases were partially offset by a lower allowed ROE of 8.46 per cent in 2007 (2006 – 8.88 per cent) and a lower average investment base.

16 MANAGEMENT'S DISCUSSION AND ANALYSIS

Alberta System

Construction and operation of the Alberta System's facilities and the terms and conditions of its services, including rates, are regulated by the AUC, primarily under the provisions of the Gas Utilities Act (Alberta) and the Pipeline Act (Alberta).

In December 2008, the AUC approved TCPL's 2008 - 2009 Revenue Requirement Settlement Application, as discussed further in the "Pipelines – Opportunities and Developments" section of this MD&A.

The Alberta System's net earnings of $145 million in 2008 were $7 million higher than in 2007. The increase was due to the recognition of earnings related to the revenue requirement settlement. Earnings in 2007 reflected an ROE of 8.51 per cent on deemed common equity of 35 per cent.

Net earnings of $138 million in 2007 were $2 million higher than in 2006. The increase was primarily due 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 Alberta Energy and Utilities Board, the AUC's predecessor, was 8.51 per cent in 2007 compared with 8.93 per cent in 2006 on deemed common equity of 35 per cent.

ANR

TCPL completed the acquisition of ANR in February 2007. The operations of ANR are regulated primarily by the U.S. Federal Energy Regulatory Commission (FERC). ANR provides natural gas transportation, storage and various capacity-related services to a variety of customers in both the U.S. and Canada. ANR's transmission system has a peak-day capacity of 6.8 billion cubic feet per day (Bcf/d). Due to the seasonal nature of its business, ANR's volumes and revenues are generally expected to be higher in the winter months. ANR also owns and operates 250 Bcf of underground natural gas storage facilities in Michigan. ANR's 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 non-discriminatory basis.

ANR Pipeline Company's (ANR Pipeline) rates were established pursuant to a settlement approved by the FERC effective November 1997. ANR Storage Company's rates were established pursuant to a settlement approved by the FERC effective 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 rate case.

Net income for 2008 was $132 million compared to $104 million for the period from the date of acquisition on February 22, 2007 to December 31, 2007. The increase in 2008 was primarily due to a full year of earnings in 2008 and increased revenues from new growth projects, partially offset by higher OM&A costs, including remediation expenditures for damage caused by Hurricane Ike.

GTN

Both of GTN's systems, the GTN System and North Baja (collectively, GTN), are subject to FERC-approved tariffs that establish maximum and minimum rates for various services. GTN's pipeline rates were established pursuant to a settlement approved by the FERC in January 2008, and these rates became effective January 1, 2007. Under the settlement, a five-year moratorium was established during which the GTN System and the settling parties are prohibited under the Natural Gas Act of 1938 from taking certain actions, including any filings to adjust rates. The settlement also requires the GTN System to file a rate case within seven years of the effective date. The systems are permitted to discount or negotiate these rates on a non-discriminatory basis. GTN's earnings are affected by variations in contracted

MANAGEMENT'S DISCUSSION AND ANALYSIS 17

volume levels, volumes delivered and prices charged under the various service types, as well as by variations in the costs of providing services.

GTN's comparable earnings were $65 million in 2008, an increase of $7 million compared to 2007 primarily due to decreased OM&A expenses. An increase in revenues for North Baja was offset by a decrease in revenues for the GTN System.

Comparable earnings were $58 million in 2007, a $12 million increase from 2006. The increase was primarily due to the positive impact of the rate case settlement in 2007, partially offset by lower long-term firm contracted volumes, a higher provision taken for non-payment of contract revenues from Calpine and a weaker U.S. dollar in 2007.

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 $96 million in 2008 compared to $87 million in 2007. The increase was primarily due to lower general, administrative and support costs, and higher earnings from PipeLines LP, Tamazunchale and Iroquois, partially offset by lower earnings from Gas Pacifico/INNERGY, TransGas, Portland and Great Lakes.

Comparable earnings from Other Pipelines were $87 million in 2007, a $6 million increase compared to 2006. The increase was primarily due to higher PipeLines LP earnings resulting from TCPL's increased ownership interests in PipeLines LP and Great Lakes, and a full year of earnings in 2007 from Tamazunchale. These increases were partially offset by higher project development and support costs associated with growing the Pipelines business, the effects of a weaker U.S. dollar in 2007 and proceeds of a bankruptcy settlement received by Portland in 2006.

At December 31, 2008, Other Assets included $74 million and $42 million for capitalized costs related to the Keystone expansion to the U.S. Gulf Coast and the Bison pipeline project, respectively.

PIPELINES – OPPORTUNITIES AND DEVELOPMENTS

Keystone

Keystone is expected to deliver crude oil from Hardisty, Alberta, to U.S. Midwest markets at Wood River and Patoka in Illinois, and to Cushing, Oklahoma.

In March 2008, the U.S. Department of State issued a Presidential Permit to Keystone authorizing construction, maintenance and operations of facilities at the U.S./Canada border for the transportation of crude oil between the two countries. Construction of Keystone began in May 2008 in both Canada and the U.S. Commissioning of the Wood River and Patoka segment is expected to commence in late 2009 with commercial operations to follow in early 2010. Commissioning of the Cushing segment is expected to commence in late 2010.

In June 2008, Keystone received approval from the NEB to add new pumping facilities to accommodate an increase to approximately 590,000 Bbl/d from 435,000 Bbl/d in volumes to be delivered to the Cushing markets.

After an open season conducted during third quarter 2008, Keystone secured additional firm, long-term contracts totaling 380,000 Bbl/d for an average term of approximately 17 years. With these shipper commitments, Keystone will proceed with the necessary regulatory applications in Canada and the U.S. for approvals to construct and operate an expansion of the pipeline system that will provide additional capacity from Western Canada to the U.S. Gulf Coast in 2012 and will increase the total commercial capacity of Keystone to approximately 1.1 million Bbl/d. With the additional contracts, Keystone now has secured long-term commitments for 910,000 Bbl/d for an average term of approximately 18 years. This includes commitments made by shippers to sign transportation service agreements for 35,000 Bbl/d capacity in an open season to be held in 2009. The commitments represent approximately 83 per cent of the commercial design of the system.

The entire Keystone project is currently expected to cost approximately US$12 billion between 2008 and 2012. In 2008, the Keystone partnerships made capital expenditures of approximately $1.7 billion on the entire project, of which $1.0 billion was contributed by TCPL.

18 MANAGEMENT'S DISCUSSION AND ANALYSIS

TCPL has agreed to increase its equity ownership in the Keystone partnerships up to 79.99 per cent from 50 per cent with ConocoPhillips' equity ownership being reduced concurrently to 20.01 per cent. In accordance with this agreement, TCPL will fund 100 per cent of the construction expenditures until the participants' project capital contributions are aligned with the revised ownership interests. At December 31, 2008, TCPL's equity ownership in the Keystone partnerships was approximately 62 per cent. Certain parties that have made volume commitments to the Keystone expansion have an option to acquire up to a combined 15 per cent equity ownership in the Keystone partnerships by the end of first quarter 2009. If all of the options are exercised, TCPL's equity ownership would be reduced to 64.99 per cent.

Keystone's tolls, tariffs and facilities are regulated by the NEB in Canada and the FERC in the U.S., and have been approved for the segments shipping to Wood River, Patoka and Cushing. The Company expects the tolls and tariffs to remain in place for the term of the initial shipper contracts, which comprise approximately 83 per cent of Keystone's commercial capacity.

Canadian Mainline

In December 2008, the NEB announced that, pursuant to its formula, the 2009 allowed ROE for NEB-regulated pipelines, including the Canadian Mainline, will be 8.57 per cent, a decrease from 8.71 per cent in 2008.

Alberta System

In December 2008, the AUC approved the Alberta System's 2008 - 2009 Revenue Requirement Settlement Application. As part of the settlement, fixed costs were established for ROE, income taxes and OM&A costs. Any variances between actual costs and those agreed to in the settlement accrue to TCPL, subject to an ROE and income tax adjustment mechanism, which accounts for variances between actual and settlement rate base, and income tax assumptions. The other cost elements of the settlement are treated on a flow-through basis.

In November 2008, an NEB hearing concluded on TCPL's application to establish Federal jurisdiction over the Alberta System. A decision is expected from the NEB at the end of February 2009. Changing from AUC to NEB jurisdiction will allow the expansion of the Alberta System beyond Alberta provincial borders.

In October 2008, the AUC approved TCPL's application for a permit to construct the North Central Corridor expansion at a cost of approximately $925 million. The expansion comprises a 300 km (186 miles) natural gas pipeline and associated compression facilities on the northern section of the Alberta System.

On September 8, 2008, TCPL reached a proposed agreement with Canadian Utilities Limited (ATCO Pipelines) to provide seamless natural gas transmission service to customers. If approved by regulatory authorities, the arrangement will see the two companies combine physical assets under a single rates and services structure with a single commercial interface for customers but with each company separately managing assets within distinct operating territories in the province. TCPL continues to work with all stakeholders to finalize this agreement.

In February 2008, the AUC initiated a Generic Cost of Capital proceeding to review the generic ROE and capital structures of AUC regulated utilities. In November 2008, TCPL filed an application requesting an 11 per cent ROE on 40 per cent deemed common equity for the Alberta System in 2009. The hearing is scheduled to begin on May 19, 2009.

ANR

In 2008, ANR completed its STEP 2008 project, which added 14 Bcf of storage and 200 million cubic feet per day (mmcf/d) of withdrawal capacity to the Cold Springs 1 storage field located in Northern Michigan, and increased ANR's total storage capacity to 250 Bcf. The project was completed under budget and service was provided on schedule. Supply on ANR's southwest leg was increased as a result of an interconnect with the Rockies Express natural gas pipeline, which commenced service in January 2008. There is strong potential for new supply on the southeast leg from shale gas in the mid-continent region, and another interconnect with the Rockies Express pipeline is planned for the southeast leg in Indiana in mid-2009. ANR is also pursuing other supply additions on both its southwest and southeast legs.

In September 2008, certain portions of the Company's Gulf of Mexico offshore facilities were impacted by Hurricane Ike. The Company estimates its total exposure to damage costs to be approximately US$30 million to US$40 million, mainly to replace, repair and abandon capital assets, including the estimated cost to abandon an offshore platform. At December 31, 2008, capital expenditures of US$2 million and OM&A costs of US$6 million had been incurred. The

MANAGEMENT'S DISCUSSION AND ANALYSIS 19

remaining costs are primarily expected to be capital expenditures. Service on the majority of the offshore facilities has been restored and related throughput volumes have returned to near pre-hurricane levels. The timing of the remaining facilities' return to service is primarily dependent upon decisions to be made by upstream producers regarding their damaged facilities in the Gulf of Mexico.

Palomar

In December 2008, Palomar Gas Transmission LLC filed with the FERC for a certificate to build a pipeline extending from the GTN System in central Oregon, to the Columbia River northwest of Portland. The proposed pipeline is expected to be capable of transporting up to 1.3 Bcf/d of natural gas. The project is a 50/50 joint venture of GTN and Northwest Natural Gas Co.

North Baja

In September 2008, the FERC approved North Baja's application to build a natural gas pipeline to serve the Yucca Power Plant owned by Arizona Public Service Company. Three miles of the proposed pipeline are expected to be in the U.S. and owned by North Baja, and another three miles in Mexico are owned by Gasoducto Bajanorte. Pending final approval by the U.S. Government, construction is expected to commence in first quarter 2009 with a projected in-service date of May 2009.

Portland

On April 1, 2008, Portland filed a general rate case with the FERC proposing a rate increase of approximately six per cent as well as other changes to its tariffs. In accordance with a FERC order dated May 1, 2008, the proposed tariffs went into effect on September 1, 2008, subject to refund. The hearing is scheduled to begin on July 13, 2009.

TQM

In December 2008, the NEB concluded a proceeding with respect to TQM's Cost of Capital application for 2007 and 2008. The application sought an ROE of 11 per cent on deemed equity of 40 per cent. The proceeding also provided an opportunity for TQM to propose alternatives to the current ROE formula. A decision from the NEB is expected in first quarter 2009.

U.S. Rockies Pipeline Projects

The Bison pipeline project is a proposed pipeline from the Powder River Basin in Wyoming to the Northern Border system in North Dakota. The project has shipping commitments for approximately 405 mmcf/d and is expected to be in service in fourth quarter 2010. The capital cost of the Bison pipeline project is estimated at US$500 million to US$600 million. TCPL continues to work with Bison shippers to finalize the size and design of this project.

In addition, TCPL is proposing the Pathfinder pipeline project, a 1,006 km (625 miles) pipeline from Meeker, Colorado to the Northern Border system in North Dakota. A portion of the Pathfinder pipeline may share a common route with the Bison pipeline and may also share some common facilities. TCPL continues to work with prospective Pathfinder shippers to advance this project.

TCPL and Williams Gas Pipeline Company, LLC (Williams) are evaluating the development of the Sunstone pipeline, a proposed pipeline from Wyoming to Stanfield, Oregon. This project would provide Pacific Northwest and California markets with access to incremental Rockies supply. TCPL and its partner continue to work with customers to determine the appropriate size, time and route for this project.

Mackenzie Gas Pipeline Project

The MGP is a proposed 1,200 km (746 miles) 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 totaled $140 million at December 31, 2008 and are included in Other Assets. These amounts constitute a loan to the APG, which becomes repayable only after the natural gas pipeline commences commercial operations. The total amount of the loan is expected to form part of the rate base of the pipeline and to 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 through loan repayments and/or equity ownership in the project depends 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 it. 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 obtaining regulatory approval and the Canadian government's support of an acceptable fiscal framework. Project timing continues to be uncertain. Detailed discussions with the Canadian government have taken place and have resulted in a proposal in January 2009 from the government to the MGP. The co-venture group is considering the proposal and is expected to respond to the government in the near future. In the event the co-venture group is unable to reach an agreement with the government on an acceptable fiscal framework, the parties will need to determine the appropriate next steps for the project. For TCPL, this may result in a reassessment of the carrying amount of the APG advances.

Alaska Pipeline Project

In November 2007, TCPL submitted an application to the State of Alaska for a license to construct the Alaska Pipeline Project under the AGIA. In January 2008, Alaska Governor Sarah Palin's administration determined that TCPL's application was the only proposal that met all of the state's requirements and in December 2008 the State of Alaska issued the AGIA license to TCPL. Under the AGIA, the State of Alaska has agreed to reimburse a share of TCPL's eligible pre-construction costs to a maximum of US$500 million.

The Alaska Pipeline Project will be a 4.5 Bcf/d natural gas pipeline extending approximately 2,760 km (1,715 miles) from a new natural gas treatment plant at Prudhoe Bay, Alaska to Alberta. This pipeline will integrate with the Alberta System to provide access to diverse markets across North America. The application included provision for expansions up to 5.9 Bcf/d through the addition of compressor stations in Alaska and Canada. TCPL estimated the total capital cost of the entire project to be approximately US$26 billion in 2007 dollars.

Since the AGIA license was awarded, TCPL has moved forward with developing the project, which involves engineering, environmental, aboriginal relations and commercial work to conclude an initial binding open season by mid-2010. TCPL continues its efforts to align with potential shippers and if sufficient firm contracts are secured in the open season, construction would begin following regulatory approvals, with an anticipated in-service date of 2018.

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 contracts has resulted in significant reductions in long-term firm contracted capacity and shifts to short-term firm and interruptible contracts on the Canadian Mainline, the Alberta System, Foothills and the GTN System.

In 2008, the gas supply environment changed. Production out of the WCSB declined while supply in the U.S. grew. Previously it had been expected that U.S. supply would decline. Furthermore, with lower natural gas prices, lower cost U.S. gas developments may hinder the further development of WCSB gas supplies.

TCPL's primary source of natural gas supply is the WCSB. The WCSB has 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, supply from the WCSB has declined in recent years due to a continued reduction in levels of drilling activity in the basin. The reduced drilling activity is a result of lower prices, higher supply costs, which include higher royalties in Alberta, and competition for capital from other North American basins that have lower exploration costs. Drilling levels in the WCSB are expected to reach a low point in 2009 and then should begin to recover in the ensuing years assuming that gas prices stabilize at $6 to $7 per gigajoule (GJ) and that finding and development costs become more economical. TCPL anticipates there will be excess natural gas pipeline capacity out of the WCSB in the foreseeable future as a result of capacity expansions on its wholly owned and partially

MANAGEMENT'S DISCUSSION AND ANALYSIS 21

owned natural gas pipelines over the past decade, competition from other pipelines, and significant growth in natural gas demand within Alberta driven by oil sands 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. Recently, shale gas production in B.C. has emerged as a potentially significant natural gas supply source.

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, resulting in an increase in Canadian Mainline tolls.

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. However, the Company believes the current environment could reverse this trend in the short term given sufficient levels of erosion of market demand. Although there are opportunities to increase market share in Canadian domestic 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 source U.S. and Atlantic Canadian supplies.

The source of oil supply for Keystone is located primarily in Alberta, which produces approximately 79 per cent of the oil in the WCSB. In 2008, the WCSB produced a total of approximately 2.4 million Bbl/d, comprised of 1.2 million Bbl/d of conventional crude oil and condensate, and 1.2 million Bbl/d of oil from the oil sands area of Alberta. The production of conventional oil has been declining but has been offset by increases in production of oil from the Alberta oil sands. The Alberta Energy Resources Conservation Board has estimated that there are 173 billion barrels of remaining established reserves in the Alberta oil sands.

A decline in oil prices in late 2008 has resulted in announcements of delays in oil sands projects and upgraders, however, in December 2008, the Canadian Association of Petroleum Producers forecast WCSB oil supply would increase from 2.4 million Bbl/d in 2008 to 3.5 million Bbl/d by 2015 and 4.1 million Bbl/d by 2020.

Keystone has 910,000 Bbl/d of contracts for capacity, on a ship or pay basis, with an average contract life of 18 years, which the Company believes will provide incentive for contract shippers to ship on Keystone. However, Keystone must compete for spot throughput with other oil pipelines from Alberta.

Keystone's markets for crude oil are refiners in the U.S. Midwest and Gulf Coast regions. A competing pipeline can also deliver WCSB crude oil to the Midwest markets supplied by Keystone. Currently, competing pipelines can deliver oil to the U.S. Gulf Coast, through interconnections with other pipelines. Keystone must also compete with U.S. domestically produced oil and imported oil for markets in the Midwest and Gulf Coast regions.

ANR's natural gas supply is primarily sourced from the Gulf of Mexico and mid-continent U.S. regions, which are also served by competing natural gas pipelines. ANR also has competition from other natural gas pipelines and storage operations 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 shale production in the mid-continent, from the Rockies Express natural gas pipeline originating in the Rocky Mountain region, and from LNG. 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. In addition to pipeline competition for market and supply, current difficult economic conditions are expected to reduce energy demand and may put future ANR capacity renewals at risk as the North American economy slows or potentially contracts in key markets in the upper U.S. Midwest. As lower natural gas prices reduce drilling activity, the supply growth that has been fuelling the growth in pipeline infrastructure in the mid-continent could slow down but is still expected to exceed demand requirements in the near term. These factors could negatively affect pipeline capacity value as transportation capacity becomes more abundant.

22 MANAGEMENT'S DISCUSSION AND ANALYSIS

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 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 has experienced significant contract non-renewals since 2005 as the natural gas it transports from the WCSB competes for the California and Nevada markets against supplies from the Rocky Mountain and southwestern U.S. basins. Recently, Pacific Gas and Electric Company, the GTN System's largest customer, received California Public Utilities Commission approval to commit to capacity on a proposed competing project out of the Rocky Mountain basin to the California border.

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 current financial returns approved by regulators are not as competitive as returns from other assets with similar risk profiles. In recent years, TCPL applied to the NEB and the AUC for an ROE of 11 per cent on 40 per cent deemed common equity for both the Canadian Mainline and the Alberta System. The NEB has reaffirmed its ROE formula and the AUC has established a generic ROE that is largely aligned with the NEB formula. Through rate applications and negotiated settlements, TCPL has been able to improve the common equity components of its Canadian wholly owned pipeline capital structures, but there is no assurance that this success can be repeated.

Most recently, TCPL has continued to address concerns about financial returns on the Alberta System in the AUC's 2009 Generic Cost of Capital Proceeding. In November 2008, TCPL filed an application requesting an ROE of 11 per cent on 40 per cent deemed common equity for the Alberta System. 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 these proceedings 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 become 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

Capital costs related to the construction of Keystone are subject to a capital cost risk- and reward-sharing mechanism with its customers. This mechanism allows Keystone to adjust its tolls by a factor based on the percentage change in the capital cost of the project. Tolls for the portion of Keystone to Wood River, Patoka and Cushing will be adjusted by a factor equal to 50 per cent of the percentage change in capital cost. Tolls on the expansion to the U.S. Gulf Coast will be adjusted by a factor equal to 75 per cent of the percentage change in capital cost.

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

PIPELINES – OUTLOOK

TCPL assumes that its operations in 2009 will be materially consistent with those in 2008 except for the impact of those factors discussed in this section.

Although demand for natural gas and crude oil has declined and is expected to further decline in North America in 2009 due to the current economic downturn, the Company expects demand to increase in the long term. 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 shale gas, coalbed methane and LNG, and construction and expansion of Keystone.

MANAGEMENT'S DISCUSSION AND ANALYSIS 23

TCPL expects producers will continue to explore and develop new fields in Western Canada, particularly in northeastern B.C. and the west and central foothills regions of Alberta. There is also expected to be significant exploration and development activity aimed at unconventional resources such as coalbed methane and shale gas.

In 2008, TCPL filed an application with the NEB to establish federal jurisdiction for the Alberta System. If the application is approved, the Alberta System will switch from AUC regulation to NEB regulation, allowing it to construct and operate pipeline extensions into other provinces and allowing it to provide direct integrated Alberta System natural gas transmission service to gas production locations outside of Alberta. Extensions of the Alberta System beyond Alberta's borders are currently prohibited under provincial regulation. An NEB jurisdiction decision is expected in first quarter 2009.

Most of TCPL's current expansion plans in Canadian natural gas transmission are focused on the Alberta System. TCPL recently concluded a binding open season process for natural gas transmission service for the Montney shale gas region located in northeastern B.C. Five shippers have committed to firm gas transportation contracts on the Groundbirch pipeline that will serve the Montney region. Volumes associated with these commitments will reach 1.1 Bcf/d by 2014. The Groundbirch pipeline is expected to commence service in fourth quarter 2010, subject to receipt of necessary approvals.

In addition, TCPL is finalizing details associated with a binding open season and pipeline extension project to service the Horn River shale gas region located in northeastern B.C. Five shippers have committed to firm gas transportation contracts for a total volume of 378 mmcf/d by second quarter 2012. Subject to concluding a successful binding open season, the Horn River project is expected to commence operation in second quarter 2011, subject to receipt of necessary approvals.

Both the Groundbirch and Horn River projects are proposed as extensions to the Alberta System, which will provide B.C. producers with direct integrated gas transmission service from receipt points in B.C. These pipeline projects will increase netbacks to producers and increase the throughput on the Alberta System and on its downstream pipelines that serve markets located throughout North America, as well as increase usage of the Nova Inventory Transfer commercial hub that is used by buyers and sellers of natural gas throughout North America.

In addition to extensions into B.C., new facilities are required to expand the integrated Alberta System in response to changes in the distribution of supply and in markets across the Alberta System.

In the U.S., TCPL expects unconventional production will continue to be developed from shale gas reservoirs in east Texas, northwest Louisiana, Arkansas, and southwest Oklahoma. Supplies from coalbed methane and tight gas sands in the Rocky Mountain region are also expected to grow. Additionally, in the medium to long term, some level of incremental supply is anticipated from LNG imports into the U.S., particularly in the summer months. The resulting growth in supply will provide 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 the additional Rocky Mountain and shale gas production to midwestern and eastern U.S. markets, including interconnections with ANR. As mid-continent supplies develop, the southeast leg of ANR has capacity to transport additional volumes of Rocky Mountain and mid-continent shale production, as well as LNG.

Producers continue to develop new oil supply in Western Canada. There are several new oil sands projects under construction that will begin production in 2009 and 2010. By 2015, oil sands production is expected to double from 1.2 million Bbl/d in 2008 and total Western Canada oil supply is projected to grow over the same period to approximately 3.5 million Bbl/d from 2.4 million Bbl/d. The primary market for new oil production extends from the U.S. Midwest to the U.S. Gulf Coast and contains a large number of refineries that are well equipped to handle Canadian light and heavy crude oil blends. Incremental western Canadian crude oil production is expected to replace declining U.S. imports of crude oil from other countries.

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

24 MANAGEMENT'S DISCUSSION AND ANALYSIS

Earnings

The Company expects continued growth on its Alberta System. The Company also 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. 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 firm transportation contract volumes due to customer defaults, lower 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 also impacted by changes in foreign currency exchange rates.

Capital Expenditures

Total capital spending for all pipelines in 2008 was $1.8 billion. Capital spending for the wholly owned pipelines in 2009 is expected to be approximately $1.1 billion. In addition, capital spending for TCPL's share of constructing Keystone is expected to be approximately $3.6 billion in 2009.

NATURAL GAS THROUGHPUT VOLUMES
(Bcf)

	2008	2007	2006
Canadian Mainline(1)	3,467	3,183	2,955
Alberta System(2)	3,800	4,020	4,051
ANR(3)	1,655	1,210	n/a
GTN System	783	827	790
Foothills	1,292	1,441	1,403
North Baja	104	90	95
Great Lakes	784	829	816
Northern Border	731	800	799
Iroquois	376	394	384
TQM	170	207	158
Ventures LP	165	178	179
Gas Pacifico	73	71	52
Portland	50	58	52
Tamazunchale(4)	53	29	n/a
Tuscarora	30	28	28
TransGas	26	24	22

⁽¹⁾

Canadian Mainline physical receipts originating at the Alberta border and in Saskatchewan in 2008 were 1,898 Bcf (2007 – 2,090 Bcf; 2006 – 2,207 Bcf).

⁽²⁾

Field receipt volumes for the Alberta System in 2008 were 3,843 Bcf (2007 – 4,047 Bcf; 2006 – 4,160 Bcf).

⁽³⁾

ANR's results include delivery volumes from the date of acquisition of February 22, 2007.

⁽⁴⁾

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   TCPL has the rights to 100 per cent of the generating capacity of the 560 MW Sundance A coal-fired power generating 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 that expires in 2020. The Sundance facilities are located in south-central Alberta.

SHEERNESS   TCPL has the rights to 756 MW of generating capacity from the Sheerness coal-fired plant under a PPA, which expires in 2020. The Sheerness plant is located in southeastern Alberta.

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

26 MANAGEMENT'S DISCUSSION AND ANALYSIS

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

BRUCE POWER   Bruce Power is a nuclear generating facility located northwest of Toronto, Ontario. TCPL owns 48.9 per cent of Bruce A, which has four 750 MW reactors, two of which are currently being refurbished and are expected to restart in 2010. TCPL owns 31.6 per cent of Bruce B, which has four operating reactors with a combined capacity of approximately 3,200 MW.

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 the downtown area of Toronto, Ontario. The plant is 50 per cent owned by TCPL and is expected to be commissioned in its combined-cycle mode in first quarter 2009.

BÉCANCOUR   A 550 MW natural gas-fired cogeneration power plant, Bécancour is located near Trois-Rivières, Québec.

CARTIER WIND   The 740 MW Cartier Wind farm consists of six wind power projects located in Québec. Cartier Wind is 62 per cent owned by TCPL. Three of the projects, Baie-des-Sables, Anse-á-Valleau and Carleton have generating capacities of 110 MW, 101 MW and 109 MW, respectively. 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.

KIBBY WIND   The 132 MW Kibby Wind power project is under construction and will include 44 turbines located in Kibby and Skinner Townships in Maine. Construction began in July 2008 and commissioning of the first phase is expected to begin in fourth quarter 2009.

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 Burrillville, Rhode Island.

RAVENSWOOD   In August 2008, TCPL acquired the 2,480 MW multiple unit generating facility in Queens, New York employing dual-fuel capable steam turbine, combined cycle and combustion turbine technology.

COOLIDGE   A 575 MW simple-cycle, natural gas-fired peaking power generation station, Coolidge is under development in Coolidge, Arizona. Detailed engineering, geotechnical and regulatory work began in 2008 and commissioning of the facility is expected in 2011.

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 capability of delivering 480 mmcf/d.

MANAGEMENT'S DISCUSSION AND ANALYSIS 27

ENERGY – HIGHLIGHTS

•

Energy's net earnings were $614 million in 2008, an increase of $100 million from $514 million in 2007. Energy's comparable earnings were $641 million in 2008, an increase of $182 million from $459 million in 2007.



•

In August 2008, TCPL acquired the 2,480 MW Ravenswood facility in Queens, New York for US$2.9 billion, subject to certain post-closing adjustments.



•

Approximately 2,700 MW of additional generation capacity was under construction at December 31, 2008, with an anticipated capital cost of $5 billion.



•

Since 1999, the nominal generating capacity of TCPL's Energy business has increased by approximately 7,800 MW, representing an investment of approximately $7 billion to the end of 2008, with an additional 2,700 MW currently under development and construction.

ENERGY RESULTS
Year ended December 31 (millions of dollars)

	2008		2007		2006
Western Power	426		308		297
Eastern Power	338		255		187
Bruce Power	201		167		235
Natural Gas Storage	135		136		93
General, administrative, support costs and other	(168	)	(158	)	(144	)
Operating income	932		708		668
Financial charges	(23	)	(22	)	(23	)
Interest income and other	6		10		5
Income taxes	(274	)	(237	)	(221	)
Comparable Earnings(1)	641		459		429
Writedown of Broadwater costs	(27	)	–		–
Gain on sale of land	–		14		–
Fair value adjustments of natural gas storage inventory and forward contracts	–		7		–
Income tax adjustments	–		34		23
Net Earnings	614		514		452

⁽¹⁾

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

Energy's net earnings in 2008 of $614 million increased $100 million compared to $514 million in 2007. Comparable earnings of $641 million in 2008 increased $182 million compared to 2007 and excluded a $27 million writedown of costs previously capitalized for Broadwater. The increases in comparable and net earnings were due to higher operating income in Western Power, Eastern Power and Bruce Power. Comparable earnings of $459 million for 2007 excluded net unrealized gains of $7 million resulting from changes in fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts, a $14 million gain on sale of land and $34 million of favourable income tax adjustments.

28 MANAGEMENT'S DISCUSSION AND ANALYSIS

Energy's net earnings in 2007 were $514 million compared to $452 million in 2006. Comparable earnings were $459 million in 2007, an increase of $30 million from 2006. The increase was due to higher operating income in Eastern Power, Natural Gas Storage and Western Power, partially offset by a reduced contribution from Bruce Power. Comparable earnings excluded net unrealized gains of $7 million resulting from natural gas storage fair value changes, a $14 million gain on sale of land, $34 million of favourable income tax adjustments in 2007 as well as a $23 million favourable impact in 2006 from future income taxes as a result of reductions in Canadian federal and provincial corporate income tax rates.

POWER PLANTS – NOMINAL GENERATING CAPACITY AND FUEL TYPE

		MW	Fuel Type
Western Power
	Sheerness	756	Coal
	Coolidge(1)	575	Natural gas
	Sundance A	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
		2,636
Eastern Power
	Ravenswood(3)	2,480	Natural gas/oil
	Halton Hills(1)	683	Natural gas
	TC Hydro	583	Hydro
	OSP	560	Natural gas
	Bécancour	550	Natural gas
	Cartier Wind(4)	458	Wind
	Portlands Energy(5)	275	Natural gas
	Kibby Wind(1)	132	Wind
	Grandview	90	Natural gas
		5,811
Bruce Power(6)		2,480	Nuclear
Total nominal generating capacity(1)		10,927

⁽¹⁾

Halton Hills and Kibby Wind are currently under construction. Coolidge is currently under development.

⁽²⁾

Represents TCPL's 50 per cent share of the Sundance B power plant output.

⁽³⁾

Acquired in third quarter 2008.

⁽⁴⁾

Represents TCPL's 62 per cent share of the total 740 MW project. Three of six wind farms were placed in service, one in November 2008, one in November 2007 and the other in November 2006, with a combined generating capacity of 320 MW.

⁽⁵⁾

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

⁽⁶⁾

Represents TCPL's 48.9 per cent proportionate interest in Bruce A and 31.6 per cent proportionate interest in Bruce B.

MANAGEMENT'S DISCUSSION AND ANALYSIS 29

ENERGY – FINANCIAL ANALYSIS

Western Power

As at December 31, 2008, Western Power owns or has the rights to approximately 2,600 MW of power supply in Alberta and the western U.S. from its three long-term power purchase arrangements (PPA), six natural gas-fired cogeneration facilities and a peaking facility under development in Arizona. The power supply portfolio of Western Power in Alberta 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 includes some of the lowest cost, most competitive generation in the Alberta market area. The Sheerness and Sundance B PPAs have remaining terms of 12 years, while the Sundance A PPA has a remaining term of nine years. In 2008, the Salt River Project Agricultural Improvement and Power District (Salt River Project), a utility based in Phoenix, Arizona, entered into a 20-year PPA to secure 100 per cent of the output from TCPL's planned Coolidge generating station. The simple-cycle natural gas-fired peaking power facility to be located in Coolidge, Arizona is expected to be commissioned in 2011 and have a nominal generating capacity of 575 MW.

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 natural 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 Energy's 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 exposure to spot market prices on uncontracted volumes, Western Power had, as at December 31, 2008, fixed-price power sales contracts to sell approximately 8,800 gigawatt hours (GWh) in 2009 and 5,500 GWh in 2010.

Plant operations in Alberta consist of five natural gas-fired cogeneration power plants 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 natural 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 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 an increase in the market heat rate and declines in proportion to a decrease in the market heat rate. Market heat rates in Alberta increased in 2008 by approximately six per cent as a result of an increase in average power prices, partially offset by an increase in spot market natural gas prices. Market heat rates averaged approximately 12.05 GJ/MWh in 2008 compared to approximately 11.40 GJ/MWh in 2007.

Western Power's plants operated with an average plant availability of approximately 87 per cent in 2008 compared to 90 per cent in 2007. The decrease was primarily due to an extended outage at the Cancarb power plant.

30 MANAGEMENT'S DISCUSSION AND ANALYSIS

Western Power Results
Year ended December 31 (millions of dollars)

		2008		2007		2006
Revenues
	Power	1,140		1,045		1,185
	Other(1)	130		89		169
		1,270		1,134		1,354
Commodity purchases resold
	Power	(575	)	(608	)	(767	)
	Other(2)	(64	)	(65	)	(135	)
		(639	)	(673	)	(902	)
Plant operating costs and other		(180	)	(135	)	(135	)
Depreciation		(25	)	(18	)	(20	)
Operating income		426		308		297

⁽¹⁾

Other revenue includes sales of natural gas, sulphur and thermal carbon black.

⁽²⁾

Other commodity purchases resold includes the cost of natural gas sold.

Western Power Sales Volumes
Year ended December 31 (GWh)

			2008	2007	2006
Supply
	Generation		2,322	2,154	2,259
	Purchased
		Sundance A & B and Sheerness PPAs	12,368	12,199	12,712
		Other purchases	807	1,433	1,905
			15,497	15,786	16,876
Contracted vs. Spot
	Contracted		11,284	11,998	12,750
	Spot		4,213	3,788	4,126
			15,497	15,786	16,876

Operating income was $426 million in 2008, an increase of $118 million from $308 million in 2007. The increase was primarily due to increased margins from a combination of higher overall realized power prices and market heat rates on uncontracted volumes of power sold, as well as a $23 million increase from sales of sulphur at significantly higher prices in 2008. In 2008, the Company sold the remainder of its sulphur stock pile, which it has been selling in modest quantities on a break-even basis since 2005.

Revenues increased in 2008 primarily due to the higher overall power sales prices. Commodity purchases resold decreased in 2008 compared to 2007 primarily due to a decrease in volumes purchased and the expiry of certain retail contracts. Plant operating costs and other, which includes fuel gas consumed in generation, increased in 2008 as a result of higher volumes of gas purchased at higher prices. Purchased power volumes in 2008 decreased primarily due

MANAGEMENT'S DISCUSSION AND ANALYSIS 31

to the expiry of certain retail contracts, partially offset by increased utilization from the Alberta PPAs. Approximately 27 per cent of power sales volumes were sold in the spot market in 2008 compared to 24 per cent in 2007.

Operating income was $308 million in 2007, an increase of $11 million from $297 million in 2006. The increase was primarily due 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 primarily due 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 into the spot market in 2007, which was consistent with 2006.

Eastern Power

Eastern Power owns approximately 5,800 MW of power generation capacity, including facilities under construction or in the development phase. Eastern Power's current operating power generation assets are Ravenswood, TC Hydro, OSP, Bécancour, the Cartier Wind farms and Grandview. Ravenswood, acquired in August 2008, is a 2,480 MW gas and oil-fired generating facility consisting of multiple units employing steam turbine, combined-cycle and combustion turbine technology. Ravenswood, located in Queens, has the capacity to serve approximately 21 per cent of the overall peak load in New York City. The TC Hydro assets include 13 hydroelectric stations housing a total of 39 hydroelectric generating units in New Hampshire, Vermont and Massachusetts.

OSP, a natural gas-fired combined-cycle facility, is the largest power plant in Rhode Island. Bécancour, a natural gas-fired cogeneration plant located near Trois Rivières, Québec, was placed into service in September 2006. The entire power output is supplied to Hydro-Québec under a 20 year power purchase contract. Steam from this facility is sold to an industrial customer for use in commercial processes. Cartier has a combined generating capacity of 320 MW and consists of three wind farms, Carleton, Anse-á-Valleau, and Baie-des-Sables, which were placed into service in November 2008, November 2007 and November 2006, respectively. Output from these three wind farms is supplied to Hydro-Québec under 20 year power purchase contracts. Grandview is a natural gas-fired cogeneration facility on the site of the Irving Oil Refinery (Irving) in Saint John, New Brunswick. Under a 20 year tolling arrangement which will expire in 2025, Irving supplies fuel for the plant and contracts for 100 per cent of the plant's heat and electricity output.

Eastern Power conducts its business primarily in the deregulated New England and New York power markets and in Eastern Canada. In the New England market, TCPL has established a marketing operation through its wholly owned subsidiary, TransCanada Power Marketing Ltd. (TCPM). TCPM is located in Westborough, Massachusetts, and effective January 1, 2009, also markets the output from the Ravenswood facility. To reduce exposure to spot market prices on uncontracted volumes, Eastern Power had, as at December 31, 2008, fixed price sales contracts to sell forward approximately 13,000 GWh in 2009 and 15,000 GWh in 2010, although certain contracted volumes are dependant on customer usage levels. Actual amounts contracted in future periods will depend on market liquidity and other factors. Fixed price sales contracts in 2009 exclude approximately 4,300 GWh of generation from the Bécancour power plant as a result of a suspension of electricity generation that began in January 2008 and continues through December 2009. The suspension of the Bécancour power facility is discussed further in the "Energy – Opportunities and Developments" section of this MD&A.

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 2008, TCPM continued to expand its marketing presence and customer base in the New England market.

The Forward Capacity Market (FCM) in the New England power pool is intended to promote investment in new and existing power resources needed to meet growing consumer demand and maintain a reliable power system. Under the FCM, Independent System Operator New England (ISO-NE) projects the needs of the power system three years in advance, following which it holds an annual auction to purchase power resources to satisfy future needs. Prior to the

32 MANAGEMENT'S DISCUSSION AND ANALYSIS

auction period, certain transition payments are made to capacity suppliers in New England that were in existence at June 2006.

ISO-NE has undertaken two Forward Capacity Auctions (FCA) under the FCM framework for procurement of installed capacity; FCA1 for the 2010-2011 period and FCA2 for the 2011-2012 period. All of Eastern Power's existing and planned power assets in the New England market were entered into both FCA1 and FCA2. Both auctions resulted in significant amounts of qualifying capacity resulting in decreased prices. The clearing prices in these auctions were US$4.25 and US$3.12 per kilowatt-month, respectively. Future auction results will be affected by actual demand growth and the pace of progress in the development of new qualifying resources that bid into these auctions, as well as other factors.

The New York Independent System Operator (NYISO) relies on a locational capacity market intended to promote investment in new and existing power resources needed to meet growing consumer demand and maintain a reliable power system. Currently, a series of voluntary forward auctions and a mandatory spot demand curve price setting process is used to determine the price that is paid to capacity suppliers. There are separate demand curves for each of the three capacity zones: Long Island, New York City and the rest of the state. Ravenswood's capacity is located in the New York City capacity zone. Energy and capacity prices for Ravenswood are affected by circumstances that have an impact on supply and demand within this zone, certain NYISO market rules impacting both buyers and suppliers of capacity in this zone, and certain reliability criteria set out by the NYISO and the New York State Reliability Council. There is currently surplus capacity within this zone, however, TCPL expects capacity will tighten after 2009 as a result of the expected retirement of a power station owned by the New York Power Authority.

Eastern Power Results⁽¹⁾
Year ended December 31 (millions of dollars)

		2008		2007		2006
Revenues
	Power	1,254		1,481		789
	Other(2)	350		239		292
		1,604		1,720		1,081
Commodity purchases resold
	Power	(519	)	(755	)	(379	)
	Other(3)	(324	)	(208	)	(257	)
		(843	)	(963	)	(636	)
Plant operating costs and other		(342	)	(454	)	(226	)
Depreciation		(81	)	(48	)	(32	)
Operating income		338		255		187

⁽¹⁾

Includes Carleton, Ravenswood, Anse-à-Valleau, Baie-des-Sables and Bécancour effective November 2008, August 2008, November 2007, November 2006 and September 2006, respectively.

⁽²⁾

Other revenue includes sales of natural gas.

⁽³⁾

Other commodity purchases resold includes the cost of natural gas sold.

MANAGEMENT'S DISCUSSION AND ANALYSIS 33

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

		2008	2007	2006
Supply
	Generation	5,043	8,095	4,700
	Purchased	6,183	6,986	3,091
		11,226	15,081	7,791
Contracted vs. Spot
	Contracted	10,990	14,505	7,374
	Spot	236	576	417
		11,226	15,081	7,791

⁽¹⁾

Includes Carleton, Ravenswood, Anse-à-Valleau and Baie-des-Sables effective November 2008, August 2008, November 2007 and November 2006, respectively. Bécancour is included in Eastern Power effective September 2006 through December 2007.

Operating income was $338 million in 2008, $83 million higher than the $255 million earned in 2007. The increase was primarily due to increased water flows from the TC Hydro generation assets and higher realized prices on sales to commercial and industrial customers in New England, incremental income from the first full year of operations from the Anse-à-Valleau wind farm and the start-up of the Carleton wind farm in November 2008. On December 31, 2008, Ravenswood fulfilled its obligation under a tolling agreement with Hess Corporation that was in place at the time of acquisition. In 2009, TCPM will manage the marketing output of the Ravenswood plant in a manner consistent with its other U.S. northeast portfolio of assets. The agreement to temporarily suspend generation at the Bécancour facility beginning January 2008 resulted in decreases to power revenues, plant operating costs and other, generation volumes and contracted sales in 2008. The temporary suspension agreement has not materially affected Eastern Power's operating income due to capacity payments received pursuant to the agreement with Hydro-Québec. The agreement to suspend generation at the Bécancour facility was extended for one year to December 31, 2009.

Eastern Power's power revenues were $1,254 million in 2008, a decrease of $227 million from $1,481 million in 2007. This was primarily due to the temporary suspension of generation at the Bécancour facility and decreased sales to commercial and industrial customers in the New England market, partially offset by higher realized prices in New England, increased water flows through the TC Hydro generation assets, and incremental revenue from Ravenswood. Other revenue and other commodity purchases resold increased year-over-year as a result of an increase in the quantity of natural gas purchased and resold under OSP's and TCPM's natural gas supply contracts. Power commodity purchases resold and purchased power volumes were lower in 2008 due to the impact of decreased sales volumes to commercial and industrial customers, lower overall cost per GWh on purchased power volumes and increased power generation from the TC Hydro assets, 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 lower in 2008 primarily due to the temporary suspension of generation at the Bécancour facility, partially offset by incremental operating costs from Ravenswood.

Operating income was $255 million in 2007, $68 million higher than the $187 million earned in 2006. The increase was primarily due to incremental income from the first full year of operations from the Bécancour facility and the Baie-des-Sables wind farm, as well as 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.

34 MANAGEMENT'S DISCUSSION AND ANALYSIS

Bruce Power

As at December 31, 2008, TCPL and BPC Generation Infrastructure Trust (BPC), a trust established by the Ontario Municipal Employees Retirement System, each owned a 48.9 per cent interest in Bruce A (2007 – 48.7 per cent). The remaining 2.2 per cent interest in Bruce A is owned by the Power Workers' Union Trust, the Society of Energy Professionals Trust and Bruce Power Employee Investment Trust. The Bruce A partnership subleases Bruce A Units 1 to 4 from the Bruce B partnership. TCPL continues to own 31.6 per cent of Bruce B, which consists of Units 5 to 8 and the supporting site infrastructure.

MANAGEMENT'S DISCUSSION AND ANALYSIS 35

The following Bruce Power financial results reflect the operations of six of the eight Bruce Power units:

Bruce Power Results
Year ended December 31 (millions of dollars)

			2008		2007		2006
Bruce Power (100 per cent basis)
	Revenues
		Power	2,064		1,920		1,861
		Other(1)	96		113		71
			2,160		2,033		1,932
	Operating expenses
		Operations and maintenance(2)	(1,066	)	(1,051	)	(912	)
		Fuel	(139	)	(104	)	(96	)
		Supplemental rent(2)	(174	)	(170	)	(170	)
		Depreciation and amortization	(151	)	(151	)	(134	)
			(1,530	)	(1,476	)	(1,312	)
			630		557		620
TCPL's proportionate share:
	Bruce A (48.9%)		62		24		91
	Bruce B (31.6%)		158		161		137
			220		185		228
Adjustments			(19	)	(18	)	7
TCPL's operating income from Bruce Power			201		167		235
Bruce Power – Other Information
Plant availability
	Bruce A		82%		78%		81%
	Bruce B		87%		89%		91%
	Combined Bruce Power		86%		86%		88%
Planned outage days
	Bruce A		91		121		81
	Bruce B		100		93		65
Unplanned outage days
	Bruce A		27		17		37
	Bruce B		65		32		31
Sales volumes (GWh)
	Bruce A – 100 per cent		10,580		10,180		10,650
	Bruce A – TCPL's proportionate share		5,159		4,959		5,158
	Bruce B – 100 per cent		24,680		25,290		25,820
	Bruce B – TCPL's proportionate share		7,799		7,992		8,159
	Combined Bruce Power – 100 per cent		35,260		35,470		36,470
	TCPL's proportionate share		12,958		12,951		13,317
Results per MWh
	Bruce A power revenues		$62		$59		$58
	Bruce B power revenues		$57		$52		$48
	Combined Bruce Power revenues		$59		$55		$51
	Combined Bruce Power fuel		$4		$3		$3
	Combined Bruce Power total operating expenses(3)		$42		$41		$35
Percentage of output sold to spot market			23%		45%		35%

⁽¹⁾

Other revenue includes Bruce A fuel cost recoveries of $61 million in 2008 (2007 – $35 million; 2006 – $30 million). Other revenue also includes unrealized losses of $6 million as a result of changes in fair value of held-for-trading derivatives in 2008 (2007 – $47 million gain; 2006 – nil).

⁽²⁾

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

⁽³⁾

Net of fuel cost recoveries.

36 MANAGEMENT'S DISCUSSION AND ANALYSIS

TCPL's operating income from Bruce Power was $201 million in 2008 compared to $167 million in 2007. TCPL's proportionate share of operating income in Bruce A increased $38 million to $62 million in 2008 compared to 2007 primarily due to higher realized prices and higher volumes associated with a decrease in outage days in 2008. TCPL's proportionate share of operating income in Bruce B decreased $3 million to $158 million in 2008 compared to 2007 primarily due to higher operating costs and lower volumes associated with an increase in outage days in 2008, and unrealized gains in 2007 from changes in the fair value of power swaps and forwards. Partially offsetting these decreases were higher realized prices reflecting a higher proportion of volumes sold at higher contract prices.

Combined Bruce Power prices, which are based solely on power revenues, were $59 per MWh in 2008 compared to $55 per MWh in 2007, 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 $42 per MWh in 2008 from $41 per MWh in 2007 primarily due to higher operating costs in 2008.

The Bruce units ran at a combined average availability of 86 per cent in 2008, which was consistent with the average availability in 2007.

TCPL's operating income from its combined investment in Bruce Power was $167 million in 2007 compared to $235 million in 2006. The decrease of $68 million was primarily due to lower output and higher operating costs associated with an increase in planned outage days, partially offset by higher overall realized prices.

Adjustments to TCPL's interest in Bruce Power's income before income taxes were lower in 2008 and 2007 than in 2006 primarily due to lower positive purchase price amortizations related to the expiry of power sales agreements.

The overall plant availability percentage in 2009 is expected to be in the low 90s for the four Bruce B units and the mid-80s for the two operating Bruce A units. An approximate six week maintenance outage of Bruce B Unit 8 is scheduled to begin in mid-April 2009 and an approximate six week maintenance outage of Bruce B Unit 6 is scheduled to begin in early October 2009. An approximate six week maintenance outage of Bruce A Unit 4 is scheduled to start in early March 2009 and an approximate one-month outage of Bruce A Unit 3 is expected to commence in mid-March 2009.

Bruce A

Income from Bruce A is affected by overall plant availability, which in turn is affected by planned and unplanned maintenance. As a result of a contract with the Ontario Power Authority (OPA), all of the output from Bruce A is effectively sold at a fixed price per MWh, adjusted for inflation annually on April 1. In addition, fuel costs are recovered from the OPA. In accordance with a 2007 contract amendment, effective April 1, 2008, the fixed price for output from Bruce A was $63.00 per MWh, an increase of $2.11 per MWh, subject to inflation adjustments from October 31, 2005.

Bruce A Fixed Price

	per MWh
April 1, 2008 – March 31, 2009	$63.00
April 1, 2007 – March 31, 2008	$59.69
April 1, 2006 – March 31, 2007	$58.63

Support payments received pursuant to the OPA contract are equal to the difference between the fixed prices under the OPA contract and spot market prices and 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. As at December 31, 2008, Bruce A had received $368 million towards this cap. Post-refurbishment prices will also be adjusted for capital cost variances associated with the refurbishment and restart projects.

Bruce B

Income from Bruce B is directly affected by fluctuations in wholesale spot market prices for electricity and overall plant availability, which in turn is affected by planned and unplanned maintenance.

MANAGEMENT'S DISCUSSION AND ANALYSIS 37

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

Bruce B Floor Price

	per MWh
April 1, 2008 – March 31, 2009	$47.66
April 1, 2007 – March 31, 2008	$46.82
April 1, 2006 – March 31, 2007	$45.99

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 have not included any amounts received pursuant to this floor mechanism. To further reduce its exposure to spot market prices, as at December 31, 2008, Bruce B had entered into fixed price sales contracts to sell forward approximately 12,460 GWh for 2009 and 7,100 GWh for 2010.

Plant Availability

Weighted average power plant availability for all plants, excluding Bruce Power, was 79 per cent in 2008 compared to 93 per cent in 2007 and 2006. Plant availability represents the percentage of time in a year that the plant is available to generate power whether actually running or not. Western Power's plant availability was affected negatively throughout 2008 and in late 2007 by an outage at the Cancarb power plant. Eastern Power achieved plant availability of 78 per cent in 2008, 18 per cent lower than 2007 as a result of outages experienced on Units 10 and 30 at Ravenswood throughout fourth quarter 2008 and a longer than expected outage at OSP in late 2008. Additionally, Bécancour, which had an availability of 97 per cent in 2007, is not included in Eastern Power's 2008 availability measurement as a result of a temporary suspension of power generation from the plant throughout 2008.

Weighted Average Plant Availability
Year ended December 31

	2008	2007	2006
Western Power	87%	90%	88%
Eastern Power	78%	96%	95%
Bruce Power	86%	86%	88%
All plants, excluding Bruce Power	79%	93%	93%
All plants	83%	91%	91%

38 MANAGEMENT'S DISCUSSION AND ANALYSIS

Natural Gas Storage

TCPL owns or has rights to 120 Bcf of natural gas storage capacity in Alberta, including a 60 per cent ownership interest in 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, subject to 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 unchanged. The Company's gas storage capability helps balance seasonal and short-term supply and demand, and adds flexibility to the delivery 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 additional gas supplies be connected to North American markets. Energy's natural gas storage business operates independently from TCPL's regulated natural gas transmission business and from ANR's regulated storage business, which is included in TCPL's Pipelines segment.

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

TCPL offers a broad range of injection and withdrawal storage alternatives tailored to customer needs in short-term to 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. Earnings from third-party storage capacity contracts are recognized over the term of the contract. At December 31, 2008, TCPL had contracted approximately 70 per cent of the total 120 Bcf of working gas storage capacity in 2009 and 57 per cent of storage capacity in 2010.

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 future positive margins, thereby effectively eliminating its exposure to natural gas seasonal price spreads.

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 Revenues. Effective April 2007, 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. Changes in the fair value of inventory are recorded in Revenues. Changes in the fair value of proprietary natural gas inventory in storage and natural gas forward purchase and sales contracts are excluded in determining comparable earnings as they are not representative of amounts that will be realized on settlement.

Natural Gas Storage operating income was $135 million in 2008, a decrease of $11 million compared to 2007. The decrease was primarily due to lower average storage values realized by CrossAlta, partially offset by higher earnings from the sale of proprietary natural gas at Edson in 2008. There were no net unrealized gains or losses in 2008 from changes in the fair value of proprietary natural gas forward purchase and sales contracts compared to net unrealized gains of $10 million in 2007.

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

MANAGEMENT'S DISCUSSION AND ANALYSIS 39

ENERGY – OPPORTUNITIES AND DEVELOPMENTS

Ravenswood    In August 2008, TCPL acquired the multiple-unit Ravenswood generating facility located in Queens, New York, which employs dual-fuel capable steam turbine, combined-cycle and combustion turbine technology. During 2008, Ravenswood operated under a tolling arrangement that existed at the date of acquisition and expired on December 31, 2008. Under the tolling arrangement, all energy generated from the facility was provided to Hess Corporation for a fixed operating fee. In January 2009, Ravenswood commenced earning revenues from the sale of energy generated from the facility into the New York market. TCPL's marketing operation located in Westborough, Massachusetts manages the marketing of output from Ravenswood.

The integration into TCPL's operations of the Ravenswood generating station, acquired in August 2008, is now complete. Shortly after closing the acquisition, TCPL experienced a forced outage event affecting one of the larger multiple generating units. The unit is currently undergoing repair and it is expected that the event will be insured both for physical damage and business interruption. Other refurbishment work is being undertaken at the station while the repair work is being completed and as a result, unit availability is expected to improve in the future.

Bruce Power    Under a long-term agreement reached in 2005 between Bruce Power and the OPA, Bruce A has committed to refurbish and restart the currently idle Units 1 and 2, extend the operating life of Unit 3 with a full refurbishment and replace the steam generators on Unit 4. Bruce Power and the OPA amended the Bruce A refurbishment agreement in 2007 to allow for a full refurbishment of Unit 4, which will extend the expected operating life of the unit. Under the 2007 amendment, the OPA had the option to elect, prior to April 1, 2008, to proceed with a three-unit refurbishment and restart program instead of the revised four-unit program. The OPA chose to not exercise this option and instead elected to proceed with the four-unit refurbishment and restart program.

In fourth quarter 2008, Bruce Power completed a review of the operating life estimates for Units 3 and 4. Unit 3 is now expected to remain in commercial service until 2011, which provides the benefit of nearly two additional years of power generation before the unit commences an expected 36 month refurbishment. After the refurbishment, the operating life of Unit 3 is expected to be extended to 2038 from 2037. In addition, Unit 4 is now expected to remain in commercial service until 2016, providing nearly seven years of generation before the unit commences a similar refurbishment period, after which, the estimated operating life of Unit 4 is expected to be extended to 2042 from 2036.

The capital cost for the refurbishment and restart of Bruce A Units 1 and 2 is expected to be approximately $3.4 billion, based on a comprehensive review in January 2008 of the estimated costs to complete the project, which is an increase from the original cost estimate of $2.75 billion. TCPL's share is expected to be approximately $1.7 billion, compared to an original estimate of $1.4 billion. The project cost increases are subject to the capital cost risk- and reward-sharing mechanism under TCPL's 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, 2008, Bruce A had incurred $2.6 billion in costs with respect to the refurbishment and restart of Units 1 and 2 and approximately $200 million for the refurbishment of Units 3 and 4.

Portlands Energy    Construction continued in 2008 on Portlands Energy. The facility was operational in single-cycle mode in the summer of 2008 and is expected to be fully commissioned in its combined-cycle mode in first quarter 2009. Portlands Energy will provide power under a 20-year Accelerated Clean Energy Supply contract with the OPA. The expected capital cost is $730 million, of which TCPL's portion is 50 per cent.

Coolidge    In May 2008, the Phoenix, Arizona-based utility, Salt River Project, signed a 20-year power purchase contract to secure 100 per cent of the output from the simple-cycle natural gas-fired peaking power facility currently under development. In December 2008, the Arizona Corporation Commission granted a Certificate of Environmental Compatibility approving construction of the facility. Construction is expected to begin in the summer of 2009 and the facility is expected to be commissioned in 2011.

40 MANAGEMENT'S DISCUSSION AND ANALYSIS

Halton Hills    Construction of Halton Hills continued in 2008. 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 Carleton wind farm commenced commercial operation in November 2008, providing up to 109 MW of power to the Hydro-Québec grid. Carleton is the third phase of the six-phase, multi-year Cartier Wind project, located in the Gaspé region of Québec. The first two phases, Baie-des-Sables and Anse-á-Valleau, went into service in November of 2006 and 2007, respectively, generating up to 110 MW and 101 MW of power, respectively. 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. TCPL has a 62 per cent ownership interest in these wind farms.

Kibby Wind    In July 2008, the State of Maine's Land Use Regulation Commission approved the final development plan submitted by TCPL to build, own and operate a wind farm, located in the Kibby and Skinner townships in Maine. Construction of the facilities at a cost of approximately US$320 million began in July 2008 and commissioning of the first phase is expected to begin in fourth quarter 2009.

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. In 2008, the agreement was extended through to December 2009. In 2009, TCPL will continue to receive payments under the agreement similar to those that would have been received under the normal course of operation.

Power Transmission Line Projects    TCPL is pursuing proposals to build, own and operate power transmission lines, including the Zephyr and Chinook transmission line projects. The projects are each proposed 500 kilovolt (kV) high voltage direct current (HVDC) transmission lines originating in Wyoming and Montana, respectively, and terminating in Nevada. If constructed, each project would cost approximately US$3 billion and be capable of delivering 3,000 MW of power. In December 2008, TCPL filed applications for both projects requesting approval from the FERC to charge negotiated rates and to proceed with an open season in the spring of 2009, with 50 per cent of the capacity of each line already pre-subscribed for a period of 25 years. In February 2009, the FERC approved both applications. Pending successful completion of the open seasons, regulatory work could commence later in 2009, followed by construction commencing in 2012 and a potential in-service date of late 2014.

TCPL is pursuing a proposal to build NorthernLights, a 500 kV HVDC electric transmission line running from central Alberta to a terminal in southern Alberta and interconnecting with the Pacific Northwest. NorthernLights is expected to cost approximately $2 billion and provide up to 3,000 MW of power.

Broadwater LNG    In March 2008, the FERC authorized the construction and operation of Broadwater, subject to conditions. In April 2008, the New York Department of State determined that construction and operation of the project would not be consistent with the State's coastal zone policies. As a result of this unfavourable decision, TCPL wrote down $27 million after tax ($41 million pre-tax) of costs for Broadwater that had been capitalized to March 31, 2008. TCPL has appealed the determination of the New York Department of State to the U.S. Department of Commerce and a decision is expected in early 2009.

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.

MANAGEMENT'S DISCUSSION AND ANALYSIS 41

Uncontracted Volumes

Energy has uncontracted power sales volumes in Western Power and Eastern Power and through its investment in Bruce Power. In addition, with the acquisition of Ravenswood, at December 31, 2008, Eastern Power significantly increased its level of uncontracted sales volumes, which are subject to price volatility. 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 subject to a floor price mechanism that are sold into the wholesale power spot market under contract price terms with the OPA, 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.

Liquidity Risk

A decrease in the number and credit quality of counterparties with which to transact may increase the Company's exposure to spot prices by reducing its ability to lock in forward sale prices at acceptable contract 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.

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, Québec, Maine and Arizona, 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.

Regulation of Power Markets

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 affect 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 and attempts by others to take out-of-market actions to build excess generation that negatively affects the price for capacity or energy, or both. In addition, TCPL's development projects rely on an orderly permitting process and any disruption to that process can have negative effects on project schedule and cost. TCPL

42 MANAGEMENT'S DISCUSSION AND ANALYSIS

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 additional risks and managing risks in the Energy business.

ENERGY – OUTLOOK

TCPL assumes that its operations in 2009 will be materially consistent with those in 2008 and includes the positive impact of a full year of earnings from Ravenswood, incremental earnings from Portlands Energy, which is expected to be commissioned in first quarter 2009, and a decrease in planned outages at Bruce Power. These positive impacts are expected to be partially offset by a return to more normal hydrology levels at TC Hydro from the record levels experienced in 2008. In addition, the current economic climate is negatively affecting demand, liquidity and prices in commodity markets in which TCPL operates.

Although TCPL has sold forward significant output from its power plants and Alberta PPAs, as well as capacity from its natural gas storage facilities, operating income in 2009 can be affected by changes in the spot market price of power, market heat rates, hydrology, forward capacity payments, natural gas storage spreads and unplanned outages. Operating income from Energy's U.S. operations is affected by changes in the U.S./Canadian dollar exchange rates.

Other factors such as plant availability, regulatory changes, weather, currency movements, and overall stability of the energy industry can also affect 2009 operating income. Refer to the "Energy – Business Risks" section of this MD&A for a complete discussion of these factors.

Following the expiry of the Ravenswood tolling arrangement with Hess Corporation on December 31, 2008, TCPL will manage the ongoing marketing of the Ravenswood plant output in the same manner as it does with other generation assets in the U.S. Northeast. Dependent on market liquidity and other factors, a significant portion of the electricity generated by the Ravenswood facility in 2009 and beyond may be sold at spot prices. As noted in the "Energy – Business Risks" section of this MD&A, spot prices for electricity are subject to change depending on underlying energy commodity prices, available supply, demand and other factors.

Capital Expenditures

Energy's total capital expenditures in 2008 were $4.3 billion, including the acquisition of Ravenswood for $3.1 billion. Energy's overall capital spending in 2009 is expected to be approximately $1.4 billion, including cash calls for the Bruce A refurbishment and restart project and continued construction at Coolidge, Cartier Wind, Kibby Wind and Halton Hills.

CORPORATE

CORPORATE RESULTS
Year ended December 31 (millions of dollars)

	2008		2007		2006
Indirect financial charges and non-controlling interests	310		266		139
Interest income and other	3		(81	)	(43	)
Income taxes	(191	)	(127	)	(61	)
Comparable Expenses(1)	122		58		35
Income tax reassessments and adjustments	(26	)	(68	)	(72	)
Net Expenses/(Earnings), after income taxes	96		(10	)	(37	)

⁽¹⁾

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

MANAGEMENT'S DISCUSSION AND ANALYSIS 43

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 in Corporate. These costs are influenced directly by the amount of debt the Company maintains, the degree to which the Company is affected by fluctuations in interest and foreign exchange rates and the amount of interest capitalized for projects under construction.

Interest Income and Other

Interest Income and Other includes interest earned on invested cash balances and income tax refunds. Also included are foreign exchange gains and losses related to translation of foreign-denominated working capital and derivatives used to manage the Company's exposure to U.S. dollar net income.

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 expenses in Corporate were $96 million in 2008 compared to net earnings of $10 million and $37 million in 2007 and 2006, respectively.

Corporate's net expenses in 2008 included favourable income tax reassessments and adjustments of $26 million compared to $68 million in 2007. Excluding these income tax adjustments, Corporate's comparable expenses increased $64 million in 2008 compared to 2007. The increase in comparable expenses was primarily due to net unrealized losses of $39 million after tax from changes in the fair value of derivatives, which are used to manage the Company's exposure to rising interest rates but do not qualify as hedges for accounting purposes. The fair value of these derivatives was negatively impacted as interest rates dropped to historic lows late in fourth quarter 2008. In addition, higher financial charges resulting from financing the Company's 2008 capital program, including the Ravenswood acquisition, and higher losses from the change in fair value of derivatives used to manage the Company's exposure to foreign exchange rate fluctuations were partially offset by increased capitalization of interest to finance a larger capital spending program. The losses from the foreign exchange derivatives were partially offset by the positive impact of a stronger U.S. dollar reported in the Pipelines and Energy businesses.

Corporate's net earnings in 2007 and 2006 included favourable income tax reassessments and adjustments of $68 million and $72 million, respectively. Excluding these income tax adjustments, Corporate's comparable expenses increased $23 million in 2007 compared to 2006. Net unrealized gains from the change in fair value of 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 ANR acquisition and additional ownership interest in Great Lakes.

CORPORATE – OUTLOOK

Corporate's net expenses in 2008 included certain favourable income tax reassessments and other impacts, including the $39 million net unrealized losses on interest rate derivatives, that are not expected to recur in 2009. Financing costs associated with debt issued in 2008 and 2009, and together with additional debt expected to be issued in 2009 to partially finance the Company's capital programs are expected to increase financial charges in Corporate in 2009. However, the increased charges are expected to be primarily offset by capitalized interest for projects under construction. Corporate's results could also be affected by debt levels, interest rates, foreign exchange rates and income tax refunds and adjustments. The performance of the Canadian dollar relative to the U.S. dollar will influence

44 MANAGEMENT'S DISCUSSION AND ANALYSIS

Corporate's results, although this impact is primarily mitigated by offsetting U.S.-dollar exposures in certain of TCPL's other businesses and by the Company's hedging activities.

DISCONTINUED OPERATIONS

The $28 million income from discontinued operations in 2006 reflected bankruptcy settlements with Mirant related to TCPL's Gas Marketing business, which was sold in 2001.

LIQUIDITY AND CAPITAL RESOURCES

Global financial markets are in turmoil, however, TCPL's financial position and ability to generate cash from its operations in the short and long term to provide liquidity and to maintain financial capacity and flexibility to provide for planned growth remains sound and consistent with recent years. TCPL's liquidity position remains solid, underpinned by highly predictable cash flow from operations, significant cash balances on hand from recent securities issues, as well as committed revolving bank lines of US$1.0 billion, $2.0 billion and US$300 million, maturing in November 2010, December 2012 and February 2013, respectively. To date, no draws have been made on these facilities as TCPL has continued to have largely uninterrupted access to the Canadian commercial paper market on competitive terms. An additional $50 million and US$320 million of capacity remains available on committed bank facilities at TCPL-operated affiliates with maturity dates from 2010 through 2012. TCPL further strengthened its liquidity and financial position through additional financing transactions in 2008 and early 2009, as discussed below. TCPL's liquidity, market and other risks are discussed further in the "Risk Management and Financial Instruments" section of this MD&A.

SUMMARIZED CASH FLOW
Year ended December 31 (millions of dollars)

	2008		2007	2006
Funds generated from operations(1)	2,992		2,603	2,374
(Increase)/decrease in operating working capital	(188	)	215	(300	)
Net cash provided by operations	2,804		2,818	2,074

⁽¹⁾

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

HIGHLIGHTS

Investing Activities

•

Capital expenditures and acquisitions, including assumed debt, totalled approximately $15.3 billion over the three-year period ending December 31, 2008.

Dividend

•

On February 2, 2009, TCPL's Board of Directors declared a dividend for the quarter ending March 31, 2009 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, 2009. The Board also declared regular dividends on TCPL's preferred shares.

MANAGEMENT'S DISCUSSION AND ANALYSIS 45

Funds Generated from Operations

Funds Generated from Operations were $3.0 billion in 2008 compared to $2.6 billion and $2.4 billion, in 2007 and 2006, respectively. The increase in 2008 compared to 2007 was primarily due to proceeds from higher operating earnings and the Calpine bankruptcy settlements. The Energy business was the primary source of the increase in 2008 compared to 2007, partially offset by a reduced contribution from Corporate. The Pipelines business and growth in Energy's operations were the main drivers for the increase in 2007 compared to 2006.

Investing Activities

Capital expenditures totalled $3,134 million in 2008 compared to $1,651 million in 2007 and $1,572 million in 2006. Expenditures in 2008 and 2007 related primarily to the refurbishment and restart at Bruce Power, development of new pipelines, including Keystone, construction of new power facilities, expansion of existing pipelines and maintenance and capacity projects in the Pipelines business. Expenditures in 2006 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 Ravenswood from National Grid plc on August 26, 2008 for US$2.9 billion, subject to certain post-closing adjustments.

In accordance with TCPL's agreement to increase its ownership interest in Keystone up to 79.99 per cent from 50 per cent, TCPL has funded $362 million of Keystone cash calls since September 30, 2008. This has resulted in an acquisition of an incremental 12 per cent ownership interest for $176 million, bringing TCPL's ownership interest to 62 per cent at December 31, 2008. The Keystone agreement is discussed further in the "Pipelines" section of this MD&A.

In 2007, TCPL acquired ANR and an additional 3.6 per cent interest in Great Lakes from El Paso Corporation for US$3.4 billion, including US$491 million of assumed long-term debt. PipeLines LP acquired the remaining 46.4 per cent of Great Lakes from El Paso Corporation for US$942 million, including US$209 million of assumed long-term debt. In 2007, PipeLines LP purchased Sierra Pacific Resources' remaining one per cent ownership interest in Tuscarora for approximately $2 million. In a separate transaction in 2007, 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.

In 2006, PipeLines LP acquired an additional 49 per cent interest in Tuscarora for US$100 million and also assumed 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.

Financing Activities

In 2008, TCPL issued Long-Term Debt of $2.2 billion and increased Notes Payable by $1.7 billion. Its proportionate share of Long-Term Debt issued by joint ventures was $173 million. Also in 2008, the Company reduced its Long-Term Debt by $840 million and its proportionate share of the Long-Term Debt of Joint Ventures by $120 million.

At December 31, 2008, total unsecured revolving and demand credit facilities of $4.2 billion were available to support the Company's commercial paper programs and for general corporate purposes. These credit facilities include the following:

•

a $2.0 billion committed, syndicated revolving credit facility, maturing December 2012.

46 MANAGEMENT'S DISCUSSION AND ANALYSIS

•

a US$300 million committed, syndicated revolving facility, maturing February 2013. This facility is part of the US$1.0 billion TransCanada PipeLine USA Ltd. credit facility discussed below under the heading "2007 Long-Term Debt Financing Activities".



•

a US$1.0 billion committed, extendible, expandable, unsecured bank facility, established in fourth quarter 2008, bearing interest at a floating rate plus a margin, with an initial term of 364 days and a one-year term renewal at the option of the borrower. The facility will support a new commercial paper program dedicated to funding a portion of expenditures for Keystone and for general partnership purposes.



•

demand lines totaling $0.6 billion, which support the issuance of letters of credit and provide additional liquidity. The Company had used approximately $433 million of these total lines of credit for letters of credit at December 31, 2008.

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, 2008, TransCanada had issued discount notes to TCPL for $1.5 billion (2007 – $1.2 billion). The notes bear interest at 2.1 per cent, mature in June 2009 and were used for general corporate purposes.

At December 31, 2007, TransCanada had issued two promissory notes to TCPL totalling $181 million. These notes were non-interest bearing and were repaid in December 2008. These notes were used for general corporate purposes.

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 US$370 million outstanding at December 31, 2007 was fully repaid on January 7, 2008.

TranCanada established a $2.5 billion, unsecured credit facility agreement with TCPL, bearing interest at the Reuters prime rate or Bankers' Acceptance rate plus 65 basis points, at TCPL's option. The funds advanced under this agreement can be used to repay indebtedness, make partner contributions to Bruce A, or for working capital and general corporate purposes. At December 31, 2008, $1.6 billion was outstanding under this credit facility (2007 – $1.3 billion). This credit agreement matures on December 15, 2009.

In May 2003, TCPL established a demand revolving credit facility with TransCanada for general corporate purposes at $500 million, or a U.S. dollar equivalent amount, bearing interest at the Royal Bank of Canada prime rate per annum or the U.S. base rate per annum. As at December 31, 2008, $200 million was outstanding on this facility (2007 – $207 million).

In 2008, Financial Charges included $76 million (2007 – $72 million) of interest expense and $55 million (2007 – $30 million) of interest income as a result of transactions with TransCanada. At December 31, 2008, Accounts Payable included $2 million of interest payable to TransCanada (2007 – $5 million).

Short-Term Debt Financing Activities

In June 2008, TCPL executed an agreement with a syndicate of banks for a US$1.5 billion committed, unsecured, one-year bridge loan facility, at a floating interest rate based on London Interbank Offered Rate (LIBOR) plus 30 basis points. The facility is extendible at the option of the Company for an additional six-month term at LIBOR plus 35 basis points. In August 2008, the Company used US$255 million from this facility to fund a portion of the Ravenswood acquisition and cancelled the remainder of the commitment. At December 31, 2008, the US$255 million remained outstanding on the facility.

2009 and 2008 Long-Term Debt Financing Activities

On February 17, 2009, the Company completed the issuance of Medium-Term Notes of $300 million and $400 million maturing in February 2014 and February 2039, respectively, and bearing interest at 5.05 per cent and 8.05 per cent,

MANAGEMENT'S DISCUSSION AND ANALYSIS 47

respectively. The proceeds are expected to be used to fund the Alberta System and Canadian Mainline rate bases. These notes were issued under a $1.5 billion debt shelf prospectus filed in Canada in March 2007.

On January 9, 2009, the Company issued Senior Unsecured Notes of US$750 million and US$1.25 billion maturing in January 2019 and January 2039, respectively, and bearing interest at 7.125 per cent and 7.625 per cent, respectively. The proceeds from these notes are expected to be used to partially fund TCPL's capital projects and retire mature debt obligations, and for general corporate purposes. These notes were issued under a US$3.0 billion debt shelf prospectus filed in January 2009. Following these issues, the Company has unutilized capacity of US$1.0 billion remaining under its January 2009 U.S. debt shelf prospectus.

In August 2008, TCPL issued $500 million of Medium-Term Notes maturing in August 2013 and bearing interest at 5.05 per cent. The proceeds from these notes were used to partially fund the Alberta System's capital program and for general corporate purposes. These notes were issued under the debt shelf prospectus filed in Canada in March 2007.

In August 2008, TCPL issued US$850 million and US$650 million of Senior Unsecured Notes maturing in August 2018 and August 2038, respectively, and bearing interest at 6.50 per cent and 7.25 per cent, respectively. The proceeds from these notes were used to partially fund the Ravenswood acquisition and for general corporate purposes. These notes were issued under the September 2007 debt shelf prospectus filed in the U.S. Following these issuances, the Company had fully utilized the capacity of its September 2007 U.S. debt shelf prospectus.

In June 2008, the Company retired $256 million of 5.84 per cent Medium-Term Notes and a $100 million 11.85 per cent debenture. In January 2008, the Company retired $105 million of 6.0 per cent Medium-Term Notes.

2007 Long-Term Debt 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.

In October 2007, TCPL issued US$1.0 billion of Senior Unsecured Notes under a US$2.5 billion debt shelf prospectus filed in the U.S. in September 2007. These notes mature on October 15, 2037 and bear interest at a rate of 6.20 per cent.

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 a 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, the Company 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 interest rate of three-month LIBOR plus 221 basis points. The Junior Subordinated Notes are subordinated to all existing and future senior indebtedness, are effectively subordinated to all indebtedness and obligations of the Company and are callable at the Company's option at any time on or after May 15, 2017 at the principal amount plus accrued and unpaid interest.

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, 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

48 MANAGEMENT'S DISCUSSION AND ANALYSIS

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. The revolving portion of the committed facility and the draw on the demand line were subsequently repaid. In 2008, the maturity date of the revolving portion of the facility was extended to February 2013.

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.

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.

2006 Long-Term Debt Financing Activities

In 2006, the Company issued Long-Term Debt of $2.1 billion and 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 Senior Unsecured Notes due 2036. In October 2006, TCPL issued $400 million of 4.65 per cent 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, 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.

2008 Equity Financing Activities

In 2008, TCPL issued 66.3 million common shares to TransCanada for proceeds of approximately $2.4 billion.

Commencing in 2007, TransCanada's Board of Directors authorized the issuance of common shares from treasury at a discount to participants in TransCanada's DRP. Under this plan, eligible TCPL preferred shareholders may reinvest their dividends and make optional cash payments to obtain additional TransCanada common shares. The DRP shares are provided to the participants at a discount to the average market price in the five days before dividend payment. The discount was set at two per cent commencing with the dividend payable in April 2007 and was increased to three per cent for the dividend payable in January 2009. Prior to the April 2007 dividend, 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.

2007 Equity Financing Activities

In 2007, TCPL issued 48.2 million common shares to TransCanada for proceeds of approximately $1.8 billion. The proceeds were used towards financing the acquisition of ANR and Great Lakes.

In February 2007, PipeLines LP completed a private placement offering of 17.4 million common units at a purchase price of US$34.57 per unit. TCPL acquired 50 per cent of the units for US$300 million and invested an additional US$12 million to maintain its general partnership ownership interest in PipeLines LP. The total private placement plus TCPL's additional investment resulted in gross proceeds to PipeLines LP of US$612 million, which were used to partially finance its Great Lakes acquisition.

MANAGEMENT'S DISCUSSION AND ANALYSIS 49

Dividends

Cash dividends on common and preferred shares amounting to $817 million were paid in 2008 compared to $725 million in 2007 and $639 million in 2006. The increase in dividends in 2008 compared to 2007 was primarily due to a greater number of shares outstanding.

On February 2, 2009, TCPL's Board of Directors declared a dividend for the quarter ending March 31, 2009 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, 2009. 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 Baa1 with a stable outlook. TCPL's senior unsecured debt is rated A with a stable outlook by DBRS, A3 with a stable outlook by Moody's, and A- with a stable outlook by Standard and Poor's.

CONTRACTUAL OBLIGATIONS

Obligations and Commitments

At December 31, 2008, the Company had $16.2 billion of total Long-Term Debt and $1.2 billion of Junior Subordinated Notes, compared to $12.9 billion of total Long-Term Debt and $1.0 billion of Junior Subordinated Notes at December 31, 2007. TCPL's share of the total debt of joint ventures, including capital lease obligations, was $1.1 billion at December 31, 2008, compared to $903 million at December 31, 2007. Total amounts due to TransCanada were $1.8 billion at December 31, 2008 compared to $1.9 billion at December 31, 2007. Total Notes Payable, including TCPL's proportionate share of the notes payable of joint ventures, were $1.7 billion at December 31, 2008, compared to $55 million at December 31, 2007. 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
Due to TransCanada Corporation	1,821	1,821	–	–	–
Long-term debt(1)	18,208	980	1,787	2,684	12,757
Capital lease obligations	235	13	25	38	159
Operating leases(2)	403	28	56	66	253
Purchase obligations	12,246	3,926	2,595	1,761	3,964
Other long-term liabilities reflected on the balance sheet	610	12	29	34	535
Total contractual obligations	33,523	6,780	4,492	4,583	17,668

⁽¹⁾

Includes Junior Subordinated Notes.

⁽²⁾

Represents future annual payments, net of sub-lease receipts, for various premises, services and equipment. The operating lease agreements for premises, services and equipment expire at various dates through 2035, with an option to renew certain lease agreements for one to ten years.

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 factors. The amount of power purchased under the PPAs in 2008 was $471 million (2007 – $440 million; 2006 – $499 million).

50 MANAGEMENT'S DISCUSSION AND ANALYSIS

At December 31, 2008, scheduled principal repayments and interest payments related to amounts due to TransCanada Corporation, long-term debt and the Company's proportionate share of the long-term debt of joint ventures were as follows:

PRINCIPAL REPAYMENTS
Year ended December 31 (millions of dollars)

		Payments Due by Period
	Total	Less than one year	1 - 3 years	3 - 5 years	More than 5 years
Due to TransCanada Corporation	1,821	1,821	–	–	–
Long-term debt(1)	16,154	786	1,545	2,550	11,273
Junior subordinated notes	1,213	–	–	–	1,213
Long-term debt of joint ventures	841	194	242	134	271
Total principal repayments	20,029	2,801	1,787	2,684	12,757

⁽¹⁾

Includes Junior Subordinated Notes.

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 amounts due to TransCanada Corporation	92	92	–	–	–
Interest payments on long-term debt	14,508	1,072	1,995	1,794	9,647
Interest payments on junior subordinated notes	662	78	156	156	272
Interest payments on long-term debt of joint ventures	328	61	76	56	135
Total interest payments	15,590	1,303	2,227	2,006	10,054

MANAGEMENT'S DISCUSSION AND ANALYSIS 51

At December 31, 2008, the Company's approximate future purchase obligations were as follows:

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

		Payments Due by Period
	Total	Less than one year	1 - 3 years	3 - 5 years	More than 5 years
Pipelines
Transportation by others(2)	931	260	396	199	76
Capital expenditures(3)(4)	2,317	2,092	155	70	–
Other	6	3	2	1	–
Energy
Commodity purchases(5)	6,711	945	1,394	1,284	3,088
Capital expenditures(3)(6)	1,049	509	456	61	23
Other(7)	1,133	88	151	124	770
Corporate
Information technology and other	99	29	41	22	7
Total purchase obligations	12,246	3,926	2,595	1,761	3,964

⁽¹⁾

The amounts in this table exclude funding contributions to pension plans and funding to the APG.

⁽²⁾

Rates are based on known 2009 levels. Beyond 2009, 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 capital projects with cash from operations and, if necessary, new debt and equity.

⁽⁴⁾

Primarily consists of capital expenditures related to TCPL's share of the construction costs of Keystone, North Central Corridor 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 of Coolidge, Bruce Power, the remaining Cartier Wind projects, Halton Hills and Portlands Energy.

⁽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 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.

In 2009, TCPL expects to make funding contributions to the Company's pension and other post-retirement benefit plans in the amount of approximately $140 million and $27 million, respectively. This represents an increase from total funding contributions of $90 million in 2008 and is attributable primarily to significantly reduced investment performance and plan experience being different than expectations. TCPL's proportionate share of funding contributions expected to be made by joint ventures to their respective pension and other post-retirement benefit plans in 2009 is approximately $37 million and $4 million, respectively, compared to actual total contributions of $42 million in 2008.

The next actuarial valuation for the Company's pension and other post-retirement benefit plans is expected to be carried out as at January 1, 2010. Primarily as a result of the significantly lower performance of the pension plan assets in 2008, it is expected that funding requirements for these plans could continue at the anticipated 2009 level for the next several years to amortize solvency deficiencies in addition to normal costs. The Company's net benefit cost is expected to remain at 2008 levels. However, the net benefit cost and the amount of funding contributions received will be

52 MANAGEMENT'S DISCUSSION AND ANALYSIS

dependent on various factors, including future investment returns achieved on plan assets, the level of interest rates, changes to plan design and actuarial assumptions, actual plan experience versus projections and amendments to pension plan regulations and legislation. Increases in the level of required plan funding are not expected to have a material impact on the Company's liquidity.

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 three-year period ending December 31, 2011, are as follows:

Year ended December 31 (millions of dollars)

2009	204
2010	49
2011	2
	255

Aboriginal Pipeline Group

Under its agreement with the APG, TCPL agreed to finance the APG's one-third share of the MGP project's predevelopment costs. These costs are currently forecast to be between $150 million and $200 million, on a cumulative basis, depending on the pace of project development. As at December 31, 2008, the Company had advanced $140 million of this total. This agreement is discussed further in the "Pipelines – Opportunities and Developments" section of this MD&A.

Contingencies

In April 2008, the Ontario Court of Appeal dismissed an appeal filed by the Canadian Alliance of Pipeline Landowners' Associations (CAPLA). CAPLA filed the appeal as a result of a decision by the Ontario Superior Court in November 2006 to dismiss CAPLA's class action lawsuit against TCPL and Enbridge Inc. for damages 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. The Ontario Court of Appeal's decision is final and binding as CAPLA did not seek any further appeal within the time frame allowed.

TCPL is subject to laws and regulations governing environmental quality and pollution control. At December 31, 2008, the Company had recorded liabilities of approximately $86 million representing the Company's estimate of the amount it expects to expend to remediate certain sites. However, additional liabilities may be incurred as more assessments occur and remediation efforts continue.

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 have 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 2010 to perpetuity. In addition, TCPL and BPC have 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 provided as part of the reorganization of Bruce Power in 2005 and have terms ending in 2019. TCPL's share of the potential exposure under these Bruce A and Bruce B guarantees was estimated at December 31, 2008 to range from $711 million to a maximum of $750 million. The fair value of these guarantees is estimated to be $17 million.

MANAGEMENT'S DISCUSSION AND ANALYSIS 53

The Company and its partners in certain jointly owned entities have severally as well as jointly and severally guaranteed the financial 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, 2008 to range from $688 million to a maximum of $1.4 billion. 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 $9 million for the fair value of these joint and several guarantees.

TCPL has guaranteed a subsidiary's equity undertaking to support the payment, under certain conditions, of principal and interest on US$43 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 would 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 AND FINANCIAL INSTRUMENTS

Risk Management Overview

TCPL has exposure to market risk, counterparty credit risk, and liquidity risk. TCPL engages in risk management activities with the primary objective being to protect earnings, 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 and internal audit personnel. The Board of Directors' Audit Committee oversees how management monitors compliance with risk management policies and procedures, and oversees 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. The Board of Directors also has a Governance Committee that assists in overseeing the risk management activities of TCPL. The Governance Committee monitors, reviews with management and makes recommendations related to TCPL's risk management programs and policies on an ongoing basis.

Market Risk

The Company constructs and invests in large infrastructure projects, purchases and sells commodities, issues short-term 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 exposure to market risk that results from these activities. Derivative 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.

54 MANAGEMENT'S DISCUSSION AND ANALYSIS

•

Options – contractual agreements to convey the right, but not the obligation, of 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.

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 electricity, natural gas and oil products. A number of strategies are used to mitigate these exposures, including the following:

•

Subject to the Company's overall risk management policies, the Company commits a significant portion of its expected power supply to fixed-price medium-term or long-term sales contracts, while reserving an amount of unsold supply to mitigate price risk in its asset portfolio.

•

The Company purchases a portion of the natural gas and oil products required for its power plants or enters into 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 sales commitments is purchased with contracts or fulfilled through power generation, thereby reducing the Company's exposure to fluctuating commodity prices.

•

The Company enters into offsetting or back-to-back positions and derivative financial instruments to manage price risk exposure in power and natural gas commodities created by certain fixed and variable pricing arrangements for different pricing indices and delivery points.

TCPL manages its exposure to seasonal natural gas price spreads in its natural gas storage business by economically hedging storage capacity with a portfolio of third-party storage capacity contracts and proprietary natural gas purchases and sales. TCPL simultaneously enters into a forward purchase of natural gas for injection into storage and an offsetting forward sale of natural gas for withdrawal at a later period, thereby locking in future positive margins and effectively eliminating exposure to price movements of natural gas. Fair value adjustments recorded each period on proprietary natural gas storage inventory and these forward contracts may not be representative of the amounts that will be realized on settlement.

Natural Gas Inventory Price Risk

At December 31, 2008, $76 million (2007 – $190 million) of proprietary natural gas inventory was included in Inventories. TCPL measures its proprietary natural gas inventory held in storage at the one-month forward price for natural gas less selling costs. The Company did not have any proprietary natural gas inventory held in storage prior to April 2007. In 2008, the net change in fair value of proprietary natural gas held in inventory was a net unrealized loss of $7 million (2007 – nil), which was recorded as a decrease to Revenue and Inventory. In 2008, the net change in fair value of natural gas forward purchases and sales contracts was a net unrealized gain of $7 million (2007 – $10 million) which was included in Revenues.

Foreign Exchange and Interest Rate Risk

Foreign exchange and interest rate risk is created by fluctuations in the fair value or cash flow of financial instruments due to changes in foreign exchange rates and/or market interest rates.

A portion of TCPL's earnings from its Pipelines and Energy operations is generated in U.S. dollars and is subject to currency fluctuations. The performance of the Canadian dollar relative to the U.S. dollar can affect TCPL's earnings. This foreign exchange impact is offset by certain related debt and financing costs being denominated in U.S. dollars and by the Company's hedging activities. Due to its increased U.S. operations, TCPL has a greater exposure to U.S. currency 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 debt and other U.S. dollar-denominated transactions, and to manage the interest rate exposure of the Canadian Mainline, Alberta System and Foothills operations. Certain of the realized gains and losses on these derivatives

MANAGEMENT'S DISCUSSION AND ANALYSIS 55

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.

TCPL 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 this risk.

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 foreign exchange contracts, cross-currency interest rate swaps and foreign exchange options. At December 31, 2008, the Company had designated as a net investment hedge U.S. dollar-denominated debt with a carrying value of $7.2 billion (US$5.9 billion) (2007 – $4.3 billion (US$4.4 billion)) and a fair value of $5.9 billion (US$4.8 billion) (2007 – $4.4 billion (US$4.5 billion)). In January 2009, the Company issued an additional US$2.0 billion of long-term debt and designated it as a hedge of the net U.S. dollar investment in foreign operations. At December 31, 2008, $254 million was included in Deferred Amounts for the fair value of the forwards, swaps and options used to hedge the Company's net U.S. dollar investment in foreign operations.

The fair values and notional or principal amount for the derivatives designated as a net investment hedge were as follows:

		2008			2007
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)	(218	)	U.S. 1,650	77		U.S. 350
U.S. dollar forward foreign exchange contracts
	(maturing 2009)	(42	)	U.S. 2,152	(4	)	U.S. 150
U.S. dollar options
	(maturing 2009)	6		U.S. 300	3		U.S. 600
		(254	)	U.S. 4,102	76		U.S. 1,100

Counterparty Credit Risk

Counterparty credit risk represents the financial loss the Company would experience if a counterparty to a financial instrument failed to meet its obligations in accordance with the terms and conditions of its contracts with the Company.

Counterparty credit risk is managed 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, using 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. The Company believes these measures minimize its counterparty credit risk but there is no certainty that these processes will protect it against all losses.

TCPL has significant credit and performance exposures to financial institutions as they provide committed credit lines and cash deposit facilities, critical liquidity in the foreign exchange derivative, interest rate derivative and energy wholesale markets, and letters of credit to mitigate TCPL's exposure to non-credit worthy counterparties.

During the deterioration of global financial markets in 2008, TCPL continued to closely monitor and reassess the creditworthiness of its counterparties, including financial institutions. This has resulted in TCPL reducing or mitigating its

56 MANAGEMENT'S DISCUSSION AND ANALYSIS

exposure to certain counterparties where it is deemed warranted and permitted under contractual terms. As part of its ongoing operations, TCPL must balance its market risk and counterparty credit risk when making business decisions.

Certain subsidiaries of Calpine filed for bankruptcy protection in both Canada and the U.S. in 2005. Gas Transmission Northwest Corporation (GTNC) and Portland Natural Gas Transmission System (PNGTS) reached agreements with Calpine for allowed unsecured claims in the Calpine bankruptcy. In February 2008, GTNC and PNGTS received initial distributions of 9.4 million common shares and 6.1 million common shares of Calpine, respectively, which represented approximately 85 per cent of their agreed-upon claims. In 2008, these shares were subsequently sold into the open market and resulted in total pre-tax gains of $279 million. Claims by NOVA Gas Transmission Limited and Foothills Pipe Lines (South B.C.) Ltd. for $32 million and $44 million, respectively, were received in cash in January 2008 and will be passed on to shippers on these systems. At December 31, 2008, $22 million remained in regulatory liabilities for these claims.

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, under both normal and stressed conditions, it always has sufficient cash and credit facilities to meet its obligations when due without incurring unacceptable losses or damage to the Company's reputation.

Management forecasts cash flows for a period of 12 months to identify financing requirements. These requirements are then managed through a combination of committed and demand credit facilities and access to capital markets. The Company's liquidity and cash flow management is also discussed in the "Liquidity and Capital Resources" and "Contractual Obligations" sections of this MD&A.

Fair Values

The fair value of financial instruments included in Cash and Cash Equivalents, Accounts Receivable, Other Assets, Notes Payable, Accounts Payable, Accrued Interest and Deferred Amounts approximates their carrying amounts due to the nature of the item and/or the short time 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 oil products derivatives has been calculated using quoted market prices where available. In the absence of quoted market prices, third-party broker quotes are used. Credit risk has been taken into consideration when calculating fair values.

Valuation techniques that refer to observable market data or estimated market prices may also be used to calculate fair value. 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, was estimated by discounting future payments of interest and principal at estimated interest rates that were made available to the Company.

MANAGEMENT'S DISCUSSION AND ANALYSIS 57

Non-Derivative Financial Instruments Summary

The carrying and fair values of non-derivative financial instruments were as follows:

	2008		2007
December 31 (millions of dollars)	Carrying Amount	Fair Value	Carrying Amount	Fair Value
Financial Assets(1)
Cash and cash equivalents	1,300	1,300	504	504
Accounts receivable and other assets(2)(3)	1,404	1,404	1,231	1,231
Due from TransCanada Corporation	1,529	1,529	1,407	1,407
Available-for-sale assets(2)	27	27	17	17
	4,260	4,260	3,159	3,159
Financial Liabilities(1)(3)
Notes payable	1,702	1,702	55	55
Accounts payable and deferred amounts(4)	1,364	1,364	1,192	1,192
Accrued interest	361	361	265	265
Due to TransCanada Corporation	1,821	1,821	1,879	1,879
Long-term debt and junior subordinated notes	17,367	16,152	13,908	15,334
Long-term debt of joint ventures	1,076	1,052	903	937
Other long-term liabilities of joint ventures(4)	–	–	60	60
	23,691	22,452	18,262	19,722

⁽¹⁾

Consolidated Net Income in 2008 and 2007 included unrealized gains or losses of nil for the fair value adjustments to each of these financial instruments.

⁽²⁾

At December 31, 2008, the Consolidated Balance Sheet included financial assets of $1,257 million (2007 – $1,018 million) in Accounts Receivable and $174 million (2007 – $230 million) in Other Assets.

⁽³⁾

Recorded at amortized cost, except for certain Long-Term Debt which is adjusted to fair value.

⁽⁴⁾

At December 31, 2008, the Consolidated Balance Sheet included financial liabilities of $1,342 million (2007 – $1,174 million) in Accounts Payable and $22 million (2007 – $78 million) in Deferred Amounts.

58 MANAGEMENT'S DISCUSSION AND ANALYSIS

Derivative Financial Instruments Summary

Information for the Company's derivative financial instruments is as follows:

			2008
December 31 (all amounts in millions unless otherwise indicated)			Power		Natural Gas		Oil Products		Foreign Exchange		Interest
Derivative Financial Instruments Held for Trading
Fair Values(1)
	Assets		$132		$144		$10		$41		$57
	Liabilities		$(82	)	$(150	)	$(10	)	$(55	)	$(117	)
Notional Values
	Volumes(2)
		Purchases	4,035		172		410		–		–
		Sales	5,491		162		252		–		–
	Canadian dollars		–		–		–		–		1,016
	U.S. dollars		–		–		–		U.S. 479		U.S. 1,575
	Japanese yen (in billions)		–		–		–		JPY 4.3		–
	Cross-currency		–		–		–		227/U.S. 157		–
Net unrealized gains/(losses) in the year(3)			$24		$(23	)	$1		$(9	)	$(61	)
Net realized gains/(losses) in the year(3)			$23		$(2	)	$1		$6		$13
Maturity dates			2009 - 2014		2009 - 2011		2009		2009 - 2012		2009 - 2018
Derivative Financial Instruments in Hedging Relationships(4)(5)
Fair Values(1)
	Assets		$115		$–		$–		$2		$8
	Liabilities		$(160	)	$(18	)	$–		$(24	)	$(122	)
Notional Values
	Volumes(2)
		Purchases	8,926		9		–		–		–
		Sales	13,113		–		–		–		–
	Canadian dollars		–		–		–		–		50
	U.S. dollars		–		–		–		U.S. 15		U.S. 1,475
	Cross-currency		–		–		–		136/U.S. 100		–
Net realized (losses)/gains in the year(3)			$(56	)	$15		$–		$–		$(10	)
Maturity dates			2009 - 2014		2009 - 2011		–		2009 - 2013		2009 - 2019

⁽¹⁾

Fair value is equal to the carrying value of these derivatives.

⁽²⁾

Volumes for power, natural gas and oil products derivatives are in gigawatt hours, billion cubic feet and thousands of barrels, respectively.

⁽³⁾

All power, natural gas and oil products realized and unrealized gains and losses are included in Revenues. All interest rate and foreign exchange realized and unrealized gains and losses are included in Financial Charges and Interest Income and Other, respectively. Realized gains and losses are included in Net Income upon settlement of the financial instrument.

⁽⁴⁾

All hedging relationships are designated as cash flow hedges except for interest-rate derivative financial instruments designated as fair value hedges with a fair value of $8 million. In 2008, the Company did not record any amounts in Net Income related to ineffectiveness for fair value hedges.

MANAGEMENT'S DISCUSSION AND ANALYSIS 59

⁽⁵⁾

In 2008, Net Income included losses of $6 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. In 2008, there were no gains or losses included in Net Income for discontinued cash flow hedges.

The anticipated timing of settlement of the derivative contracts assumes no changes in commodity prices, interest rates and foreign exchange rates from December 31, 2008. Actual settlements will vary based on changes in these factors. The anticipated timing of settlement of these contracts is as follows:

(millions of dollars)	Total		2009		2010 and 2011		2012 and 2013		2014 and Thereafter
Derivative financial instruments held for trading	(30	)	38		(46	)	(14	)	(8	)
Derivative financial instruments in hedging relationships	(199	)	(68	)	(65	)	(43	)	(23	)
	(229	)	(30	)	(111	)	(57	)	(31	)

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		–
Net unrealized gains/(losses) in the year(3)			$16		$(10	)	$8		$(5	)
Net realized (losses)/gains in the year(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		–
Net realized (losses)/gains in the year(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.

60 MANAGEMENT'S DISCUSSION AND ANALYSIS

⁽²⁾

Volumes for power and natural gas derivatives are in gigawatt hours and billion cubic feet, respectively.

⁽³⁾

All power and natural gas realized and unrealized gains and losses are included in Revenues. All interest rate and foreign exchange realized and unrealized gains and losses are included in Financial Charges and Interest Income and Other, respectively. Realized gains and losses are included in Net Income upon settlement of the financial instrument.

⁽⁴⁾

All hedging relationships are designated as cash flow hedges except for interest rate derivative financial instruments designated as fair value hedges with a fair value of $2 million. In 2007, the Company did not record any amounts in Net Income related to ineffectiveness for fair value hedges.

⁽⁵⁾

In 2007, Net Income 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. In 2007, Net Income 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 when the anticipated transaction was not likely to occur by the end of the originally specified time period.

Balance Sheet Presentation of Derivative Financial Instruments

The fair value of the derivative financial instruments in the Company's Balance Sheet was as follows:

December 31 (millions of dollars)		2008		2007
Current
	Other current assets	318		160
	Accounts payable	(298	)	(144	)
Long-term
	Other assets	191		204
	Deferred amounts	(694	)	(205	)

OTHER RISKS

Development Projects and Acquisitions

TCPL continues to focus on growing its Pipelines and Energy operations through greenfield development projects and acquisitions. TCPL capitalizes costs incurred on certain of its projects during the development 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 assets and operations that certain commercial opportunities and operational synergies may not materialize as expected and would subsequently be subject to an impairment writedown.

Health, Safety and Environment Risk Management

Health, safety and environment (HS&E) is a priority in all of TCPL's operations and is guided by the Company's HS&E Commitment Statement. The Commitment Statement outlines guiding principles for a safe and healthy environment for TCPL's employees, contractors and the public, and that strive to protect the environment. All employees are held responsible and accountable for HS&E performance. The Company is committed to being an industry leader in conducting its business so that it meets or exceeds all applicable laws and regulations, and minimizes risk to people and the environment. The Company is committed to tracking and improving its HS&E performance, and to promoting safety on and off the job in the belief that all occupational injuries and illnesses are preventable. TCPL endeavours to do business with companies and contractors that share its perspective on HS&E performance and to influence them to improve their collective performance. TCPL is committed to respecting the diverse environments and cultures in which it operates and to supporting open communication with the public, policy makers, scientists and public interest groups with whom it shares stewardship of the world it inhabits.

TCPL is committed to ensuring compliance with its internal policies and regulated requirements. The HS&E Committee of TCPL's Board of Directors monitors compliance with the Company's HS&E corporate policy through regular reporting. TCPL's HS&E management system is modeled on the International Organization of Standardization's (ISO) standard for

MANAGEMENT'S DISCUSSION AND ANALYSIS 61

environmental management systems, ISO 14001, and focuses resources on the areas of significant risk to the organization's HS&E business activities. Management is informed regularly of all important HS&E operational issues and initiatives through formal reporting processes. TCPL's HS&E management system and performance are assessed by an independent outside firm every three years. The most recent assessment occurred in November 2006. The HS&E management system also is subject to ongoing internal review to ensure that it remains effective as circumstances change.

In 2008, employee and contractor health and safety performance continued to be a top priority. TCPL's assets were highly reliable and there were no incidents that were material to TCPL's operations.

The safety and integrity of the Company's pipelines is a top priority. The Company expects to spend approximately $185 million in 2009 for pipeline integrity on its wholly owned pipelines, which is higher than the amount spent in 2008 primarily due to increased levels of in-line pipeline inspection on all systems. 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. Expenditures on the GTN System are also recovered through a cost recovery mechanism in its rates. Pipeline safety in 2008 continued to be very good, as TCPL experienced only one small-diameter pipeline failure in a remote part of east central Alberta. The break resulted in minimal impact with no injuries or property damage. Spending associated with public safety on the Energy assets is focused primarily on the Company's hydro dams and associated equipment, and is consistent with previous years.

Environment

TCPL's facilities are subject to various federal, provincial, state and local statutes and regulations, including requirements to establish compliance and remediation obligations. Compliance obligations can result in significant costs associated with installing and maintaining pollution controls, fines and penalties resulting from any failure to comply, and potential limitations on operations. Remediation obligations can result in significant costs associated with the investigation and remediation of contaminated properties, some of which have been designated as Superfund sites by the U.S. Environmental Protection Agency under the Comprehensive Environmental Response, Compensation and Liability Act, and with damage claims arising out of the contamination of properties or impact on natural resources. It is not possible for the Company to estimate exactly the amount and timing of all future expenditures related to environmental matters due to:

•

uncertainties in estimating pollution control and clean-up costs, including sites where only preliminary site investigation or agreements have been completed;

•

the potential discovery of new sites or additional information at existing sites;

•

the uncertainty in quantifying liability under environmental laws that impose joint and several liability on all potentially responsible parties;

•

the evolving nature of environmental laws and regulations, including the interpretation and enforcement thereof; and

•

the potential for litigation on existing or discontinued assets.

Environmental risks from TCPL's operating facilities typically include: air emissions, such as nitrogen oxides, particulate matter and greenhouse gases; potential impacts on land, including land reclamation or restoration following construction; the use, storage or release of chemicals or hydrocarbons; the generation, handling and disposal of wastes and hazardous wastes; and water impacts such as uncontrolled water discharge. Environmental controls including physical design, programs, procedures and processes are in place to effectively manage these risks. TCPL has ongoing inspection programs designed to keep all of its facilities in compliance with environmental requirements and the Company is confident that its systems are in material compliance with the applicable requirements.

In 2008, TCPL conducted environmental risk assessments and remediation work, resulting in total costs of approximately $7 million and US$6 million for work conducted on TCPL's Canadian and U.S. facilities, respectively. TCPL also conducted various retirement, reclamation and restoration work in 2008, which resulted in total costs of approximately $7 million. At December 31, 2008, TCPL had recorded liabilities of approximately $86 million for compliance and remediation obligations. The Company believes it has considered all necessary contingencies and established appropriate reserves for environmental liabilities, however, there is the risk that unforeseen matters may arise requiring the Company to set aside additional amounts.

62 MANAGEMENT'S DISCUSSION AND ANALYSIS

TCPL is not aware of any material outstanding orders, 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.

North American climate change policy continues to evolve at regional and national levels. While recent political and economic events may significantly affect the scope and timing of new measures that are put in place, TCPL anticipates that most of the company's facilities in Canada and the U.S. will be captured under future regional and/or federal climate change regulations to manage industrial greenhouse gas (GHG) emissions.

In 2008, the Company owned assets in three regions affected by climate change policy measures related to industrial emissions. In Alberta, the Specified Gas Emitters Regulation, which came into effect in 2007, requires industrial facilities to reduce GHG emissions intensities by 12 per cent. TCPL's Alberta-based pipeline and power facilities are subject to this regulation, as are the Sundance and Sheerness coal-fired power facilities with which TCPL has commercial arrangements. The Company's total cost of compliance incurred by the Alberta-based facilities for the period from July 2007 to December 2007 was approximately $12 million. Costs for 2008 compliance are estimated to be $28 million and will be finalized when compliance reports are submitted in March 2009. Compliance costs of the Alberta System are recovered through tolls paid by customers. Recovery of compliance costs for the Company's power generation facilities and interests in Alberta is partially achieved through contracts and the impact of increased operating costs on Alberta power market prices.

The hydrocarbon royalty in Québec is collected by the natural gas distributor on behalf of the Québec government via a green fund contribution charge on gas consumed. In 2008, the cost pertaining to the Bécancour facility arising from the hydrocarbon royalty was less than $1 million as a result of an agreement between TCPL and Hydro-Québec to temporarily suspend the facility's power generation. The cost is expected to increase when the plant returns to service in 2010.

B.C.'s carbon tax, which came into effect in mid-2008, applies to carbon dioxide (CO₂) emissions arising from fossil fuel combustion. Compliance costs for fuel combustion at the Company's compressor and meter stations in B.C. are recovered through tolls paid by customers. Costs related to the carbon tax for 2008 were $1 million. This cost is expected to increase over the next four years as the tax charge per tonne of CO₂ increases by $5 per tonne annually from the initial tax rate of $10 per tonne.

TCPL has assets located in Ontario and Manitoba, where the provincial governments have announced climate change strategies that will impact industrial sources of GHG emissions. The details of these programs and how they will align with the Canadian government's climate change policies are still uncertain.

The Canadian government has expressed interest in pursuing the development of a North American cap and trade system for GHG emissions. In April 2007, the Government of Canada released the Regulatory Framework for Air Emissions (Framework). The Framework outlines short-, medium- and long-term objectives for managing both GHG emissions and air pollutants in Canada. TCPL 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 not known at this time whether the impacts from the pending regulations will be material as the draft regulations have not yet been released. It is uncertain how the Framework will fit within a North American cap and trade system and what the specific requirements for industrial emitters will be.

Climate change is a strategic issue for the new U.S. government administration and federal policy to manage domestic GHG emissions is expected to be a priority. Seven western states and four Canadian provinces are focused on the implementation of a cap and trade program under the Western Climate Initiative (WCI). Northeastern states that are members of the Regional Greenhouse Gas Initiative (RGGI) implemented a CO₂ cap and trade program for electricity generators effective January 1, 2009. Participants in the Midwestern Greenhouse Gas Reduction Accord, which involves six states and one province, are developing a regional strategy for reducing members' GHG emissions that will include a multi-sector cap and trade mechanism.

MANAGEMENT'S DISCUSSION AND ANALYSIS 63

The Company anticipates a number of its facilities will be affected by these legislative initiatives. Under the RGGI, both the Ravenswood and OSP facilities will be required to submit allowances by December 31, 2011. It is expected that the costs will be recovered from the market and the net impact to TCPL will be minimal. Company assets located in regions affected by the WCI and Midwestern Greenhouse Gas Reduction Accord and in California are most likely to be covered by GHG reduction measures put in place, however, the level of impact is uncertain as key policy details remain outstanding.

TCPL monitors climate change policy developments and, when warranted, participates in policy discussions in jurisdictions where the Company has operations. The Company is also continuing its programs to manage GHG emissions from its facilities and to evaluate new processes and technologies that result in improved efficiencies and lower GHG emission rates.

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, 2008, an evaluation 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 was carried out under the supervision and with the participation of management, including the President and Chief Executive Officer and the Chief Financial Officer. 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, 2008.

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. The Company acquired Ravenswood in August 2008 and began consolidating the operations of Ravenswood from that date. Management has excluded this business from its evaluation of the effectiveness of the Company's internal control over financial reporting as of December 31, 2008. The net income attributable to this business represented less than one per cent of the Company's consolidated net income for the year ended December 31, 2008, and its aggregate total assets represented approximately nine per cent of the Company's consolidated total assets as at December 31, 2008.

Based on this evaluation, management concluded that internal control over financial reporting is effective as at December 31, 2008, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes.

64 MANAGEMENT'S DISCUSSION AND ANALYSIS

In 2008, 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 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 2008 reports filed with the SEC and the Canadian securities regulators.

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. The Company believes the following accounting policies and estimates require it to make assumptions about highly uncertain matters and changes in these estimates could have a material impact to the Company's financial information.

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 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 the timing of recognition of certain expenses and revenues in the regulated businesses may differ from that otherwise expected under GAAP in order to appropriately reflect the economic impact of the regulators' decisions regarding the Company's revenues and tolls.

Effective January 1, 2009, the Company's accounting for its future income taxes recorded on rate-regulated operations will change as discussed in the "Accounting Changes" section of this MD&A.

Financial Instruments and Hedges

Financial Instruments

Effective January 1, 2007, the Company adopted the accounting requirements for the Canadian Institute of Chartered Accountants (CICA) Handbook Sections 1530 "Comprehensive Income", 3855 "Financial Instruments – Recognition and Measurement", and 3865 "Hedges". Effective December 31, 2007, the Company adopted the accounting requirements for CICA Handbook Sections 3862 "Financial Instruments – Disclosure", 3863 "Financial Instruments – Presentation", and 1535 "Capital Disclosures". Adjustments to the consolidated financial statements for 2007 were made on a prospective basis.

The CICA Handbook requires that all financial instruments 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. The Company does not have any held-to-maturity investments.

Held-for-trading derivative financial assets and liabilities consist of swaps, options, forwards and futures. Commodity held-for-trading financial instruments are initially recorded at their fair value and changes to fair value are included in

MANAGEMENT'S DISCUSSION AND ANALYSIS 65

Revenues. Changes in the fair value of interest rate and foreign exchange rate held-for-trading instruments are recorded in Financial Charges and in Interest Income and Other, respectively.

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. These instruments are accounted for initially at their fair value and changes to fair value are recorded through Other Comprehensive Income. 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 at amortized cost using the effective interest method, net of any impairment. Other financial liabilities consist of liabilities not classified as held for trading. Items in this financial instrument category are recognized at amortized cost using the effective interest method.

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.

Hedges

The CICA Handbook 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 hedging relationship ceases to be effective or the hedging or hedged items cease to exist as a result of maturity, expiry, sale, termination, cancellation or exercise.

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 are also recorded in Net Income.

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 from Accumulated Other Comprehensive 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 reclassified to Net Income in the event the Company settles or otherwise reduces its investment in a foreign operation.

The fair value of financial instruments and hedges is primarily derived from market values adjusted for credit risk, which can fluctuate greatly from period to period. These changes in fair value can result in variability in net income as a result of recording these changes in fair value through earnings. The risks associated with fluctuations to earnings and cash flows for financial instruments and hedges are discussed further in the "Risk Management and Financial Instruments" section of this MD&A.

66 MANAGEMENT'S DISCUSSION AND ANALYSIS

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 one per cent to 25 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 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 and the remaining lease term. 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 per cent to 20 per cent.

Depreciation expense in 2008 was $1,189 million (2007 – $1,179 million) and is recorded in Pipelines and Energy. In Pipelines, depreciation rates are approved by regulators when 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 will have no material impact on TCPL's net income but will directly affect funds generated from operations.

Impairment of Long-Lived Assets and Goodwill

The Company reviews long-lived assets such as property, plant and equipment, and intangible assets for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows is less than the carrying value of the assets, an impairment loss is recognized for the excess of the carrying value over the fair value of the assets.

Goodwill is tested in the Pipelines and Energy segments for impairment annually or more frequently if events or changes in circumstances indicate that the asset might be impaired. An initial assessment is made by comparing the fair value of the operations, which includes goodwill, to the book values of each reporting unit. If this fair value is less than book value, an impairment is indicated and a second test is performed to measure the amount of the impairment. In the second test, the implied fair value of the goodwill is calculated by deducting the fair value of all tangible and intangible net assets of the reporting unit from the fair value determined in the initial assessment. If the carrying value of the goodwill exceeds this calculated implied fair value of the goodwill, an impairment charge is recorded.

These valuations are based on management's projections of future cash flows and, therefore, require estimates and assumptions with respect to:

•

discount rates;

•

commodity prices;

•

market supply and demand assumptions;

•

growth opportunities;

•

output levels;

•

competition from other companies; and

•

regulatory changes.

Significant changes in these assumptions could affect the Company's need to record an impairment charge.

MANAGEMENT'S DISCUSSION AND ANALYSIS 67

ACCOUNTING CHANGES

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, was withdrawn. In addition, Section 3465 "Income Taxes" was amended to require the recognition of future income tax assets and liabilities for rate-regulated entities. The Company has chosen to adopt accounting policies consistent with the U.S. Financial Accounting Standards Board's Financial Accounting Standard (FAS) 71 "Accounting for the Effects of Certain Types of Regulation". Accordingly, TCPL will retain its current method of accounting for its rate-regulated operations, except that TCPL will be required to recognize future income tax assets and liabilities instead of using the taxes payable method, and will record an offsetting adjustment to regulatory assets and liabilities. If the Company had adopted FAS 71 at December 31, 2008, additional future income tax liabilities and a regulatory asset in the amount of $1,434 million would have been recorded and would have been recoverable from future revenue. These changes will be applied retrospectively without restatement beginning January 1, 2009.

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 International Financial Reporting Standards (IFRS) and U.S. GAAP. CICA Handbook 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 International Accounting Standards Board's (IASB) "Framework for the Preparation and Presentation of Financial Statements" that helps distinguish assets from expenses. CICA Handbook Section 3064 "Goodwill and Intangible Assets", which replaced CICA Handbook 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. In addition, CICA Handbook 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.

Business Combinations, Consolidated Financial Statements and Non-Controlling Interests

CICA Handbook Section 1582 "Business Combinations" is effective for business combinations with an acquisition date after January 1, 2011. This standard was amended to require additional use of fair value measurements, recognition of additional assets and liabilities, and increased disclosure. Adopting this standard is expected to have a material effect on the way the Company accounts for future business combinations. Entities adopting Section 1582 will also be required to adopt CICA Handbook Sections 1601 "Consolidated Financial Statements" and 1602 "Non-Controlling Interests". These standards will require a change in the measurement of non-controlling interest and will require the change to be presented as part of shareholders' equity on the balance sheet. In addition, the income statement of the controlling parent will include 100 per cent of the subsidiary's results and present the allocation between the controlling interest and non-controlling interest. These standards will be effective January 1, 2011, with early adoption permitted. The changes resulting from adopting Section 1582 will be applied prospectively and the changes from adopting Sections 1601 and 1602 will be applied retrospectively.

International Financial Reporting Standards

The CICA's Accounting Standards Board announced that Canadian publicly accountable enterprises are required to adopt IFRS, as issued by the IASB, effective January 1, 2011. In June 2008, the Canadian Securities Administrators proposed that Canadian public companies that are SEC registrants, such as TCPL, retain the option to prepare their financial statements under U.S. GAAP instead of IFRS. In November 2008, the SEC issued for public comment a recommendation that, beginning in 2014, U.S. issuers be required to adopt IFRS using a phased-in approach based on market capitalization.

68 MANAGEMENT'S DISCUSSION AND ANALYSIS

TCPL is currently considering the impact a conversion to IFRS or U.S. GAAP would have on its accounting systems and financial statements. TCPL's conversion project planning includes an analysis of project structure and governance, resources and training, analysis of key GAAP differences and a phased approach to the assessment of current accounting policies and implementation. The current status of the key elements of TCPL's conversion project is as follows:

Project Structure and Governance

A Steering Committee and an Implementation Committee have been established to provide directional leadership for the conversion project and to assist in developing accounting policy recommendations. These are multi-disciplinary committees and include representatives from Accounting, Information Technology, Treasury, Investor Relations, Human Resources and Operations. Management updates the Audit Committee at least quarterly on the status of the project.

Resources and Training

TCPL's conversion project team has been assembled and will support the conversion effort through project leadership, training, issue identification, technical research, policy recommendations, work group leadership and implementation support.

TCPL's IFRS training plan was developed and introduced in 2008. The first stage of the training has been completed and included IFRS project awareness sessions and a comprehensive IFRS immersion course. Later phases of the project will include more directed technical and implementation training relating to new accounting policies, procedures and processes. Throughout the project, IFRS training will be offered on a regular basis to ensure that TCPL staff remains current with respect to new IFRS developments.

Analysis of Significant GAAP Differences

The project team is currently assessing the differences between Canadian GAAP and IFRS. TCPL's conversion project is being executed using a risk-based methodology focusing on the significant differences between Canadian GAAP and IFRS. A high-level diagnostic was completed in 2008 outlining the significant differences and rating each option based on its significance to TCPL. In making this assessment, the technical accounting complexity, availability of policy choices, estimated need for conversion resources and impact on systems were considered. The differences between Canadian and US GAAP have already been identified in the Company's U.S. GAAP reconciliation. The most significant differences under the IFRS and U.S. GAAP conversion options were identified as follows:

IFRS

Converting to IFRS would have a significant impact on TCPL's rate-regulated operations, property plant and equipment, employee benefits, income taxes, financial statement disclosure and the initial adoption of IFRS in accordance with IFRS 1 "First-Time Adoption of IFRS".

Project work groups are currently conducting a detailed analysis of the significant differences identified to date and assessing the impact they could have on TCPL's financial reporting, information systems and internal controls over financial reporting. Less significant differences will be assessed starting in 2009. Under existing Canadian GAAP, TCPL follows specific accounting policies unique to rate-regulated businesses. TCPL is actively monitoring ongoing discussions and developments at the IASB regarding potential future guidance to clarify the applicability of certain aspects of rate-regulated accounting under IFRS. The IASB is expected to issue a proposed standard for rate-regulated businesses in 2009.

Several IFRS standards are in the process of being amended by the IASB. Amendments to existing standards are expected to continue until the transition date of January 1, 2011. TCPL actively monitors the IASB's schedule of projects, giving consideration to any proposed changes, where applicable, in its assessment of differences between IFRS and Canadian GAAP.

At the current stage of the project, TCPL cannot reasonably determine the full impact that adopting IFRS would have on its financial position and future results. In addition, developments with respect to specific rate-regulated accounting guidance under IFRS could have a significant effect on the scope of the project and on TCPL's financial results.

MANAGEMENT'S DISCUSSION AND ANALYSIS 69

U.S. GAAP

As an SEC registrant, TCPL is currently required to prepare and file a reconciliation from Canadian GAAP to U.S. GAAP. The differences that have the most significant impact on TCPL, as outlined in the reconciliation, include valuation of proprietary natural gas inventory held in storage, measurement of the deficit or surplus of defined benefit pension plans and recognition of deferred tax liabilities for TCPL's rate-regulated business. As previously noted, effective January 1, 2009, the U.S. GAAP difference with respect to recognition of deferred tax liabilities for TCPL's rate-regulated businesses will be eliminated.

SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA⁽¹⁾

(unaudited)		2008
(millions of dollars except per share amounts)		Fourth	Third	Second	First
Revenues		2,332	2,137	2,017	2,133
Net Income Applicable to Common Shares		274	383	318	445
Share Statistics
	Net income per common share – Basic and Diluted	$0.47	$0.70	$0.60	$0.84

(unaudited)		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		373	320	254	263
Share Statistics
	Net income per common share – Basic and Diluted	$0.71	$0.61	$0.49	$0.52

⁽¹⁾

The selected quarterly consolidated financial data has been prepared in accordance with Canadian GAAP.

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.

Significant developments that affected quarterly net earnings in 2008 and 2007 were as follows:

•

Fourth quarter 2008, Energy's net earnings included net unrealized gains of $6 million after tax ($7 million pre-tax) due to changes in fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts. Corporate's net expenses included net unrealized losses of $39 million after tax ($57 million pre-tax) for changes in the fair value of derivatives, which are used to manage the Company's exposure to rising interest rates but do not qualify as hedges for accounting purposes.

70 MANAGEMENT'S DISCUSSION AND ANALYSIS

•

Third quarter 2008, Energy's net earnings included contributions from the August 26, 2008 acquisition of Ravenswood. Corporate's net earnings included favourable income tax adjustments of $26 million from an internal restructuring and realization of losses.



•

Second quarter 2008, Energy's net earnings included net unrealized gains of $8 million after tax ($12 million pre-tax) due to changes in fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts. In addition, Western Power's revenues and operating income increased due to higher overall realized prices and market heat rates in Alberta.



•

First quarter 2008, Pipelines' net earnings included $152 million after tax ($240 million pre-tax) from the Calpine bankruptcy settlements received by GTN and Portland, and proceeds of $10 million after tax ($17 million pre-tax) from a lawsuit settlement. Energy's net earnings included a writedown of $27 million after tax ($41 million pre-tax) of costs related to Broadwater and net unrealized losses of $12 million after tax ($17 million pre-tax) due to changes in the fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts.



•

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. Energy's net earnings included net unrealized gains of $10 million after tax ($15 million pre-tax) due to changes in fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts.



•

Third quarter 2007, net earnings included $15 million of favourable income tax reassessments and associated interest income relating to prior years.



•

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.



•

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 additional ownership interests in Great Lakes. Energy's net earnings included earnings from the Edson natural gas facility, which was placed in service on December 31, 2006.

MANAGEMENT'S DISCUSSION AND ANALYSIS 71

FOURTH QUARTER 2008 HIGHLIGHTS

CONSOLIDATED RESULTS OF OPERATIONS
Reconciliation of Comparable Earnings to Net Income
Applicable to Common Shares

(unaudited) (millions of dollars)			2008		2007
Pipelines			210		202
Energy
	Comparable earnings(1)		147		104
	Specific items (net of tax, where applicable):
		Fair value adjustments of natural gas storage inventory and forward contracts	6		10
		Gain on sale of land	–		14
		Income tax adjustments	–		30
	Net income		153		158
Corporate
	Comparable expenses(1)		(89	)	(13	)
	Specific item:
		Income tax reassessments and adjustments	–		26
	Net (expenses)/income		(89	)	13
Net Income Applicable to Common Shares			274		373
Comparable Earnings(1)			268		293
	Specific items (net of tax, where applicable):
		Fair value adjustments of natural gas storage inventory and forward contracts	6		10
		Gain on sale of land	–		14
		Income tax reassessments and adjustments	–		56
Net Income Applicable to Common Shares			274		373

⁽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 in fourth quarter 2008 was $274 million compared to $373 million in fourth quarter 2007. Net income applicable to common shares decreased primarily due to increased net expenses from Corporate, which included unrealized losses of $39 million after tax in fourth quarter 2008, for changes in the fair value of derivatives, which are used to manage the Company's exposure to rising interest rates but do not qualify as hedges for accounting purposes. Corporate's net expenses also increased in fourth quarter 2008 compared to fourth quarter 2007 as a result of higher charges for financing the Company's 2008 capital program, including the Ravenswood acquisition, and higher unrealized gains in 2007 for changes in the fair value of derivatives used to manage the Company's exposure to foreign exchange rate fluctuations. Earnings from the Pipelines business increased in fourth quarter 2008 compared to fourth quarter 2007 primarily due to earnings recognized from a 2008 revenue requirement settlement for the Alberta System and increased earnings for PipeLines LP, partially offset by the inclusion in earnings in fourth quarter 2007 for a rate case settlement for GTN. Earnings from the Energy business were slightly lower in fourth quarter 2008 compared to fourth quarter 2007 as increases in Western Power, Eastern Power and Bruce Power were more than offset by a decrease in earnings from Natural Gas Storage in 2008 and favourable income tax adjustments that were included in fourth quarter 2007. Western Power earnings increased significantly in fourth quarter 2008 compared to fourth quarter 2007 primarily due to increased margins from the Alberta power portfolio. Energy's

72 MANAGEMENT'S DISCUSSION AND ANALYSIS

earnings in fourth quarter 2008 and 2007 included $6 million after tax ($7 million pre-tax) and $10 million after tax ($15 million pre-tax), respectively, of net unrealized gains resulting from changes in the fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts. Energy's earnings in fourth quarter 2007 also included a $14 million after-tax ($16 million pre-tax) gain on the sale of land. Net income for fourth quarter 2007 included $56 million ($30 million in Energy and $26 million in Corporate) of favourable income tax adjustments as a result of changes in Canadian federal income tax legislation.

Comparable earnings in fourth quarter 2008 were $268 million compared to $293 million for the same period in 2007. Comparable earnings in fourth quarter 2008 and 2007 excluded the $6 million and $10 million, respectively, of net unrealized gains resulting from changes in fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts. Comparable earnings in fourth quarter 2007 also excluded the $56 million of favourable income tax adjustments and $14 million gain on the sale of land.

The Pipelines business generated net income and comparable earnings of $210 million in fourth quarter 2008, an increase of $8 million compared to net income and comparable earnings of $202 million in fourth quarter 2007.

Canadian Mainline's net income for fourth quarter 2008 increased $2 million, compared to the same period in 2007 primarily due to higher performance-based incentives earned, increased OM&A cost savings and a higher ROE, as determined by the NEB, of 8.71 per cent in 2008 compared to 8.46 per cent in 2007. These increases were partially offset by a lower average investment base.

The Alberta System's net income in fourth quarter 2008 was $48 million compared to $41 million in fourth quarter 2007. Earnings increased primarily due to the recognition of earnings related to the revenue requirement settlement in fourth quarter 2008. Earnings in 2007 reflected an approved ROE of 8.51 per cent on a deemed common equity of 35 per cent.

ANR's net income in fourth quarter 2008 was $38 million compared to $35 million in fourth quarter 2007. The increase in fourth quarter 2008 was primarily due to higher revenues from new growth projects and the positive impact of a stronger U.S. dollar. These increases were partially offset by higher OM&A costs, including Hurricane Ike remediation costs.

GTN's comparable earnings in fourth quarter 2008 decreased $16 million compared to the same period in 2007. The decrease was primarily due to the positive impact of the rate case settlement included in fourth quarter 2007, partially offset by decreased OM&A expenses.

TCPL's proportionate share of net income from Other Pipelines was $29 million for the three months ended December 31, 2008 compared to $16 million for the same period in 2007. Other Pipelines' earnings increased in fourth quarter 2008 primarily due to lower support costs, higher PipeLines LP and Tamazunchale earnings, and a stronger U.S. dollar, partially offset by lower TransGas, Gas Pacifico/INNERGY and Portland earnings.

Energy's net income of $153 million in fourth quarter 2008 decreased $5 million compared to $158 million in fourth quarter 2007. Comparable earnings in fourth quarter 2008 of $147 million increased $43 million compared to $104 million for the same period in 2007. Comparable earnings excluded the net unrealized gains of $6 million after tax and $10 million after tax in fourth quarter 2008 and 2007, respectively, resulting from changes in fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts. In addition, comparable earnings in fourth quarter 2007 excluded the $14 million gain on sale of land and $30 million of favourable income tax adjustments.

Western Power's operating income of $106 million in fourth quarter 2008 increased $48 million compared to $58 million in fourth quarter 2007 primarily due to increased margins from the Alberta power portfolio, which resulted from higher overall realized power prices and market heat rates on both contracted and uncontracted volumes of power sold in Alberta. The market heat rate is determined by dividing the average price of power per MWh by the average price of natural gas per GJ for a given period.

MANAGEMENT'S DISCUSSION AND ANALYSIS 73

Eastern Power's operating income of $73 million in fourth quarter 2008 increased $7 million compared to $66 million in fourth quarter 2007. The increase was due to higher realized prices on sales to commercial and industrial customers in New England, the positive impact of the stronger U.S. dollar in fourth quarter 2008 and incremental earnings from the Carleton wind farm, which went into service in November 2008. On December 31, 2008, Ravenswood fulfilled its obligation under a tolling agreement with Hess Corporation that was in place at the time of acquisition. In 2009, TCPL's marketing operation will manage marketing of the Ravenswood plant output in a manner consistent with its other U.S. Northeast portfolio of assets.

TCPL's combined operating income of $50 million from its investment in Bruce Power increased $7 million in fourth quarter 2008 compared to fourth quarter 2007 primarily due to higher revenues resulting from higher realized prices. TCPL's proportionate share of operating loss in Bruce A increased $1 million to $6 million in fourth quarter 2008 compared to fourth quarter 2007 as a result of lower revenues due to decreased output, partially offset by higher contract prices and lower operating costs. TCPL's proportionate share of operating income in Bruce B increased $8 million to $61 million in fourth quarter 2008 compared to fourth quarter 2007 primarily due to higher realized prices achieved during fourth quarter 2008, as well as increased output. The increase in realized prices was due to higher contract prices on a larger proportion of volumes sold under contract in the three months ended December 31, 2008 compared to the same period in 2007.

Natural Gas Storage operating income of $40 million in fourth quarter 2008 decreased $17 million compared to $57 million in fourth quarter 2007. The decrease was due to lower realized seasonal natural gas price spreads at the Edson facility compared to the same period in 2007. Operating income in fourth quarter 2008 included net unrealized gains of $7 million for changes in the fair value of proprietary natural gas inventory in storage and natural gas forward purchase and sale contracts compared to net unrealized gains of $15 million for the same period in 2007.

Corporate's net expenses for the three months ended December 31, 2008 were $89 million compared to net income of $13 million for the same period in 2007. Excluding the $26 million of favourable income tax adjustments in fourth quarter 2007, Corporate's comparable expenses increased $76 million in fourth quarter 2008 compared to fourth quarter 2007. The increase in comparable expenses in fourth quarter 2008 was primarily due to net unrealized losses of $39 million after tax from changes in the fair value of derivatives, which are used to manage the Company's exposure to rising interest rates but do not qualify as hedges for accounting purposes. In addition, higher financial charges resulting from financing the Ravenswood acquisition and higher losses from the change in fair value of derivatives used to manage the Company's exposure to foreign exchange rate fluctuations were partially offset by increased capitalization of interest to finance a larger capital spending program.

SHARE INFORMATION

At February 23, 2009, TCPL had 600 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 2000 to 2008 is found under the heading "Nine Year Financial Highlights" in the Supplementary Information section of the Company's Annual Report.

74 MANAGEMENT'S DISCUSSION AND ANALYSIS

GLOSSARY OF TERMS

AFUDC	Allowance for funds used during construction
AGIA	Alaska Gasline Inducement Act
Alaska Pipeline Project	A proposed natural gas pipeline extending from a new natural gas treatment plant at Prudhoe Bay, Alaska to Alberta
Alberta System	A natural gas transmission system in Alberta
American Natural Resources (ANR)	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 underground natural gas storage facilities in Michigan
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
Bear Creek	A natural gas-fired cogeneration plant near Grande Prairie, Alberta
Bécancour	A natural gas-fired cogeneration plant near Trois-Rivières, Québec
Bison	A proposed pipeline from the Powder River Basin in Wyoming to the Northern Border system in North Dakota
BPC	BPC Generation Infrastructure Trust
Broadwater	A proposed offshore LNG project located in the New York waters of Long Island Sound
Bruce A	A partnership interest in the nuclear power generation facilities of Bruce Power A L.P.
Bruce B	A partnership interest in the nuclear power generation facilities of Bruce Power L.P
Bruce Power	Bruce A and Bruce B, collectively
Calpine	Calpine Corporation
Cameco	Cameco Corporation
Canadian Mainline	A natural gas transmission system extending from the Alberta/Saskatchewan border east into Québec
Cancarb	A waste-heat fuelled power plant at the Cancarb thermal carbon black facility in Medicine Hat, Alberta
CAPLA	Canadian Alliance of Pipeline Landowners' Associations
Carseland	A natural gas-fired cogeneration plant located near Carseland, Alberta
Cartier Wind	Six wind farms in Gaspé, Québec, three of which have been built
Chinook	A proposed HVDC transmission project that will originate in Montana and terminate in Nevada
CICA	Canadian Institute of Chartered Accountants
CO2	Carbon dioxide
Coolidge	A simple-cycle, natural gas-fired peaking power generation station under development in Coolidge, Arizona
CrossAlta	An underground natural gas storage facility near Crossfield, Alberta
DRP	Dividend Reinvestment and Share Purchase Plan
Edson	A natural gas storage facility near Edson, Alberta
FAS	Financial Accounting Standard
FCM	Forward Capacity Market
FERC	U.S. Federal Energy Regulatory Commission
Foothills	A natural gas transmission system extending from central Alberta to the B.C./U.S. border and to the Saskatchewan/U.S. border
Framework	Regulatory Framework for Air Emissions
GAAP	Generally accepted accounting principles
Gas Pacifico	A natural gas transmission system extending from Loma de la Lata, Argentina to Concepción, Chile
GHG	Greenhouse gas
GJ	Gigajoule
Grandview	A natural gas-fired cogeneration plant near Saint John, New Brunswick
Great Lakes	A natural gas transmission system that connects to the Canadian Mainline and serves markets in Eastern Canada and the northeastern and midwestern U.S.
Gas Transmission Network (GTN)	GTN System and North Baja, collectively
GTNC	Gas Transmission Northwest Corporation

MANAGEMENT'S DISCUSSION AND ANALYSIS 75

GTN System	A natural gas transmission system extending from the B.C./Idaho border to the Oregon/California border, traversing Idaho, Washington and Oregon
GWh	Gigawatt hours
Halton Hills	A natural gas-fired, combined-cycle power plant near Toronto, Ontario
HS&E	Health, Safety and Environment
HVDC	High voltage direct current
IASB	International Accounting Standards Board
IFRS	International Financial Reporting Standards
INNERGY	An industrial natural gas marketing company based in Concepción, Chile
Iroquois	A natural gas transmission system that connects with the Canadian Mainline near Waddington, New York, and delivers natural gas to the northeastern U.S.
ISO	International Organization of Standardization
ISO-NE	Independent System Operator New England
Keystone	A pipeline under construction that will transport crude oil from Hardisty, Alberta, to U.S. markets at Wood River and Patoka in Illinois, and to Cushing, Oklahoma
Keystone partnerships	TransCanada Keystone Pipeline Limited Partnership and TransCanada Keystone Pipeline, LP, collectively
Kibby Wind	A wind power project located in Kibby and Skinner Townships in northwestern Franklin County, Maine
km	Kilometres
kV	Kilovolt
LIBOR	London Interbank Offered Rate
LNG	Liquefied natural gas
MacKay River	A natural gas-fired cogeneration plant located near Fort McMurray, Alberta
MD&A	Management's Discussion and Analysis
Mackenzie Gas Pipeline (MGP)	A proposed natural gas pipeline to be constructed from a point near Inuvik, Northwest Territories to the northern border of Alberta
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 of Canada
Net earnings	Net income from continuing operations
North Baja	A natural gas transmission system extending from Arizona to the Baja California, Mexico/California border
Northern Border	A natural gas transmission system extending from a point near Monchy, Saskatchewan, to the U.S. Midwest
NorthernLights	A proposed HVDC electric transmission line running from central Alberta to a terminal in southern Alberta and interconnecting with the Pacific Northwest
NYISO	New York Independent System Operator
OM&A	Operating, maintenance and administration
OPA	Ontario Power Authority
Ocean State Power (OSP)	A natural gas-fired, combined-cycle plant in Burrillville, Rhode Island
Palomar	A proposed pipeline extending from the GTN System to the Columbia River northwest of Portland
Pathfinder	A proposed pipeline from Meeker, Colorado to the Northern Border system in North Dakota
PipeLines LP	TC PipeLines, LP
PNGTS	Portland Natural Gas Transmission System
Portland	A natural gas transmission system that extends from a point near East Hereford, Québec to the northeastern U.S.
Portlands Energy	A combined-cycle natural gas cogeneration plant near downtown Toronto, Ontario
PPA	Power purchase arrangement
Ravenswood	A natural gas and oil-fired generating facility consisting of multiple units employing steam turbine, combined cycle and combustion turbine technology located in Queens, New York
Redwater	A natural gas-fired cogeneration plant located near Redwater, Alberta
RGGI	Regional Greenhouse Gas Initiative
ROE	Rate of return on common equity
Salt River Project	Salt River Project Agricultural Improvement and Power District

76 MANAGEMENT'S DISCUSSION AND ANALYSIS

SEC	U.S. Securities and Exchange Commission
Sempra	Sempra Pipelines and Storage
Sheerness	A coal-fired power generating facility located near Hanna, Alberta
STEP 2008	Storage enhancement project
Sundance A	A coal-fired power generating facility located near Wabamun, Alberta
Sundance B	A coal-fired power generating facility located near Wabamun, Alberta
Sunstone	A proposed pipeline from Wyoming to Stanfield, Oregon
Tamazunchale	A natural gas transmission system in Mexico extending from Naranjos, Veracruz to Tamazunchale, San Luis Potosi
TC Hydro	Hydroelectric generation assets located in New Hampshire, Vermont and Massachusetts
TCPL or the Company	TransCanada PipeLines Limited
TCPM	TransCanada Power Marketing Ltd.
Trans Québec & Maritimes (TQM)	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
TransCanada	TransCanada Corporation
TransGas	A natural gas transmission system, extending from Mariquita in the central region of Colombia to Cali in the southwest region of Colombia
Tuscarora	A natural gas transmission system extending from Malin, Oregon to Wadsworth, Nevada
U.S.	United States
VaR	Value-at-Risk methodology
Ventures LP	Natural gas transmission systems in Alberta that supply natural gas to the oil sands region of northern Alberta and to a petrochemical complex at Joffre, Alberta
WCI	Western Climate Initiative
WCSB	Western Canada Sedimentary Basin
Williams	Williams Gas Pipeline Company, LLC
Zephyr	A proposed HVDC transmission project that will originate in Wyoming and terminate in Nevada

MANAGEMENT'S DISCUSSION AND ANALYSIS 77

Report of
Management The consolidated financial statements included in this Annual Report are the responsibility of TransCanada PipeLines Limited's (TCPL or the Company) 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 judgements. 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 and operating performance in 2008 to that in 2007 and should be read in conjunction with the consolidated financial statements and accompanying notes. In addition, it highlights significant changes between 2007 and 2006.

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 the 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 of, 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 the Ravenswood Generating Station (Ravenswood) in 2008 and began consolidating the operations of Ravenswood from the date of acquisition. Management has excluded this business from its evaluation of the effectiveness of the Company's internal control over financial reporting as of December 31, 2008. The net income attributable to this business represented less than one per cent of the Company's consolidated net income for the year ended December 31, 2008 and its aggregate total assets represented approximately nine per cent of the Company's consolidated total assets as at December 31, 2008.

Based on their evaluation, management concluded that internal control over financial reporting is effective as of December 31, 2008 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 independent, non-management directors. The Audit Committee meets with management at least six times a year and meets independently with 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, which is 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 independent external auditors are able to access the Audit Committee without the requirement to obtain 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 the results of the audit. It also recommends to the Board of Directors the firm of external auditors to be appointed by the shareholders.

The shareholders have 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 23, 2009

78 TRANSCANADA PIPELINES LIMITED

Auditors'
Report To the Shareholders of TransCanada PipeLines Limited

We have audited the consolidated balance sheets of TransCanada PipeLines Limited as at December 31, 2008 and 2007 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, 2008. 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 and 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, 2008 and 2007 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2008 in accordance with Canadian generally accepted accounting principles.

Chartered Accountants
Calgary, Canada

February 23, 2009

CONSOLIDATED FINANCIAL STATEMENTS 79

TRANSCANADA PIPELINES LIMITED
CONSOLIDATED INCOME

Year ended December 31 (millions of dollars)		2008		2007		2006
Revenues		8,619		8,828		7,520
Operating Expenses
Plant operating costs and other		3,062		3,030		2,411
Commodity purchases resold		1,511		1,959		1,707
Depreciation		1,189		1,179		1,059
		5,762		6,168		5,177
		2,857		2,660		2,343
Other Expenses/(Income)
Financial charges (Note 10)		962		961		828
Financial charges of joint ventures (Note 11)		72		75		92
Interest income and other		(80	)	(166	)	(179	)
Calpine bankruptcy settlements (Note 18)		(279	)	–		–
Writedown of Broadwater LNG project costs (Note 7)		41		–		–
		716		870		741
Income from Continuing Operations before Income Taxes and Non-Controlling Interests		2,141		1,790		1,602
Income Taxes (Note 19)
	Current	524		429		300
	Future	67		54		175
		591		483		475
Non-Controlling Interests (Note 15)		108		75		56
Net Income from Continuing Operations		1,442		1,232		1,071
Net Income from Discontinued Operations (Note 26)		–		–		28
Net Income		1,442		1,232		1,099
Preferred Share Dividends		22		22		22
Net Income Applicable to Common Shares		1,420		1,210		1,077
Net Income Applicable to Common Shares
	Continuing operations	1,420		1,210		1,049
	Discontinued operations	–		–		28
		1,420		1,210		1,077

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

80 CONSOLIDATED FINANCIAL STATEMENTS

TRANSCANADA PIPELINES LIMITED
CONSOLIDATED CASH FLOWS

Year ended December 31 (millions of dollars)	2008		2007		2006
Cash Generated from Operations
Net income	1,442		1,232		1,099
Depreciation	1,189		1,179		1,059
Future income taxes (Note 19)	67		54		175
Non-controlling interests (Note 15)	108		75		56
Employee future benefits funding lower than/(in excess of) expense (Note 22)	17		43		(31	)
Writedown of Broadwater LNG project costs (Note 7)	41		–		–
Other	128		20		16
	2,992		2,603		2,374
(Increase)/decrease in operating working capital (Note 23)	(188	)	215		(300	)
Net cash provided by operations	2,804		2,818		2,074
Investing Activities
Capital expenditures	(3,134	)	(1,651	)	(1,572	)
Acquisitions, net of cash acquired (Note 9)	(3,229	)	(4,223	)	(470	)
Disposition of assets, net of current income taxes (Note 9)	28		35		23
Deferred amounts and other	(143	)	(321	)	(95	)
Net cash used in investing activities	(6,478	)	(6,160	)	(2,114	)
Financing Activities
Dividends on common and preferred shares (Note 16 and 17)	(817	)	(725	)	(639	)
Distributions paid to non-controlling interests	(119	)	(66	)	(50	)
Advances (to)/from parent (Note 25)	(180	)	389		40
Notes payable issued/(repaid), net (Note 20)	1,659		(412	)	(495	)
Long-term debt issued, net of issue costs (Note 10)	2,197		2,616		2,107
Reduction of long-term debt	(840	)	(1,088	)	(729	)
Long-term debt of joint ventures issued (Note 11)	173		142		56
Reduction of long-term debt of joint ventures	(120	)	(157	)	(70	)
Common shares issued (Note 17)	2,419		1,842		–
Junior subordinated notes issued, net of issue costs (Note 12)	–		1,094		–
Preferred securities redeemed	–		(488	)	–
Partnership units of subsidiary issued (Note 9)	–		348		–
Net cash provided by financing activities	4,372		3,495		220
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents	98		(50	)	9
Increase in Cash and Cash Equivalents	796		103		189
Cash and Cash Equivalents
Beginning of year	504		401		212
Cash and Cash Equivalents
End of year	1,300		504		401

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

CONSOLIDATED FINANCIAL STATEMENTS 81

TRANSCANADA PIPELINES LIMITED
CONSOLIDATED BALANCE SHEET

December 31 (millions of dollars)	2008	2007
ASSETS
Current Assets
Cash and cash equivalents	1,300	504
Accounts receivable	1,280	1,116
Due from TransCanada Corporation (Note 25)	1,529	1,407
Inventories	489	497
Other	523	188
	5,121	3,712
Plant, Property and Equipment (Note 5)	29,189	23,452
Goodwill (Note 6)	4,397	2,633
Other Assets (Note 7)	2,228	1,940
	40,935	31,737
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Notes payable (Note 20)	1,702	55
Accounts payable	1,868	1,764
Due to TransCanada Corporation (Note 25)	1,821	572
Accrued interest	361	265
Current portion of long-term debt (Note 10)	786	556
Current portion of long-term debt of joint ventures (Note 11)	207	30
	6,745	3,242
Due to TransCanada Corporation (Note 25)	–	1,307
Deferred Amounts (Note 13)	1,719	1,107
Future Income Taxes (Note 19)	1,253	1,193
Long-Term Debt (Note 10)	15,368	12,377
Long-Term Debt of Joint Ventures (Note 11)	869	873
Junior Subordinated Notes (Note 12)	1,213	975
	27,167	21,074
Non-Controlling Interests (Note 15)	805	610
Shareholders' Equity	12,963	10,053
	40,935	31,737
Commitments, Contingencies and Guarantees (Note 24)

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

82 CONSOLIDATED FINANCIAL STATEMENTS

TRANSCANADA PIPELINES LIMITED
CONSOLIDATED COMPREHENSIVE INCOME

Year ended December 31 (millions of dollars)	2008		2007		2006
Net Income	1,442		1,232		1,099
Change in foreign currency translation gains and losses on investments in foreign operations(1)	571		(350	)	6
Change in gains and losses on hedges of investments in foreign operations(2)	(589	)	79		(6	)
Change in gains and losses on derivative instruments designated as cash flow hedges(3)	(60	)	42		–
Reclassification to net income of gains and losses on derivative instruments designated as cash flow hedges pertaining to prior periods(4)	(23	)	42		–
Change in gains and losses on available-for-sale financial instruments(5)	2		–		–
Other Comprehensive Income/(Loss)	(99	)	(187	)	–
Comprehensive Income	1,343		1,045		1,099

⁽¹⁾

Net of income tax recovery of $104 million in 2008 (2007 – $101 million expense; 2006 – $3 million expense).

⁽²⁾

Net of income tax recovery of $303 million in 2008 (2007 – $41 million expense; 2006 – $3 million recovery).

⁽³⁾

Net of income tax recovery of $41 million in 2008 (2007 – $27 million expense).

⁽⁴⁾

Net of income tax recovery of $19 million in 2008 (2007 – $23 million expense).

⁽⁵⁾

Net of income tax expense of nil in 2008.

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

CONSOLIDATED FINANCIAL STATEMENTS 83

TRANSCANADA PIPELINES LIMITED
CONSOLIDATED ACCUMULATED OTHER COMPREHENSIVE INCOME

(millions of dollars)	Currency Translation Adjustment		Cash Flow Hedges and Other		Total
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	)
Change in foreign currency translation gains and losses on investments in foreign operations(1)	571		–		571
Change in gains and losses on hedges of investments in foreign operations(2)	(589	)	–		(589	)
Change in gains and losses on derivative instruments designated as cash flow hedges(4)	–		(60	)	(60	)
Reclassification to net income of gains and losses on derivative instruments designated as cash flow hedges pertaining to prior periods(5)(6)	–		(23	)	(23	)
Change in gains and losses on available-for-sale financial instruments(7)	–		2		2
Balance at December 31, 2008	(379	)	(93	)	(472	)

⁽¹⁾

Net of income tax recovery of $104 million in 2008 (2007 – $101 million expense; 2006 – $3 million expense).

⁽²⁾

Net of income tax recovery of $303 million in 2008 (2007 – $41 million expense; 2006 – $3 million recovery).

⁽³⁾

Net of income tax recovery of $44 million in 2007.

⁽⁴⁾

Net of income tax recovery of $41 million in 2008 (2007 – $27 million expense).

⁽⁵⁾

Net of income tax recovery of $19 million in 2008 (2007 – $23 million expense).

⁽⁶⁾

The amount of losses related to cash flow hedges reported in accumulated other comprehensive income that will be reclassified to net income in 2009 is estimated to be $62 million ($41 million, net of tax). These estimates assume constant commodity prices, interest rates and foreign exchange rates over time, however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement.

⁽⁷⁾

Net of income tax expense of nil in 2008.

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

84 CONSOLIDATED FINANCIAL STATEMENTS

TRANSCANADA PIPELINES LIMITED
CONSOLIDATED SHAREHOLDERS' EQUITY

Year ended December 31 (millions of dollars)	2008		2007		2006
Preferred Shares
Balance at beginning and end of year	389		389		389
Common Shares
Balance at beginning of year	6,554		4,712		4,712
Proceeds from shares issued (Note 17)	2,419		1,842		–
Balance at end of year	8,973		6,554		4,712
Contributed Surplus
Balance at beginning of year	281		277		275
Other	3		4		2
Balance at end of year	284		281		277
Retained Earnings
Balance at beginning of year	3,202		2,719		2,267
Net income	1,442		1,232		1,099
Preferred share dividends	(22	)	(22	)	(22	)
Common share dividends	(833	)	(731	)	(625	)
Transition adjustment resulting from adopting new financial instruments accounting standards	–		4		–
Balance at end of year	3,789		3,202		2,719
Accumulated Other Comprehensive Income, Net of Income Taxes
Balance at beginning of year	(373	)	(90	)	(90	)
Other comprehensive income/(loss)	(99	)	(187	)	–
Transition adjustment resulting from adopting new financial instruments accounting standards	–		(96	)	–
Balance at end of year	(472	)	(373	)	(90	)
	3,317		2,829		2,629
Total Shareholders' Equity	12,963		10,053		8,007

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

CONSOLIDATED FINANCIAL STATEMENTS 85

TRANSCANADA PIPELINES LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1    DESCRIPTION OF TRANSCANADA PIPELINES LIMITED'S BUSINESS

TransCanada PipeLines Limited (TCPL or the Company) is a wholly owned subsidiary of TransCanada Corporation (TransCanada) and 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 consists primarily of the Company's investments in regulated pipelines and regulated natural gas storage facilities. Through its Pipelines segment, TCPL owns and operates:

•

a natural gas transmission system extending from the Alberta/Saskatchewan 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 to regulated natural gas storage facilities in Michigan (ANR);

•

a natural gas transmission system extending from the British Columbia (B.C.)/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 B.C./United States border and to the Saskatchewan/U.S. border (Foothills);

•

a natural gas transmission system extending from Arizona to the Baja California, Mexico/California border (North Baja);

•

natural gas transmission systems in Alberta that supply natural gas to the oil sands 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 direct ownership interest in a natural gas transmission system that connects to the Canadian Mainline and serves markets in Eastern Canada and the 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 pipelines operated by TCPL:

•

a 46.4 per cent interest in Great Lakes, in which TCPL has a combined 68.5 per cent effective ownership interest through PipeLines LP and a direct interest described above;

•

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), in which TCPL 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), in which TCPL has a 32.1 per cent effective ownership interest through PipeLines LP.

TCPL owns but does not operate:

•

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, extending from Mariquita in the central region of Colombia to Cali in the southwest region of Colombia (TransGas); and

•

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).

TCPL has a 62 per cent interest in a pipeline under construction that will transport crude oil from Hardisty, Alberta, to U.S. markets at Wood River and Patoka in Illinois, and at Cushing, Oklahoma (Keystone).

Energy

The Energy segment consists primarily of the Company's investments in electrical power generation plants and non-regulated natural gas storage facilities. Through its Energy segment, the Company also sells electricity and holds interests in liquefied natural gas (LNG) regasification projects in North America. Through its Energy segment, TCPL owns and operates:

•

natural gas-fired cogeneration plants in Alberta at Carseland, Redwater, Bear Creek and MacKay River;

•

a waste-heat fuelled power plant at the Cancarb thermal carbon black facility in Medicine Hat, Alberta (Cancarb);

86 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

•

a natural gas and oil-fired generating facility in Queens, New York, consisting of multiple units employing steam turbine, combined-cycle and combustion turbine technology (Ravenswood);

•

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);

•

a natural gas-fired cogeneration plant near Trois-Rivières, Québec (Bécancour);

•

a natural gas-fired cogeneration plant near Saint John, New Brunswick (Grandview); and

•

a natural gas storage facility near Edson, Alberta (Edson).

TCPL owns but does not operate:

•

a 48.9 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 Tiverton, Ontario;

•

a 62 per cent interest in the Baie-des-Sables, Anse-à-Valleau and Carleton wind farms, three of six planned wind farms in Gaspé, Québec (Cartier Wind); and

•

a 60 per cent interest in an underground natural gas storage facility near Crossfield, Alberta (CrossAlta).

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 the following projects under construction:

•

a 50 per cent interest in a natural gas-fired, combined-cycle cogeneration plant near downtown Toronto, Ontario (Portlands Energy);

•

a natural gas-fired, combined-cycle power plant near Toronto (Halton Hills); and

•

a wind power project located in Kibby and Skinner Townships in northwestern Franklin County, Maine (Kibby Wind).

NOTE 2    ACCOUNTING POLICIES

The Company's consolidated financial statements 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 as the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgement in making these estimates and assumptions. 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. The Company consolidates its 32.1 per cent ownership interest in PipeLines LP and its 61.7 per cent interest in the Portland Natural Gas Transmission System (Portland) as the Company is able to exercise control over these assets. The other partners' interests are included in Non-Controlling Interests. TCPL proportionately consolidates its share of the accounts of joint ventures in which the Company is able to exercise joint control. TCPL uses the equity method of accounting for investments over which the Company is able to exercise significant influence.

Regulation

The Canadian Mainline, Foothills Pipe Lines Ltd. (Foothills) and Trans Québec & Maritimes System (TQM) are subject to the authority of the National Energy Board (NEB) of Canada. The Alberta System is regulated by the Alberta Utilities Commission (AUC). The GTN System and North Baja (collectively, GTN), the ANR Pipeline Company, the ANR Storage Company and the other natural gas pipelines in the U.S. are subject to the authority of the U.S. Federal Energy Regulatory Commission (FERC). These natural gas transmission operations are regulated with respect to construction, operations and the determination of tolls. 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 revenues and tolls. The impact of rate regulation on TCPL is provided in Note 14 of these financial statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 87

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. The Company's natural gas pipeline revenues are generally based on quantity of gas delivered or contracted capacity. Revenues are recognized on firm contracted capacity over the contract period. For interruptible or volumetric-based services, revenues are recorded when physical delivery is made. As the majority of the Company's natural gas pipelines are subject to rate regulation, revenues collected that are subject to rate proceedings may have to be refunded. Revenues from non-regulated operations are recorded when products have been delivered or services have been performed.

Energy

i)      Power

Revenues from the Company's Power business are primarily 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 capacity payments and ancillary services earned as well as the impact of energy derivative contracts, the accounting for which is described in the Financial Instruments section of this note.

ii)     Natural Gas Storage

Revenues earned from providing natural gas storage services are recognized in accordance with the terms of the natural 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 Revenues.

Cash and Cash Equivalents

The Company's cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value.

Inventories

Effective April 1, 2007, the Company adopted the accounting requirements for the Canadian Institute of Chartered Accountants (CICA) Handbook Section 3031 "Inventories". Inventories primarily consist of materials and supplies, including spare parts, and are carried at the lower of average cost and net realizable value. The Company values its proprietary natural gas inventory held in storage at fair value, as measured by the one-month forward price for natural gas, less selling costs. 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. The Company records its net proprietary natural gas storage sales and purchases in Revenues. All changes in the fair value of the proprietary natural gas inventories are reflected in Inventories and Revenues.

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 one per cent to 25 per cent and metering and other plant equipment are depreciated at various rates. The cost of regulated pipelines includes an allowance for funds used during construction (AFUDC) consisting of a debt and an equity component based on the rate of return on rate base approved by regulators. This allowance is reflected as an increase in the cost of the assets on the balance sheet. Interest is capitalized during construction of non-regulated pipelines. The equity component of AFUDC is a non-cash expenditure.

When regulated pipelines retire plant, property and equipment from service, the original book cost is removed from the gross plant amount and recorded as a reduction to accumulated depreciation. Costs incurred to remove a plant from service, net of any salvage proceeds, are also recorded in accumulated depreciation.

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 per cent to ten per cent. Nuclear power generation assets under capital lease are recorded initially 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 and the remaining lease term. Other equipment is depreciated at various rates. The cost of major overhauls of equipment is capitalized and depreciated over the estimated service lives. Interest is capitalized on facilities under construction.

88 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

Impairment of Long-Lived Assets

The Company reviews long-lived assets such as property, plant and equipment, and intangible assets for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows is less than the carrying value of the assets, an impairment loss is recognized for the excess of the carrying value over the fair value of the assets.

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. An initial assessment is made by comparing the fair value of the operations, which includes goodwill, to the book values of each reporting unit. If this fair value is less than book value, an impairment is indicated and a second test is performed to measure the amount of the impairment. In the second test, the implied fair value of the goodwill is calculated by deducting the fair value of all tangible and intangible net assets of the reporting unit from the fair value determined in the initial assessment. If the carrying value of the goodwill exceeds the calculated implied fair value of the goodwill, an impairment charge is recorded.

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, with remaining terms ranging from nine to 12 years. The PPAs under which TCPL buys power are accounted for as operating leases. A portion of these PPAs has been subleased to third parties under similar terms and conditions. The subleases are accounted for as operating leases and TCPL records the margin earned from the subleases as a component of Revenues.

Income Taxes

The taxes payable method of accounting for income taxes is used for tollmaking purposes for 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 at December 31, 2008, 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 all of the Company's other operations. Under the liability method, future income 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 during 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, shareholders' 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 monetary assets and liabilities are recorded in income except for exchange gains or losses on the principal amounts of foreign currency debt related to the Alberta System, Foothills and Canadian Mainline, which are deferred until they are refunded or recovered in tolls, as permitted by regulatory bodies.

Financial Instruments

Effective January 1, 2007, the Company adopted the accounting requirements for CICA Handbook Sections 1530 "Comprehensive Income", 3855 "Financial Instruments – Recognition and Measurement", and 3865 "Hedges". Effective December 31, 2007, the Company adopted the accounting requirements for CICA Handbook Sections 3862 "Financial Instruments – Disclosure", 3863 "Financial Instruments – Presentation", and 1535 "Capital Disclosures". Adjustments to the consolidated financial statements for 2007 were made on a prospective basis.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 89

The CICA Handbook requires that all financial instruments 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 derivative financial assets and liabilities consist of swaps, options, forwards and futures. A financial asset or liability may be designated as held for trading if it is entered into with the intention of generating a profit. The Company has not designated any non-derivative financial assets or liabilities as held for trading. Commodity held-for-trading financial 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 rate held-for-trading instruments are recorded in Financial Charges and in Interest Income and Other, respectively.

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 accounted for initially 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.

The held-to-maturity classification consists of non-derivative financial assets that are accounted for at their amortized cost using the effective interest method. The Company does not have any held-to-maturity financial assets.

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 at amortized cost using the effective interest method, 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. Items in this financial instrument category are recognized at amortized cost using the effective interest method. Interest expense is included in Financial Charges and in Financial Charges of Joint Ventures.

The Company uses derivatives 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.

All derivatives are recorded on the balance sheet at fair value, with the exception of non-financial derivatives 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. Changes in 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 in the Hedges section of this note.

Derivatives embedded in other financial instruments or contracts (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 derivatives that are recorded separately are included in Net Income.

The recognition of gains and losses on the derivatives for the Alberta System, Foothills and Canadian Mainline 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.

Transaction costs are defined as incremental costs that are directly attributable to the acquisition, issue or disposal of a financial instrument. The Company offsets long-term debt transaction costs against the associated debt and amortizes these costs using the effective interest method for all costs except those related to the Canadian regulated pipelines, which continue to be amortized on a straight-line basis in accordance with the provisions of tolling mechanisms.

The Company records the fair values of material joint and several guarantees. 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 is recorded in Deferred Amounts.

Hedges

The CICA Handbook 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 hedging relationship ceases to be effective or the hedging or hedged items cease to exist as a result of maturity, expiry, sale, termination, cancellation or exercise.

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.

90 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 are also recorded in Net Income. Changes in the fair value of foreign exchange and interest rate fair value 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 from Accumulated Other Comprehensive 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 reclassified to Net Income in the event the Company settles or otherwise reduces its investment in a foreign operation.

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 to do so exists and 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 pipelines and, therefore, it is 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 regulated natural gas pipelines, with the exception of certain 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, it is 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 plants. With respect to the nuclear assets leased by Bruce Power, the Company has not recorded an amount for asset retirement obligations, as Bruce Power leases the assets and the lessor is responsible for decommissioning liabilities under the lease agreement.

Environmental Liabilities

The Company records liabilities on an undiscounted basis for environmental remediation efforts that are likely to occur and where the cost can be reasonably estimated. The estimates, including associated legal costs, are based on available information using existing technology and enacted laws and regulations. The estimates are subject to revision in future periods based on actual costs incurred or new circumstances. Any amounts expected to be recovered from other parties, including insurers, are recorded as an asset separate from the associated liability.

Employee Benefit and Other Plans

The Company sponsors defined benefit pension plans (DB Plans), defined contributions plans (DC Plans), a Savings Plan and other post-employment plans. Contributions made by the Company to the DC Plans and Savings Plan 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 of the DB Plans' 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 market-related value of the DB Plans' assets, if any, is amortized over the average remaining service period of

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 91

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 medium-term incentive plans, which are payable in cash to eligible employees. 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 3    ACCOUNTING CHANGES

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, was withdrawn. In addition, Section 3465 "Income Taxes" was amended to require the recognition of future income tax assets and liabilities for rate-regulated entities. The Company has chosen to adopt accounting policies consistent with the U.S. Financial Accounting Standards Board's Financial Accounting Standard (FAS) 71 "Accounting for the Effects of Certain Types of Regulation". Accordingly, TCPL will retain its current method of accounting for its rate-regulated operations, except that TCPL will be required to recognize future income tax assets and liabilities instead of using the taxes payable method, and will record an offsetting adjustment to regulatory assets and liabilities. If the Company had adopted FAS 71, at December 31, 2008, additional future income tax liabilities and a regulatory asset in the amount of $1,434 million would have been recorded and would have been recoverable from future revenue. These changes will be applied retrospectively without restatement beginning January 1, 2009.

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 International Financial Reporting Standards (IFRS) and U.S. GAAP. CICA Handbook 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 International Accounting Standards Board's (IASB) "Framework for the Preparation and Presentation of Financial Statements" that helps distinguish assets from expenses. CICA Handbook Section 3064 "Goodwill and Intangible Assets", which replaced CICA Handbook 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. In addition, CICA Handbook 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.

Business Combinations, Consolidated Financial Statements and Non-Controlling Interests

CICA Handbook Section 1582 "Business Combinations" is effective for business combinations with an acquisition date after January 1, 2011. This standard was amended to require additional use of fair value measurements, recognition of additional assets and liabilities, and increased disclosure. Adopting this standard is expected to have a material effect on the way the Company accounts for future business combinations. Entities adopting Section 1582 will also be required to adopt CICA Handbook Sections 1601 "Consolidated Financial Statements" and 1602 "Non-Controlling Interests". These standards will require a change in the measurement of non-controlling interest and will require the change to be presented as part of shareholders' equity on the balance sheet. In addition, the income statement of the controlling parent will include 100 per cent of the subsidiary's results and present the allocation between the controlling interest and non-controlling interest. These standards will be effective January 1, 2011, with early adoption permitted. The changes resulting from adopting Section 1582 will be applied prospectively and the changes from adopting Sections 1601 and 1602 will be applied retrospectively.

International Financial Reporting Standards

The CICA's Accounting Standards Board announced that Canadian publicly accountable enterprises are required to adopt IFRS, as issued by the IASB, effective January 1, 2011. In June 2008, the Canadian Securities Administrators proposed that Canadian public companies that are also U.S. Securities and Exchange Commission (SEC) registrants, such as TCPL, retain the option to prepare their financial statements under U.S. GAAP instead of IFRS. In November 2008, the SEC issued for public comment a recommendation that, beginning in 2014, U.S. issuers be required to adopt IFRS using a phased-in approach based on market capitalization.

TCPL is currently considering the impact a conversion to IFRS or U.S. GAAP would have on its accounting systems and financial statements. TCPL's conversion project planning includes an analysis of project structure and governance, resources and training, analysis of key GAAP differences and a phased approach to the assessment of current accounting policies and implementation.

Under existing Canadian GAAP, TCPL follows specific accounting policies unique to rate-regulated businesses. TCPL is actively monitoring ongoing discussions and developments at the IASB regarding potential future guidance to clarify the applicability of certain aspects of rate-regulated accounting under IFRS. The IASB is expected to issue a proposed standard for rate-regulated businesses in 2009.

92 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 4    SEGMENTED INFORMATION

NET INCOME⁽¹⁾

Year ended December 31, 2008 (millions of dollars)	Pipelines		Energy		Corporate		Total
Revenues	4,650		3,969		–		8,619
Plant operating costs and other	(1,732	)	(1,326	)	(4	)	(3,062	)
Commodity purchases resold	–		(1,511	)	–		(1,511	)
Depreciation	(989	)	(200	)	–		(1,189	)
	1,929		932		(4	)	2,857
Financial charges	(674	)	–		(288	)	(962	)
Financial charges of joint ventures	(49	)	(23	)	–		(72	)
Interest income and other	73		6		1		80
Calpine bankruptcy settlements	279		–		–		279
Writedown of Broadwater LNG project costs	–		(41	)	–		(41	)
Income taxes	(548	)	(260	)	217		(591	)
Non-controlling interests and preferred share dividends	(108	)	–		(22	)	(130	)
Net Income Applicable to Common Shares	902		614		(96	)	1,420

Year ended December 31, 2007 (millions of dollars)
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	(718	)	1		(244	)	(961	)
Financial charges of joint ventures	(52	)	(23	)	–		(75	)
Interest income and other	52		10		88		150
Gain on sale of assets	–		16		–		16
Income taxes	(470	)	(208	)	195		(483	)
Non-controlling interests and preferred share dividends	(75	)	–		(22	)	(97	)
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	(711	)	–		(117	)	(828	)
Financial charges of joint ventures	(69	)	(23	)	–		(92	)
Interest income and other	100		5		51		156
Gain on sale of assets	23		–		–		23
Income taxes	(410	)	(198	)	133		(475	)
Non-controlling interests and preferred share dividends	(56	)	–		(22	)	(78	)
Net income from continuing operations	560		452		37		1,049
Net income from discontinued operations							28
Net Income Applicable to Common Shares							1,077

⁽¹⁾

Certain expenses such as indirect financial charges and related income taxes are not allocated to business segments when determining their net income.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 93

TOTAL ASSETS

December 31 (millions of dollars)	2008	2007
Pipelines	25,020	22,024
Energy	12,006	7,037
Corporate	3,909	2,676
	40,935	31,737

GEOGRAPHIC INFORMATION

Year ended December 31 (millions of dollars)	2008	2007	2006
Revenues(1)
Canada – domestic	4,599	5,019	4,956
Canada – export	1,125	1,006	972
United States and other	2,895	2,803	1,592
	8,619	8,828	7,520

⁽¹⁾

Revenues are attributed based on the country where the product or service originated.

December 31 (millions of dollars)	2008	2007
Plant, Property and Equipment
Canada	18,041	16,741
United States	10,973	6,564
Mexico	175	147
	29,189	23,452

CAPITAL EXPENDITURES

Year ended December 31 (millions of dollars)	2008	2007	2006
Pipelines	1,854	564	560
Energy	1,266	1,079	976
Corporate	14	8	36
	3,134	1,651	1,572

94 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 5    PLANT, PROPERTY AND EQUIPMENT

		2008			2007
December 31 (millions of dollars)		Cost	Accumulated Depreciation	Net Book Value	Cost		Accumulated Depreciation	Net Book Value
Pipelines(1)
Canadian Mainline
	Pipeline	8,740	4,269	4,471	8,889		4,149	4,740
	Compression	3,373	1,399	1,974	3,371		1,303	2,068
	Metering and other	344	140	204	345		140	205
		12,457	5,808	6,649	12,605		5,592	7,013
	Under construction	16	–	16	28		–	28
		12,473	5,808	6,665	12,633		5,592	7,041
Alberta System
	Pipeline	5,518	2,637	2,881	5,258		2,504	2,754
	Compression	1,552	914	638	1,522		842	680
	Metering and other	846	317	529	831		297	534
		7,916	3,868	4,048	7,611		3,643	3,968
	Under construction	354	–	354	120		–	120
		8,270	3,868	4,402	7,731		3,643	4,088
ANR
	Pipeline	976	69	907	772		25	747
	Compression	579	61	518	424		32	392
	Metering and other	686	50	636	483		6	477
		2,241	180	2,061	1,679		63	1,616
	Under construction	31	–	31	69		–	69
		2,272	180	2,092	1,748		63	1,685
GTN
	Pipeline	1,482	215	1,267	1,181		134	1,047
	Compression	562	63	499	436		39	397
	Metering and other	134	23	111	81		3	78
		2,178	301	1,877	1,698		176	1,522
	Under construction	30	–	30	31		–	31
		2,208	301	1,907	1,729		176	1,553
Great Lakes		1,875	744	1,131	1,509		552	957
Foothills		1,655	873	782	1,647		819	828
Northern Border		1,530	682	848	1,232		528	704
Keystone – under construction		1,361	–	1,361	158		–	158
Other(2)		2,078	566	1,512	1,705		439	1,266
		8,499	2,865	5,634	6,251		2,338	3,913
		33,722	13,022	20,700	30,092		11,812	18,280
Energy
	Nuclear(3)	1,604	364	1,240	1,479		286	1,193
	Natural gas/oil – Ravenswood(4)	1,977	22	1,955	n/a	(5)	n/a	n/a
	Natural gas – Other(6)	1,702	504	1,198	1,570		383	1,187
	Hydro	628	48	580	503		28	475
	Wind	391	18	373	288		6	282
	Natural gas storage	374	46	328	358		33	325
	Other	156	82	74	137		78	59
		6,832	1,084	5,748	4,335		814	3,521
	Under construction(7)	2,687	–	2,687	1,606		–	1,606
		9,519	1,084	8,435	5,941		814	5,127
Corporate		74	20	54	60		15	45
		43,315	14,126	29,189	36,093		12,641	23,452

⁽¹⁾

In 2008, the Company capitalized $27 million (2007 – $14 million) relating to AFUDC.

⁽²⁾

Pipelines – Other primarily includes assets of Iroquois, Portland, TQM, Tuscarora and Tamazunchale.

⁽³⁾

Includes assets under capital lease relating to Bruce Power.

⁽⁴⁾

TCPL acquired Ravenswood on August 26, 2008.

⁽⁵⁾

Not applicable, as there are no comparative amounts for prior years.

⁽⁶⁾

Certain owned power generation facilities with long-term PPAs are accounted for as assets under operating leases. The net book value of these facilities was $77 million at December 31, 2008 (2007 – $78 million). Revenues of $14 million were recognized in 2008 (2007 – $16 million) through the sale of electricity under the related PPAs.

⁽⁷⁾

Energy assets under construction primarily include expenditures for the Bruce A refurbishment and restart, and for construction of Halton Hills, Portland Energy, Kibby Wind and Coolidge.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 95

NOTE 6    GOODWILL

The Company has recorded the following goodwill on its acquisitions in the U.S.:

(millions of dollars)	Pipelines		Energy	Total
Balance at January 1, 2007	281		–	281
Acquisition of ANR	2,235		–	2,235
Acquisition of additional interests in Great Lakes	573		–	573
Acquisition of additional interest in Tuscarora	3		–	3
Foreign exchange and adjustments	(459	)	–	(459	)
Balance at December 31, 2007	2,633		–	2,633
Acquisition of Ravenswood	–		949	949
Foreign exchange and adjustments	749		66	815
Balance at December 31, 2008	3,382		1,015	4,397

NOTE 7    OTHER ASSETS

December 31 (millions of dollars)	2008	2007
PPAs(1)	651	709
Prepaid operating lease(2)	369	n/a
Pension and other benefit plans (Note 22)	234	234
Regulatory assets (Note 14)	201	336
Fair value of derivative contracts (Note 18)	191	204
Loans and advances(3) (Note 24)	140	137
Deferred project development costs(4)	116	40
Equity investments(5)	85	63
Other	241	217
	2,228	1,940

⁽¹⁾

The following amounts related to the PPAs are included in the consolidated financial statements:

	2008			2007
December 31 (millions of dollars)	Cost	Accumulated Amortization	Net Book Value	Cost	Accumulated Amortization	Net Book Value
PPAs	915	264	651	915	206	709

Amortization expense for the PPAs was $58 million for the year ended December 31, 2008 (2007 – $58 million; 2006 – $58 million). The expected annual amortization expense in each of the next five years is: 2009 – $58 million; 2010 – $58 million; 2011 – $57 million; 2012 – $57 million; and 2013 – $57 million.

⁽²⁾

The balance at December 31, 2008 represents the long-term portion of a prepaid operating lease from the acquisition of Ravenswood. The expected annual operating lease expense in each of the next five years is US$10 million.

⁽³⁾

The balance at December 31, 2008 represents a $140-million loan (2007 – $137 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.

⁽⁴⁾

The balance at December 31, 2008 includes $74 million (2007 – nil) related to the proposed expansion of the Keystone pipeline project and $42 million related to the Bison pipeline project. The balance of $40 million at December 31, 2007 related to the Broadwater LNG project and, in 2008, TCPL wrote down $41 million of capitalized costs related to this project after the New York Department of State rejected a proposal to construct this facility.

⁽⁵⁾

The balance primarily relates to the Company's 46.5 per cent ownership interest in TransGas.

96 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 8    JOINT VENTURE INVESTMENTS

			TCPL's Proportionate Share
			Income/(Loss) Before Income Taxes Year ended December 31				Net Assets December 31
(millions of dollars)	Ownership Interest as at December 31, 2008		2008		2007	2006	2008	2007
Pipelines
Northern Border(1)			59		67	52	479	415
Iroquois	44.5%		32		25	25	239	163
TQM	50.0%		12		11	11	69	74
Keystone	61.9%	(2)	(7	)	n/a	n/a	906	207
Great Lakes(3)			–		13	69	–	–
Other	Various		15		13	6	70	48
Energy
Bruce A	48.9%		46		8	75	2,012	1,640
Bruce B	31.6%		136		140	140	429	325
CrossAlta	60.0%		44		59	64	56	38
Cartier Wind	62.0%	(4)	12		10	2	365	275
TC Turbines	50.0%		9		5	5	31	29
Portlands Energy	50.0%		–		–	–	334	269
ASTC Power Partnership	50.0%	(5)	–		–	–	70	76
			358		351	449	5,060	3,559

⁽¹⁾

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, 2008 and 2007.

⁽²⁾

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. In 2008, TCPL agreed to increase its equity ownership in the Keystone partnerships to 79.99 per cent. ConocoPhillips' equity ownership will be reduced concurrently to 20.01 per cent. TCPL's increase in ownership is expected to occur as the Company funds 100 per cent of the construction expenditures until the participants' project capital contributions are aligned with the revised ownership interests. At December 31, 2008, TCPL's equity ownership in the Keystone partnerships was 61.9 per cent (December 31, 2007 – 50.0 per cent), however, strategic, operational and financial decisions are made jointly with ConocoPhillips.

⁽³⁾

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 interest in Great Lakes, net of non-controlling interests, was 68.5 per cent at December 31, 2008 and 2007. TCPL commenced consolidating its investment in Great Lakes on a prospective basis effective February 22, 2007.

⁽⁴⁾

TCPL proportionately consolidates its 62 per cent interest in the Cartier Wind assets. The first three phases of the six-phase Cartier Wind project, Baie-des-Sables, Anse-à-Valleau and Carleton, began operating in November 2006, 2007 and 2008, respectively.

⁽⁵⁾

The Company has a 50 per cent ownership interest in ASTC Power Partnership, an Alberta partnership which holds the Sundance B PPA. The underlying power volumes related to this ownership interest are effectively transferred to TCPL.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 97

Summarized Financial Information of Joint Ventures

Year ended December 31 (millions of dollars)	2008		2007		2006
Income
Revenues	1,264		1,305		1,382
Plant operating costs and other	(683	)	(736	)	(686	)
Depreciation	(154	)	(150	)	(163	)
Financial charges and other	(69	)	(68	)	(84	)
Proportionate share of joint venture income before income taxes	358		351		449

Year ended December 31 (millions of dollars)	2008		2007		2006
Cash Flows
Operating activities	1,067		420		645
Investing activities	(2,031	)	(761	)	(641	)
Financing activities(1)	952		409		(31	)
Effect of foreign exchange rate changes on cash and cash equivalents	23		(8	)	9
Proportionate share of increase/(decrease) in cash and cash equivalents of joint ventures	11		60		(18	)

⁽¹⁾

Financing activities included cash outflows resulting from distributions paid to TCPL of $287 million in 2008 (2007 – $361 million; 2006 – $470 million) and cash inflows resulting from capital contributions paid by TCPL of $1,067 million in 2008 (2007 – $771 million; 2006 – $452 million).

December 31 (millions of dollars)	2008		2007
Balance Sheet
Cash and cash equivalents	181		170
Other current assets	159		343
Plant, property and equipment	6,341		4,283
Other assets/(deferred amounts), net	45		(69	)
Current liabilities	(793	)	(293	)
Long-term debt	(871	)	(873	)
Future income taxes	(2	)	(2	)
Proportionate share of net assets of joint ventures	5,060		3,559

NOTE 9    ACQUISITIONS AND DISPOSITIONS

Acquisitions

Pipelines

Keystone

In 2008, TCPL agreed to increase its equity ownership in the Keystone partnerships up to 79.99 per cent from 50 per cent, with ConocoPhillips' equity ownership being reduced concurrently to 20.01 per cent. The increase in ownership is expected to occur as TCPL funds 100 per cent of the construction expenditures until the participants' project capital contributions are aligned with the revised ownership interests. In accordance with the agreement, TCPL funded $362 million of cash calls, resulting in the acquisition of an incremental 12 per cent ownership interest for $176 million, bringing TCPL's ownership interest to 62 per cent at December 31, 2008. TCPL continues to proportionately consolidate the Keystone partnerships.

During 2008, Keystone purchased pipeline facilities located in Saskatchewan and Manitoba from the Canadian Mainline for use in the construction of the Keystone oil pipeline. The sale was completed in three phases for total proceeds of $65 million, with no gain recognized on the sale.

98 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ANR and Great Lakes

On February 22, 2007, TCPL acquired from El Paso Corporation 100 per cent of American Natural Resources Company and ANR Storage Company (collectively, 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, 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 purchase price was allocated 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	1,945		32		1,977
Current liabilities	(179	)	(3	)	(182	)
Long-term debt	(475	)	(16	)	(491	)
Other non-current liabilities	(357	)	(19	)	(376	)
	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, 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. As of February 2007, TCPL's effective ownership interest in Great Lakes was 68.5 per cent, comprising its direct ownership interest and its indirect ownership interest through PipeLines LP. The purchase price was allocated 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 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 value.

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

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. 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.

Tuscarora

In December 2007, 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 addition, PipeLines LP purchased TCPL's one per cent interest in Tuscarora for

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 99

US$2 million. Beginning December 2007, PipeLines LP owned 100 per cent of Tuscarora, resulting in TCPL's effective ownership of 32.1 per cent, net of non-controlling interests.

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.

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. As of April 2006, PipeLines LP owned 50 per cent of Northern Border, giving TCPL effective ownership of 16.1 per cent, net of non-controlling interests.

Energy

Ravenswood

On August 26, 2008, TCPL acquired from National Grid plc 100 per cent of the 2,480 MW Ravenswood power facility for US$2.9 billion, subject to certain post-closing adjustments. The acquisition was accounted for using the purchase method of accounting. TCPL began consolidating Ravenswood in the Energy segment subsequent to the acquisition date.

The preliminary allocation of the purchase price at December 31, 2008 was as follows:

Purchase Price Allocation

(millions of US dollars)
Current assets	149
Plant, property and equipment	1,666
Other non-current assets	305
Goodwill	835
Current liabilities	(19	)
Other non-current liabilities	(20	)
	2,916

A preliminary allocation of the purchase price, subject to certain post-closing adjustments, has been made using fair values of the net assets at the date of acquisition. Factors that contributed to goodwill included the opportunity to expand the Energy segment further in the U.S. market and to gain a stronger competitive position in the North American power generation business. The goodwill recognized on this transaction is amortizable for tax purposes.

Dispositions

Pipelines

Northern Border Partners, L.P. Interest

In April 2006, TCPL sold its 17.5 per cent general partner interest in Northern Border Partners, L.P., 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.

Energy

Ontario Land Sale

In November 2007, TCPL's Energy segment sold land in Ontario that had previously been held for development, generating net proceeds of $37 million and recognizing an after-tax gain of $14 million on the sale.

100 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 10    LONG-TERM DEBT

			2008		2007
Outstanding loan amounts (millions of dollars unless otherwise indicated)		Maturity Dates	Outstanding December 31	Interest Rate(1)	Outstanding December 31	Interest Rate(1)
TRANSCANADA PIPELINES LIMITED
Debentures
	Canadian dollars	2009 to 2020	1,251	10.8%	1,351	10.9%
	U.S. dollars (2008 and 2007 – US$600)(2)	2012 to 2021	734	9.5%	594	9.5%
Medium-Term Notes
	Canadian dollars(3)	2009 to 2031	3,653	5.3%	3,413	6.1%
Senior Unsecured Notes
	U.S. dollars (2008 – US$4,723; 2007 – US$3,223)(4)	2009 to 2038	5,751	6.3%	3,161	6.0%
			11,389		8,519
NOVA GAS TRANSMISSION LTD.
Debentures and Notes
	Canadian dollars	2010 to 2024	439	11.5%	501	11.6%
	U.S. dollars (2008 and 2007 – US$375)	2012 to 2023	457	8.2%	368	8.2%
Medium-Term Notes
	Canadian dollars	2025 to 2030	502	7.4%	607	7.2%
	U.S. dollars (2008 and 2007 – US$33)	2026	39	7.5%	32	7.5%
			1,437		1,508
TRANSCANADA PIPELINE USA LTD.
Bank Loan
	U.S. dollars (2008 – US$700; 2007 – US$860)	2012	857	2.4%	850	5.7%
ANR PIPELINE COMPANY
Senior Unsecured Notes
	U.S. dollars (2008 and 2007 – US$444)	2010 to 2025	541	9.1%	435	9.1%
GAS TRANSMISSION NORTHWEST CORPORATION
Senior Unsecured Notes
	U.S. Dollars (2008 and 2007 – US$400)	2010 to 2035	488	5.4%	399	5.4%
TC PIPELINES, LP
Unsecured Loan
	U.S. dollars (2008 – US$475; 2007 – US$507)	2011	580	2.7%	499	6.2%
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Senior Unsecured Notes
	U.S. dollars (2008 – US$430; 2007 – US$440)	2011 to 2030	526	7.8%	434	7.8%
TUSCARORA GAS TRANSMISSION COMPANY
Senior Unsecured Notes
	U.S. dollars (2008 – US$64; 2007 – US$69)	2010 to 2012	78	7.4%	67	7.4%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Senior Secured Notes
	U.S. dollars (2008 – US$196; 2007 – US$211)(5)	2018	236	6.1%	205	6.1%
OTHER
Senior Notes
	U.S. dollars (2008 – US$18; 2007 – US$17)	2011	22	7.3%	17	7.3%
			16,154		12,933
Less: Current Portion of Long-Term Debt			786		556
			15,368		12,377

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 101

⁽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. Weighted average and effective interest rates are stated as at the respective outstanding dates.

⁽²⁾

Includes fair value adjustments for interest rate swap agreements on US$50 million of debt at December 31, 2008 and 2007.

⁽³⁾

Includes fair value adjustments for interest rate swap agreements on $50 million of debt at December 31, 2008 (2007 – $150 million).

⁽⁴⁾

Includes fair value adjustments for interest rate swap agreements on US$150 million of debt at December 31, 2008 and 2007.

⁽⁵⁾

Senior Secured Notes are secured by shipper transportation contracts, existing and new guarantees, letters of credit and collateral requirements.

Principal Repayments

Principal repayments on the long-term debt of the Company for the next five years are approximately as follows: 2009 – $786 million; 2010 – $531 million; 2011 – $1,014 million; 2012 – $1,370 million; and 2013 – $1,180 million.

Debt Shelf Programs – TransCanada PipeLines Limited

In January 2009, the Company filed a debt shelf prospectus in the U.S. qualifying for issuance US$3.0 billion of debt securities.

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. Subsequent to the February 2009 debt issue discussed below, the Company had $300 million of remaining capacity available under the Canadian shelf 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. At December 31, 2008, the Company had fully utilized its capacity under the September 2007 U.S. shelf prospectus.

TransCanada PipeLines Limited

On February 17, 2009, TCPL completed the issuance of Medium-Term Notes of $300 million and $400 million maturing in February 2014 and February 2039, respectively, and bearing interest at 5.05 per cent and 8.05 per cent, respectively. These notes were issued under the $1.5 billion debt shelf prospectus filed in Canada in March 2007.

On January 9, 2009, TCPL issued US$750 million and US$1.25 billion of Senior Unsecured Notes maturing in January 2019 and January 2039, respectively, and bearing interest at 7.125 per cent and 7.625 per cent, respectively. These notes were issued under the January 2009 U.S. debt shelf prospectus.

In August 2008, TCPL issued $500 million of Medium-Term Notes maturing in August 2013, and bearing interest at 5.05 per cent under the March 2007 Canadian debt shelf prospectus.

In August 2008, TCPL issued US$850 million and US$650 million of Senior Unsecured Notes maturing in August 2018 and August 2038, respectively, and bearing interest at 6.50 per cent and 7.25 per cent, respectively. These notes were issued under the September 2007 U.S. debt shelf prospectus.

In October 2007, TCPL issued US$1.0 billion of Senior Unsecured Notes under the U.S. debt shelf filed in September 2007.

NOVA Gas Transmission Ltd.

Debentures issued by NOVA Gas Transmission Ltd. (NGTL) in the amount of $225 million 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 to December 31, 2008.

TransCanada PipeLine USA Ltd.

In February 2007, TransCanada PipeLine USA Ltd. established a US$1.0 billion committed, unsecured, syndicated credit facility, consisting of a US$700-million five-year term loan and a US$300-million five-year, extendible revolving facility. There was an outstanding balance of US$700 million and US$860 million on the credit facility at December 31, 2008 and 2007, respectively. In 2008, the maturity date of the revolving portion of the facility was extended to February 2013.

102 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

TC PipeLines, LP

In February 2007, PipeLines LP increased 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. During 2008, an additional US$13 million (2007 – US$18 million) of the senior term loan was terminated due to principal repayments. There was an outstanding balance of US$475 million and US$507 million on the credit facility at December 31, 2008 and 2007, respectively.

Sensitivity

A one per cent change in interest rates would have the following effect assuming all other variables were to remain constant:

(millions of dollars)	Increase		Decrease
Effect on fair value of fixed interest rate debt	(895	)	1,014
Effect on interest expense of variable interest rate debt	2		(2	)

Financial Charges

Year ended December 31 (millions of dollars)	2008		2007		2006
Interest on long-term debt	970		986		849
Interest on junior subordinated notes	68		43		n/a
Interest on short-term debt	51		28		23
Capitalized interest	(141	)	(68	)	(60	)
Amortization and other financial charges(1)	14		(28	)	16
	962		961		828

⁽¹⁾

Amortization and other financial charges in 2008 and 2007 included amortization of transaction costs and debt discounts calculated using the effective interest method.

The Company made interest payments of $869 million in 2008 (2007 – $944 million; 2006 – $771 million).

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 103

NOTE 11    LONG-TERM DEBT OF JOINT VENTURES

			2008		2007
Outstanding loan amounts (millions of dollars)		Maturity Dates	Outstanding December 31(1)	Interest Rate(2)	Outstanding December 31(1)	Interest Rate(2)
NORTHERN BORDER PIPELINE COMPANY
Senior Unsecured Notes
	(2008 – US$225; 2007 – US$232)	2009 to 2021	275	7.7%	229	7.7%
Bank Facility
	(2008 – US$96; 2007 – US$83)	2012	116	3.4%	82	5.3%
IROQUOIS GAS TRANSMISSION SYSTEM, L.P.
Senior Unsecured Notes
	(2008 – US$160; 2007 – US$165)	2010 to 2027	195	7.6%	162	7.5%
Bank Loan
	(2007 – US$7)		–		7	7.4%
BRUCE POWER L.P. AND BRUCE POWER A L.P.
Capital Lease Obligations		2018	235	7.5%	243	7.5%
Term Loan		2031	95	7.1%	n/a
TRANS QUÉBEC & MARITIMES PIPELINE INC.
Bonds		2009 to 2010	137	6.0%	137	6.0%
Term Loan		2011	18	1.9%	28	4.6%
OTHER		2009 to 2010	5	5.5%	15	4.5%
			1,076		903
Less: Current Portion of Long-Term Debt of Joint Ventures			207		30
			869		873

⁽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. Weighted average and effective interest rates are stated as at the respective outstanding dates. At December 31, 2008, the effective interest rate resulting from swap agreements was 4.1 per cent on the Northern Border bank facility (2007 – nil). At December 31, 2007, the effective interest rate resulting from swap agreements was 7.5 per cent on the Iroquois bank loan.

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 of each joint venture is limited to the rights and assets of the joint venture and does not extend to the rights and assets of TCPL, except to the extent of TCPL's investment. 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.

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 for the next five years resulting from maturities and sinking fund obligations of the non-recourse joint venture debt is approximately as follows: 2009 – $194 million; 2010 – $212 million; 2011 – $30 million; 2012 – $126 million; and 2013 – $8 million.

The Company's proportionate share of principal payments for the next five years resulting from the capital lease obligations of Bruce Power is approximately as follows: 2009 – $13 million; 2010 – $13 million; 2011 – $15 million; 2012 – $18 million; and 2013 – $20 million.

In September 2008, Bruce A entered into a $193 million unsecured term loan, maturing December 2031 and bearing interest at 7.12 per cent.

104 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In April 2007, Northern Border established a US$250-million five-year unsecured 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.

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	(39	)	44
Effect on interest expense of variable interest rate debt	1		(1	)

Financial Charges of Joint Ventures

Year ended December 31 (millions of dollars)	2008	2007	2006
Interest on long-term debt	45	50	67
Interest on capital lease obligations	18	18	19
Short-term interest and other financial charges	7	4	3
Deferrals and amortization	2	3	3
	72	75	92

The Company's proportionate share of the interest payments of joint ventures was $50 million in 2008 (2007 – $45 million; 2006 – $73 million).

The Company's proportionate share of interest payments from the capital lease obligations of Bruce Power was $18 million in 2008 (2007 – $18 million; 2006 – $20 million).

NOTE 12    JUNIOR SUBORDINATED NOTES

			2008		2007
Outstanding loan amount (millions of dollars)		Maturity Dates	Outstanding December 31	Effective Interest Rate	Outstanding December 31	Effective Interest Rate
TRANSCANADA PIPELINES LIMITED
	U.S. dollars (2008 and 2007 – US$1,000)	2017	1,213	6.5%	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 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, in whole or in part, upon the occurrence of certain events and at the Company's option 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 a specified formula in accordance with the terms of the Junior Subordinated Notes. The Junior Subordinated Notes were issued under the U.S. debt shelf prospectus filed in March 2007.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 105

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	(45	)	49

NOTE 13    DEFERRED AMOUNTS

December 31 (millions of dollars)	2008	2007
Fair value of derivative contracts (Note 18)	694	205
Regulatory liabilities (Note 14)	551	525
Employee benefit plans (Note 22)	219	196
Asset retirement obligations (Note 21)	114	88
Other	141	93
	1,719	1,107

NOTE 14    REGULATED BUSINESSES

TCPL's regulated businesses include Canadian and U.S. natural gas pipelines. Regulatory assets and liabilities represent future revenues that are expected to be recovered from or refunded to customers. They arise from certain costs and revenues generated in the current period or in prior periods that may be collected from or refunded to shippers if, through the rate-setting process, it is found that revenues were over- or under-collected. Regulatory assets and liabilities are only recognized when approved by the applicable regulatory authorities. In addition to GAAP financial reporting, TCPL's regulated pipelines file financial reports using accounting regulations required by their respective regulators.

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 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 and revenues are more or less than the forecasted costs and revenues, the regulators generally allow the difference to be deferred to a future period and recovered or refunded in rates 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 (Canada). The Alberta System is regulated by the AUC primarily under the provisions of the Gas Utilities Act (Alberta) and the Pipeline Act (Alberta). The AUC regulates the construction and operation of facilities, and the terms and conditions of services, including rates for the Alberta System. 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 natural gas transmission systems. The Alberta System has filed an application with the NEB to change its regulatory jurisdiction from the AUC to the NEB. The NEB's decision is expected in first quarter 2009.

106 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Canadian Mainline

The Canadian Mainline currently operates under a five-year tolls settlement, which is effective January 1, 2007, to December 31, 2011. Canadian Mainline's cost of capital for establishing tolls under the settlement reflects 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. The allowed ROE in 2008 for Canadian Mainline was 8.71 per cent (2007 – 8.46 per cent). The remaining capital structure consists of short- and long-term debt following the agreed-upon redemption of US$460 million of Preferred Securities in 2007.

The settlement also establishes the Canadian Mainline's fixed operations, maintenance and administrative (OM&A) costs for each year of the five years. Any variance between actual OM&A costs and those agreed to in the settlement 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 are treated on a flow-through basis. There are also performance-based incentive arrangements that provide mutual benefits to both TCPL and its customers.

Alberta System

In March 2008, NOVA Gas Transmission Ltd. (NGTL) reached a revenue requirement settlement with interested stakeholders for 2008 and 2009 on the Alberta System. In December 2008, the AUC approved the 2008-2009 Revenue Requirement Settlement Application, which is effective for the full two-year period.

As part of the settlement, fixed costs were established for certain operating costs, ROE and income taxes. Any variances between actual costs and those agreed to in the settlement accrue to TCPL, subject to ROE and income tax adjustment mechanisms. All other costs of the revenue requirement are treated on a flow-through basis.

Other Canadian Pipelines

The NEB approves pipeline tolls on an annual cost of service basis for Foothills and TQM. 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.

The ROE for Foothills, which is based on the NEB-allowed ROE formula, was 8.71 per cent in 2008 (2007 – 8.46 per cent) on a deemed equity component of 36 per cent.

In September 2008, the NEB approved TQM's application for a three-year partial negotiated settlement with interested parties concerning all cost of service matters, with the exception of cost of capital and associated income taxes, for the years 2007 to 2009. In December 2007, TQM filed a cost of capital application with the NEB for the years 2007 and 2008, which requests approval of an 11 per cent return on deemed common equity of 40 per cent. An NEB hearing on the application concluded in October 2008 and a decision from the NEB is expected in early 2009. TQM currently is subject to the 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 Policy 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 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.

GTN

GTN is regulated by the FERC. Both of GTN's natural gas pipeline 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 and its customers reached a rate case settlement in November 2007 that was approved by the FERC in January 2008. GTN's financial results in 2007 reflected the terms of the settlement. In 2008, the GTN System refunded 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 was established during which the GTN System and the settling parties are prohibited from taking

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 107

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 certifying 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 rates currently in effect. The settlement expired October 31, 2005, with no requirement to file for new rates at any time, nor is Great Lakes prohibited from filing such a rate case. Great Lakes' services are provided pursuant to its FERC-approved tariff, which includes, among other factors, maximum and minimum rate levels for services and permits Great Lakes to negotiate or discount rates on a non-discriminatory basis.

Portland

In April 2008, Portland filed a general rate case under the Natural Gas Act of 1938, in accordance with the terms of its previous settlement approved by the FERC in 2003. The proposed tariffs, which included a rate increase of approximately six per cent, became effective September 1, 2008, subject to refund, in accordance with a FERC order dated May 1, 2008. The rate case hearing is scheduled to begin in July 2009.

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. 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 is required to provide services under negotiated and discounted rates on a non-discriminatory basis.

Regulatory Assets and Liabilities

Year ended December 31 (millions of dollars)	2008	2007	Remaining Recovery/ Settlement Period
			(years)
Regulatory Assets
Unrealized losses on derivatives(1)	67	106	1 - 5
Foreign exchange on long-term debt principal(2)	32	34	21
Deferred income tax on carrying costs capitalized during construction of utility plant(3)	26	20	n/a
Unamortized issue costs on Preferred Securities(4)	18	19	18
Phase II preliminary expenditures(5)	16	18	7
Transitional other benefit obligations(6)	15	16	8
Unamortized post-retirement benefits(7)	11	13	3 - 5
Operating and debt-service regulatory assets(8)	–	85	n/a
Other	16	25	n/a
Total Regulatory Assets (Other Assets)	201	336
Regulatory Liabilities
Operating and debt-service regulatory liabilities(8)	234	3	1
Foreign exchange gain on redemption of Preferred Securities, net of income tax of $10 million (2007 – $15 million)(4)	101	150	3
Foreign exchange on long-term debt(9)	70	266	4 - 21
Post-retirement benefits other than pension(10)	58	38	n/a
Unamortized gains on derivatives(1)	24	n/a	4
Fuel tracker(11)	23	29	n/a
Negative salvage(12)	16	17	n/a
Other	25	22	n/a
Total Regulatory Liabilities (Deferred Amounts)	551	525

⁽¹⁾

Unrealized gains and losses on derivatives represent the net position of fair value gains and losses on cross-currency and interest-rate swaps, and forward foreign 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. Pre-tax operating results would have been $63 million higher in 2008 (2007 – $22 million lower) if these amounts had not been recorded as regulatory assets and liabilities.

108 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

⁽²⁾

The foreign exchange on long-term debt principal account in the Alberta System, as approved by the AUC, is designed to facilitate the recovery or refund of foreign exchange gains and losses over the life of the foreign currency debt issues. Realized gains and losses and estimated net future losses on foreign currency debt are 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. Pre-tax operating results would have been $2 million lower in 2008 (2007 – $1 million higher) if these amounts had not been recorded as regulatory assets.

⁽³⁾

Rate-regulated accounting allows the capitalization of both equity and interest components for the carrying costs of funds used during the construction of utility assets. The capitalized 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.

⁽⁴⁾

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 current rate case settlement. In addition, the issue costs on the Preferred Securities will be amortized over 20 years beginning January 1, 2007. 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 if these amounts had not been recorded as regulatory assets. This would have (decreased)/increased 2008 pre-tax operating results by $(54) million and $1 million (2007 – $165 million and $(19) million) related to the foreign exchange gain and issue costs, respectively.

⁽⁵⁾

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 2002 to December 2015. Pre-tax operating results would have been $2 million higher in 2008 (2007 – $2 million higher) if these amounts had not been recorded as regulatory assets.

⁽⁶⁾

The regulatory asset with respect to the annual transitional other benefit obligations is being amortized over 17 years to December 2016, at which time the full transitional obligation will have been recovered through tolls. Pre-tax operating results would have been $1 million higher in 2008 (2007 – $2 million higher) if these amounts had not been recorded as regulatory assets.

⁽⁷⁾

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 through 2011. Pre-tax operating results would have been $3 million higher in 2008 (2007 – $3 million higher) if these amounts had not been recorded as regulatory assets.

⁽⁸⁾

Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances approved by the regulatory authority for inclusion in determining tolls for the immediate following calendar year. Pre-tax operating results would have been $316 million higher in 2008 (2007 – $152 million lower) if these amounts had not been recorded as regulatory assets and liabilities.

⁽⁹⁾

Foreign exchange on long-term debt of the Canadian Mainline, 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 PBOP. This regulatory liability represents the difference between the amount collected in rates and the amount of PBOP expense. No PBOP expense was recorded in 2008 and 2007.

⁽¹¹⁾

ANR's tariff stipulates a fuel tracker mechanism to track over- or under-collections of fuel used and gas lost and 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.

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 at December 31, 2008, this method is also used for accounting purposes. Consequently, future income tax liabilities have not been recognized, as it is expected they will be recovered through future rates when the amounts become payable. 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 would have been recorded at December 31, 2008 and would have been recoverable from future revenues. The liability method of accounting is used for both accounting and toll-making purposes for the U.S. natural gas transmission operations. Under this method, future income tax assets and liabilities are

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 109

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. Effective January 1, 2009, the Company will be adopting policies consistent with FAS 71 to account for its rate-regulated pipelines, as discussed in Note 3.

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)	2008	2007
Non-controlling interest in PipeLines LP	721	539
Non-controlling interest in Portland	84	71
	805	610

The Company's non-controlling interests included in the consolidated income statement are as follows:

Year ended December 31 (millions of dollars)	2008	2007	2006
Non-controlling interest in PipeLines LP	62	65	43
Non-controlling interest in Portland	46	10	13
	108	75	56

The non-controlling interests in PipeLines LP and Portland as at December 31, 2008 represented the 67.9 per cent and 38.3 per cent interest, respectively, not owned by TCPL (2007 – 67.9 per cent and 38.3 per cent, respectively).

TCPL received revenues of $2 million from PipeLines LP in 2008 (2007 – $2 million; 2006 – $1 million) and $7 million from Portland in 2008 (2007 – $7 million; 2006 – $6 million) for services it provided.

NOTE 16    PREFERRED SHARES

December 31	Number of Shares	Dividend Rate Per Share	Redemption Price Per Share	2008	2007
	(thousands)			(millions of dollars)	(millions of dollars)
Cumulative First Preferred Shares
Series U	4,000	$2.80	$50.00	195	195
Series Y	4,000	$2.80	$50.00	194	194
				389	389

The authorized number of preferred shares issuable in series is unlimited. All of the cumulative first preferred shares are without par value.

On or after October 15, 2013, TCPL may redeem the Series U shares at $50 per share and on or after March 5, 2014, TCPL may redeem the Series Y shares at $50 per share.

Dividend Reinvestment and Share Purchase Plan

Commencing in 2007, the Board of Directors of TransCanada authorized the issuance of common shares from treasury at a discount to participants in TransCanada's Dividend Reinvestment and Share Purchase Plan (DRP). Under the DRP, eligible TCPL preferred shareholders may reinvest their dividends and make optional cash payments to obtain additional TransCanada common shares. The discount was set at two per cent commencing with the dividend payable in April 2007 and was increased to three per cent for the dividend payable in January 2009. TransCanada reserves the right to alter the discount or return to purchasing shares on the open market at any time. Prior to the April 2007 dividend, TransCanada purchased shares on the open market and provided them to DRP participants at cost.

110 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 17    COMMON SHARES

		Number of Shares	Amount
		(thousands)	(millions of dollars)
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
	Issued for cash or cash equivalent	66,341	2,419
Outstanding at December 31, 2008		597,890	8,973

Common Shares Issued and Outstanding

The Company is authorized to issue an unlimited number of common shares without par value.

Share Capital

In 2008, TCPL issued 66.3 million common shares to TransCanada for proceeds of approximately $2.4 billion.

In 2007, TCPL issued 48.2 million common shares to TransCanada for proceeds of approximately $1.8 billion.

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, 2008, approximately $1.7 billion (2007 – $1.5 billion) was available for the payment of dividends on common and preferred shares.

NOTE 18    RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

Risk Management Overview

TCPL has exposure to market risk, counterparty credit risk, and liquidity risk. TCPL engages in management activities with the primary objective being to protect earnings, 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 and internal audit personnel. The Board of Directors' Audit Committee oversees how management monitors compliance with risk management policies and procedures, and oversees 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. The Board of Directors also has a Governance Committee that assists in overseeing the risk management activities of TCPL. The Governance Committee monitors, reviews with management and makes recommendations related to TCPL's risk management programs and policies on an ongoing basis.

Market Risk

The Company constructs and invests in large infrastructure projects, purchases and sells commodities, issues short-term 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 exposure to market risk that results from these activities. Derivative 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, of 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 111

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 electricity, natural gas and oil products. A number of strategies are used to mitigate these exposures, including the following:

•

Subject to the Company's overall risk management policies, the Company commits a significant portion of its expected power supply to fixed-price medium-term or long-term sales contracts, while reserving an amount of unsold supply to mitigate price risk in its asset portfolio.

•

The Company purchases a portion of the natural gas and oil products required for its power plants or enters into 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 sales commitments is purchased with contracts or fulfilled through power generation, thereby reducing the Company's exposure to fluctuating commodity prices.

•

The Company enters into offsetting or back-to-back positions and derivative financial instruments to manage price risk exposure in power and natural gas commodities created by certain fixed and variable pricing arrangements for different pricing indices and delivery points.

The Company assesses its commodity contracts and derivative instruments used to manage commodity risk to determine the appropriate accounting treatment. Contracts, with the exception of leases, have been assessed to determine whether they or certain aspects of them 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 expected purchase, sale or usage requirements 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 economically hedging storage capacity with a portfolio of third-party storage capacity contracts and proprietary natural gas purchases and sales. TCPL simultaneously enters into a forward purchase of natural gas for injection into storage and an offsetting forward sale of natural gas for withdrawal at a later period, thereby locking in future positive margins and effectively eliminating exposure to price movements of natural gas. Fair value adjustments recorded each period on proprietary natural gas storage inventory and these forward contracts may not be representative of the amounts that will be realized on settlement.

Natural Gas Inventory Price Risk

At December 31, 2008, $76 million (2007 – $190 million) of proprietary natural gas inventory was included in Inventories. Effective April 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 less selling costs. The Company did not have any proprietary natural gas inventory held in storage prior to April 2007. In 2008, the net change in fair value of proprietary natural gas held in inventory was a net unrealized loss of $7 million (2007 – nil), which was recorded as a decrease to Revenue and Inventory. In 2008, the net change in fair value of natural gas forward purchases and sales contracts was a net unrealized gain of $7 million (2007 – $10 million) which was included in Revenues.

Foreign Exchange and Interest Rate Risk

Foreign exchange and interest rate risk is created by fluctuations in the fair value or cash flow of financial instruments due to changes in foreign exchange rates and/or market interest rates.

A portion of TCPL's earnings from its Pipelines and Energy operations is generated in U.S. dollars and is subject to currency fluctuations. The performance of the Canadian dollar relative to the U.S. dollar can affect TCPL's earnings. This foreign exchange impact is offset by certain related debt and financing costs being denominated in U.S. dollars and by the Company's hedging activities. Due to its increased U.S. operations, TCPL has a greater exposure to U.S. currency 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 debt and other U.S. dollar-denominated transactions, and to manage the interest rate exposure of the Canadian Mainline, Alberta System and Foothills operations. 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.

TCPL 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 this risk.

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 foreign exchange contracts, cross-currency interest rate swaps and foreign exchange options. At December 31, 2008, the Company had designated as a net investment hedge U.S. dollar-denominated debt with a carrying value of $7.2 billion (US$5.9 billion) (2007 – $4.3 billion (US$4.4 billion)) and a fair value of $5.9 billion (US$4.8 billion) (2007 – $4.4 billion (US$4.5 billion)). In January 2009, the Company issued an additional US$2.0 billion of long-term debt and designated it as a hedge of the net U.S. dollar investment in foreign operations. At December 31, 2008, $254 million was included in Deferred Amounts for the fair value of the forwards, swaps and options used to hedge the Company's net U.S. dollar investment in foreign operations.

112 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair values and notional or principal amount for the derivatives designated as a net investment hedge were as follows:

		2008			2007
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)	(218	)	U.S. 1,650	77		U.S. 350
U.S. dollar forward foreign exchange contracts
	(maturing 2009)	(42	)	U.S. 2,152	(4	)	U.S. 150
U.S. dollar options
(maturing 2009)		6		U.S. 300	3		U.S. 600
		(254	)	U.S. 4,102	76		U.S. 1,100

VaR Analysis

TCPL uses a Value-at-Risk (VaR) methodology 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. The VaR methodology is a statistically-calculated, probability-based approach that takes into consideration market volatilities as well as risk diversification by recognizing offsetting positions and correlations among products and markets. Risks are measured across all products and markets, and risk measures are 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. 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 $23 million at December 31, 2008 (2007 – $8 million). The increase from December 31, 2007 was primarily due to the Ravenswood acquisition.

Counterparty Credit Risk

Counterparty credit risk represents the financial loss the Company would experience if a counterparty to a financial instrument failed to meet its obligations in accordance with the terms and conditions of its contracts with the Company.

Counterparty credit risk is managed 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, using 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. The Company believes these measures minimize its counterparty credit risk but there is no certainty that these processes will protect it against all losses.

TCPL's maximum counterparty credit exposure with respect to financial instruments at the balance sheet date consisted primarily of the carrying amount, which approximates fair value, of non-derivative financial assets, such as accounts receivable, as well as the fair value of derivative financial assets.

The Company does not have significant concentrations of counterparty credit risk with any individual counterparties and the majority of counterparty credit exposure is with counterparties who are investment grade. At December 31, 2008, there were no significant amounts past due or impaired.

TCPL has significant credit and performance exposures to financial institutions as they provide committed credit lines and cash deposit facilities, critical liquidity in the foreign exchange derivative, interest rate derivative and energy wholesale markets, and letters of credit to mitigate TCPL's exposure to non-credit worthy counterparties.

During the deterioration of global financial markets in 2008, TCPL continued to closely monitor and reassess the creditworthiness of its counterparties, including financial institutions. This has resulted in TCPL reducing or mitigating its exposure to certain counterparties where it is deemed warranted and permitted under contractual terms. As part of its ongoing operations, TCPL must balance its market risk and counterparty credit risk when making business decisions.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 113

Certain subsidiaries of Calpine Corporation (Calpine) filed for bankruptcy protection in both Canada and the U.S. in 2005. Gas Transmission Northwest Corporation (GTNC) and Portland Natural Gas Transmission System (PNGTS) reached agreements with Calpine for allowed unsecured claims in the Calpine bankruptcy. In February 2008, GTNC and PNGTS received initial distributions of 9.4 million common shares and 6.1 million common shares of Calpine, respectively, which represented approximately 85 per cent of their agreed upon claims. In 2008, these shares were subsequently sold into the open market and resulted in total pre-tax gains of $279 million. Claims by NGTL and Foothills Pipe Lines (South B.C.) Ltd. for $32 million and $44 million, respectively, were received in cash in January 2008 and will be passed on to shippers on these systems. At December 31, 2008, $22 million remained in regulatory liabilities for these claims.

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, under both normal and stressed conditions, it always has sufficient cash and credit facilities to meet its obligations when due, without incurring unacceptable losses or damage to the Company's reputation.

Management forecasts cash flows for a period of 12 months to identify financing requirements. These requirements are then managed through a combination of committed and demand credit facilities and access to capital markets, as discussed under the heading Capital Management in this note.

At December 31, 2008, the Company had committed revolving bank lines of US$1.0 billion, $2.0 billion and US$300 million maturing in November 2010, December 2012 and February 2013, respectively. As of December 31, 2008, no draws were made on these facilities as the Company has continued to have largely uninterrupted access to the Canadian commercial paper market on competitive terms. In January 2009, TCPL filed a new US$3.0 billion debt shelf in the U.S. to supplement the $1.8 billion and $1.0 billion of capacity available under its existing equity and Canadian debt shelves, respectively. The Company has US$1.0 billion of capacity remaining available under its January 2009 U.S. debt shelf.

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, 2008:

Contractual Repayments of Financial Liabilities⁽¹⁾

		Payments Due by Period
(millions of dollars)	Total	2009	2010 and 2011	2012 and 2013	2014 and Thereafter
Notes payable	1,702	1,702	–	–	–
Due to TransCanada Corporation	1,821	1,821	–	–	–
Long-term debt and junior subordinated notes	17,367	786	1,545	2,550	12,486
Long-term debt of joint ventures	1,076	207	270	172	427
Total contractual repayments	21,966	4,516	1,815	2,722	12,913

⁽¹⁾

The anticipated timing of settlement of derivative contracts is presented in the Derivatives Financial Instrument Summary in this Note.

Interest Payments on Financial Liabilities

		Payments Due by Period
(millions of dollars)	Total	2009	2010 and 2011	2012 and 2013	2014 and Thereafter
Due to TransCanada Corporation	92	92	–	–	–
Long-term debt and junior subordinated notes	15,170	1,150	2,151	1,950	9,919
Long-term debt of joint ventures	328	61	76	56	135
Total interest payments	15,590	1,303	2,227	2,006	10,054

Capital Management

The primary objective of capital management is to ensure TCPL has strong credit ratings to support its businesses and maximize shareholder value. In 2008, this overall objective and policy for managing capital remained unchanged from the prior year.

114 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 Shareholders' Equity. Net debt is comprised of Notes Payable, net amounts Due to TransCanada Corporation, Long-Term Debt and Junior Subordinated Notes 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 was as follows:

(millions of dollars)	2008		2007
Notes payable	1,685		41
Due to TransCanada Corporation, net	292		472
Long-term debt	16,154		12,933
Junior subordinated notes	1,213		975
Cash and cash equivalents	(1,109	)	(333	)
Net debt	18,235		14,088
Non-controlling interests	805		610
Shareholders' equity	12,963		10,053
Total equity	13,768		10,663
Total capital	32,003		24,751

Fair Values

The fair value of financial instruments included in Cash and Cash Equivalents, Accounts Receivable, Other Assets, Notes Payable, Accounts Payable, Accrued Interest and Deferred Amounts approximates their carrying amounts due to the nature of the item and/or the short time 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 oil products derivatives has been calculated using quoted market prices where available. In the absence of quoted market prices, third-party broker quotes are used. Credit risk has been taken into consideration when calculating fair values.

Valuation techniques that refer to observable market data or estimated market prices may also be used to calculate fair value. 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, was estimated by discounting future payments of interest and principal at estimated interest rates that were made available to the Company.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 115

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 follows:

	2008		2007
December 31 (millions of dollars)	Carrying Amount	Fair Value	Carrying Amount	Fair Value
Long-Term Debt
TransCanada PipeLines Limited(1)	11,389	10,583	8,519	9,400
NOVA Gas Transmission Ltd.	1,437	1,534	1,508	1,877
TransCanada PipeLine USA Ltd.	857	857	850	850
ANR Pipeline Company	541	570	435	573
Gas Transmission Northwest Corporation	488	393	399	383
TC PipeLines, LP	580	580	499	499
Great Lakes Gas Transmission Limited Partnership	526	496	434	519
Tuscarora Gas Transmission Company	78	80	67	81
Portland Natural Gas Transmission System	236	220	205	214
Other	22	24	17	24
	16,154	15,337	12,933	14,420
Junior Subordinated Notes	1,213	815	975	914
	17,367	16,152	13,908	15,334
Long-Term Debt of Joint Ventures
Northern Border Pipeline Company	391	391	311	329
Iroquois Gas Transmission System, L.P.	195	181	169	180
Bruce Power L.P. and Bruce Power A L.P.	330	318	243	243
Trans Québec & Maritimes Pipeline Inc.	155	157	165	169
Other	5	5	15	16
	1,076	1,052	903	937
	18,443	17,204	14,811	16,271

⁽¹⁾

At December 31, 2008, the carrying amount of Long-Term Debt included $15 million (2007 – $15 million) for fair value adjustments related to swap agreements on $50 million (2007 – $150 million) and US$200 million (2007 – US$200 million) of this debt.

Non-Derivative Financial Instruments Summary

The carrying and fair values of non-derivative financial instruments were as follows:

	2008		2007
December 31 (millions of dollars)	Carrying Amount	Fair Value	Carrying Amount	Fair Value
Financial Assets(1)
Cash and cash equivalents	1,300	1,300	504	504
Accounts receivable and other assets(2)(3)	1,404	1,404	1,231	1,231
Due from TransCanada Corporation	1,529	1,529	1,407	1,407
Available-for-sale assets(2)	27	27	17	17
	4,260	4,260	3,159	3,159
Financial Liabilities(1)(3)
Notes payable	1,702	1,702	55	55
Accounts payable and deferred amounts(4)	1,364	1,364	1,192	1,192
Accrued interest	361	361	265	265
Due to TransCanada Corporation	1,821	1,821	1,879	1,879
Long-term debt and junior subordinated notes	17,367	16,152	13,908	15,334
Long-term debt of joint ventures	1,076	1,052	903	937
Other long-term liabilities of joint ventures(4)	–	–	60	60
	23,691	22,452	18,262	19,722

116 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

⁽¹⁾

Consolidated Net Income in 2008 and 2007 included unrealized gains or losses of nil for the fair value adjustments to each of these financial instruments.

⁽²⁾

At December 31, 2008, the Consolidated Balance Sheet included financial assets of $1,257 million (2007 – $1,018 million) in Accounts Receivable and $174 million (2007 – $230 million) in Other Assets.

⁽³⁾

Recorded at amortized cost, except for certain Long-Term Debt which is adjusted to fair value.

⁽⁴⁾

At December 31, 2008, the Consolidated Balance Sheet included financial liabilities of $1,342 million (2007 – $1,174 million) in Accounts Payable and $22 million (2007 – $78 million) in Deferred Amounts.

Derivative Financial Instruments Summary

Information for the Company's derivative financial instruments is as follows:

			2008
December 31 (all amounts in millions unless otherwise indicated)			Power		Natural Gas		Oil Products		Foreign Exchange		Interest
Derivative Financial Instruments Held for Trading
Fair Values(1)
	Assets		$132		$144		$10		$41		$57
	Liabilities		$(82	)	$(150	)	$(10	)	$(55	)	$(117	)
Notional Values
	Volumes(2)
		Purchases	4,035		172		410		–		–
		Sales	5,491		162		252		–		–
	Canadian dollars		–		–		–		–		1,016
	U.S. dollars		–		–		–		U.S. 479		U.S. 1,575
	Japanese yen (in billions)		–		–		–		JPY 4.3		–
	Cross-currency		–		–		–		227/U.S. 157		–
Net unrealized gains/(losses) in the year(3)			$24		$(23	)	$1		$(9	)	$(61	)
Net realized gains/(losses) in the year(3)			$23		$(2	)	$1		$6		$13
Maturity dates			2009 - 2014		2009 - 2011		2009		2009 - 2012		2009 - 2018
Derivative Financial Instruments in Hedging Relationships(4)(5)
Fair Values(1)
	Assets		$115		$–		$–		$2		$8
	Liabilities		$(160	)	$(18	)	$–		$(24	)	$(122	)
Notional Values
	Volumes(2)
		Purchases	8,926		9		–		–		–
		Sales	13,113		–		–		–		–
	Canadian dollars		–		–		–		–		50
	U.S. dollars		–		–		–		U.S. 15		U.S. 1,475
	Cross-currency		–		–		–		136/U.S. 100		–
Net realized (losses)/gains in the year(3)			$(56	)	$15		$–		$–		$(10	)
Maturity dates			2009 - 2014		2009 - 2011		–		2009 - 2013		2009 - 2019

⁽¹⁾

Fair value is equal to the carrying value of these derivatives.

⁽²⁾

Volumes for power, natural gas and oil products derivatives are in gigawatt hours, billion cubic feet and thousands of barrels, respectively.

⁽³⁾

All power, natural gas and oil products realized and unrealized gains and losses are included in Revenues. All interest rate and foreign exchange realized and unrealized gains and losses are included in Financial Charges and Interest Income and Other, respectively. Realized gains and losses are included in Net Income upon settlement of the financial instrument.

⁽⁴⁾

All hedging relationships are designated as cash flow hedges except for interest-rate derivative financial instruments designated as fair value hedges with a fair value of $8 million. In 2008, the Company did not record any amounts in Net Income related to ineffectiveness for fair value hedges.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 117

⁽⁵⁾

In 2008, Net Income included losses of $6 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. In 2008, there were no gains or losses included in Net Income for discontinued cash flow hedges.

The anticipated timing of settlement of the derivative contracts assumes no changes in commodity prices, interest rates and foreign exchange rates from December 31, 2008. Actual settlements will vary based on changes in these factors. The anticipated timing of settlement of these contracts is as follows:

(millions of dollars)	Total		2009		2010 and 2011		2012 and 2013		2014 and Thereafter
Derivative financial instruments held for trading	(30	)	38		(46	)	(14	)	(8	)
Derivative financial instruments in hedging relationships	(199	)	(68	)	(65	)	(43	)	(23	)
	(229	)	(30	)	(111	)	(57	)	(31	)

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		–
Net unrealized gains/(losses) in the year(3)			$16		$(10	)	$8		$(5	)
Net realized(losses)/gains in the year(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		–
Net realized (losses)/gains in the year(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 power and natural gas realized and unrealized gains and losses are included in Revenues. All interest rate and foreign exchange realized and unrealized gains and losses are included in Financial Charges and Interest Income and Other, respectively. Realized gains and losses are included in Net Income upon settlement of the financial instrument.

118 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

⁽⁴⁾

All hedging relationships are designated as cash flow hedges except for interest rate derivative financial instruments designated as fair value hedges with a fair value of $2 million. In 2007, the Company did not record any amounts in Net Income related to ineffectiveness for fair value hedges.

⁽⁵⁾

In 2007, Net Income 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. In 2007, Net Income 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 when the anticipated transaction was not likely to occur by the end of the originally specified time period.

Balance Sheet Presentation of Derivative Financial Instruments

The fair value of the derivative financial instruments in the Company's Balance Sheet was as follows:

December 31 (millions of dollars)		2008		2007
Current
	Other current assets	318		160
	Accounts payable	(298	)	(144	)
Long-term
	Other assets	191		204
	Deferred amounts	(694	)	(205	)

Derivative Financial Instruments of Joint Ventures

Included in the Balance Sheet Presentation of Derivative Financial Instruments table above are amounts related to power derivatives used by one 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, 2008 (2007 – $75 million). These contracts mature from 2009 to 2014. The Company's proportionate share of the notional sales volumes of power associated with this exposure was 7,600 gigawatt hours (GWh) at December 31, 2008 (2007 – 7,300 GWh). The Company's proportionate share of the notional purchased volumes of power associated with this exposure was 47 GWh at December 31, 2008 (2007 – 50 GWh).

NOTE 19    INCOME TAXES

Provision for Income Taxes

Year ended December 31 (millions of dollars)	2008		2007	2006
Current
Canada	381		364	263
Foreign	143		65	37
	524		429	300
Future
Canada	(10	)	8	104
Foreign	77		46	71
	67		54	175
	591		483	475

Geographic Components of Income

Year ended December 31 (millions of dollars)	2008	2007	2006
Canada	1,203	1,208	1,158
Foreign	938	582	444
Income from continuing operations before income taxes and non-controlling interests	2,141	1,790	1,602

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 119

Reconciliation of Income Tax Expense

Year ended December 31 (millions of dollars)	2008		2007		2006
Income from continuing operations before income taxes and non-controlling interests	2,141		1,790		1,602
Federal and provincial statutory tax rate	29.5%		32.1%		32.5%
Expected income tax expense	632		575		521
Income tax differential related to regulated operations	44		69		72
Lower effective foreign tax rates	(5	)	(39	)	n/a
Tax rate and legislated changes	–		(73	)	(33	)
Income from equity investments and non-controlling interests	(45	)	(34	)	(27	)
Change in valuation allowance	(9	)	–		–
Other(1)	(26	)	(15	)	(58	)
Actual income tax expense	591		483		475

⁽¹⁾

Includes net income tax benefits of $7 million recorded in 2008 (2007 – $13 million; 2006 – $51 million) on the resolution of certain income tax matters with taxation authorities and changes in estimates.

Future Income Tax Assets and Liabilities

December 31 (millions of dollars)	2008	2007
Deferred amounts	119	43
Other post-employment benefits	69	57
Unrealized losses on derivatives	62	22
Unrealized foreign exchange losses on long-term debt	77	n/a
Non-capital loss carryforwards	24	n/a
Other	107	63
	458	185
Less: valuation allowance(1)	77	13
Future income tax assets, net of valuation allowance	381	172
Difference in accounting and tax bases of plant, equipment and PPAs	1,464	1,073
Investments in subsidiaries and partnerships	28	61
Pension benefits	55	50
Unrealized foreign exchange gains on long-term debt	14	110
Unrealized gains on derivatives	19	27
Other	54	44
Future income tax liabilities	1,634	1,365
Net future income tax liabilities	1,253	1,193

⁽¹⁾

A valuation allowance was recorded in 2008 as there is no virtual certainty that the Company will realize the tax benefit related to the unrealized foreign exchange losses on long-term debt in the future.

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 $102 million at December 31, 2008 (2007 – $72 million) if there had been a provision for these taxes.

Income Tax Payments

Income tax payments of $486 million were made during the year ended December 31, 2008 (2007 – $440 million; 2006 – $494 million).

120 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 20    NOTES PAYABLE

	2008		2007
	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	1,250	1.8%	55	5.0%
U.S. dollars (2008 –  US$369)	452	3.3%	–	–
	1,702		55

Notes payable consists of commercial paper outstanding and drawings on bridge and line-of-credit facilities. Unsecured revolving and demand credit facilities totaled $4.2 billion at December 31, 2008 to support the Company's commercial paper program and for general corporate purposes. These credit facilities included the following:

•

a $2.0 billion committed, syndicated, revolving credit facility maturing December 2012, which was fully available at December 31, 2008. The cost to maintain the credit facility was $2 million in 2008 (2007 – $2 million).



•

a US$300 million syndicated, revolving facility, maturing February 2013, which was fully available at December 31, 2008. This facility is part of the US$1.0 billion committed, unsecured TransCanada PipeLine USA Ltd. credit facility established in February 2007.



•

a US$1.0 billion committed, extendible, expandable, revolving, unsecured, one-year agreement executed by TransCanada Keystone Pipeline L.P. in fourth quarter 2008 with a syndicate of banks, bearing interest at a floating rate, based on the greater of bank prime interest rates and LIBOR, plus a margin of not less than one per cent and not more than three per cent on revolving loans and not less than three per cent and not more than 6.5 per cent if drawn as a term loan. The agreement is extendible at the option of the Keystone partnership for an additional one-year term. As at December 31, 2008, this facility was fully available. This US$1.0 billion agreement is guaranteed by TCPL.



•

demand lines totaling $611 million, which support the issuance of letters of credit and provide additional liquidity. The Company had used approximately $433 million of its total lines of credit for letters of credit at December 31, 2008. 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.

In June 2008, TCPL executed an agreement with a syndicate of banks for a US$1.5 billion, committed, unsecured, one-year bridge loan facility, at a floating interest rate based on LIBOR plus 30 basis points. The facility is extendible at the option of the Company for an additional six-month term at LIBOR plus 35 basis points. In August 2008, the Company used US$255 million from this facility and cancelled the remainder of the commitment. At December 31, 2008, US$255 million remained outstanding on the facility.

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 $69 million at December 31, 2008 (2007 – $65 million), calculated using an inflation rate ranging from two per cent to four per cent per annum. The estimated fair value of these liabilities was $31 million at December 31, 2008 (2007 – $25 million) after discounting the estimated cash flows at rates ranging from 5.4 per cent to 8.0 per cent. At December 31, 2008, the expected timing of payment for settlement of the obligations ranged from one year to 27 years. Management believes it is reasonable to assume that all retirement costs associated with its regulated pipelines will be recovered through future tolls and, therefore, typically only records asset retirement obligations for its non-regulated pipelines.

The estimated undiscounted cash flows required to settle the asset retirement obligations with respect to the Energy segment were $427 million at December 31, 2008 (2007 – $216 million), calculated using an inflation rate ranging from two per cent to three per cent per annum. The estimated fair value of this liability was $85 million at December 31, 2008 (2007 – $63 million), after discounting the estimated cash flows at rates ranging from 5.4 per cent to 8.0 per cent. At December 31, 2008, the expected timing of payment for settlement of the obligations ranged from 10 years to 33 years.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 121

Reconciliation of Asset Retirement Obligations⁽¹⁾

(millions of dollars)	Pipelines	Energy	Total
Balance at January 1, 2006	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
New obligations and revisions in estimated cash flows	4	18	22
Accretion expense	2	4	6
Balance at December 31, 2008	31	85	116

⁽¹⁾

At December 31, 2008, Asset Retirement Obligations totalling $114 million (2007 – $88 million) and $2 million (2007 – nil) were included in Deferred Amounts and Accounts Payable, respectively.

NOTE 22    EMPLOYEE FUTURE BENEFITS

The Company sponsors DB Plans that cover substantially all employees. Pension 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 in the Canadian pension plan 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 nine years.

Effective January 1, 2008, the Company also provides its employees with a Savings Plan in Canada, a 401(k) Plan in the U.S. 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 11 years at December 31, 2008. Contributions to the Savings Plan and 401(k) Plan are expensed as incurred.

Total cash payments for employee future benefits, consisting of cash contributed by the Company to the DB Plans and other benefit plans, was $90 million in 2008 (2007 – $61 million; 2006 – $104 million), including $21 million in 2008 (2007 – $8 million; 2006 – $2 million) related to retirement savings plans.

122 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company measures its accrued benefit obligations and the fair value of plan assets for accounting purposes as at December 31 of each year. The most recent actuarial valuation of the pension plans for funding purposes was as at January 1, 2009, and the next required valuation will be as at January 1, 2010.

		Pension Benefit Plans				Other Benefit Plans
(millions of dollars)		2008		2007		2008		2007
Change in Benefit Obligation
	Benefit obligation – beginning of year	1,462		1,378		155		132
	Current service cost	52		45		2		2
	Interest cost	80		73		8		7
	Employee contributions	3		4		1		–
	Benefits paid	(68	)	(65	)	(8	)	(7	)
	Actuarial (gain)/loss	(261	)	(22	)	(21	)	8
	Foreign exchange rate changes	35		(16	)	10		(6	)
	Plan amendment	–		–		(11	)	–
	Acquisition	29		65		8		19
	Benefit obligation – end of year	1,332		1,462		144		155
Change in Plan Assets
	Plan assets at fair value – beginning of year	1,358		1,264		30		33
	Actual return on plan assets	(222	)	33		(10	)	2
	Employer contributions	62		46		7		7
	Employee contributions	3		4		1		–
	Benefits paid	(68	)	(65	)	(8	)	(7	)
	Foreign exchange rate changes	32		(17	)	6		(5	)
	Acquisition	28		93		–		–
	Plan assets at fair value – end of year	1,193		1,358		26		30
Funded status – plan deficit		(139	)	(104	)	(118	)	(125	)
Unamortized net actuarial loss		340		299		33		44
Unamortized past service costs		25		28		(1	)	7
Accrued benefit asset/(liability), net of valuation allowance of nil		226		223		(86	)	(74	)

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)	2008	2007	2008		2007
Other Assets	226	223	–		5
Deferred Amounts	–	–	(86	)	(79	)
Total	226	223	(86	)	(74	)

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)	2008		2007		2008		2007
Benefit obligation	(1,317	)	(1,324	)	(144	)	(155	)
Plan assets at fair value	1,178		1,198		26		30
Funded status – plan deficit	(139	)	(126	)	(118	)	(125	)

The Company's expected contributions in 2009 are approximately $140 million for the pension benefit plans and approximately $27 million for the other benefit plans.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 123

The following are estimated future benefit payments, which reflect expected future service:

(millions of dollars)	Pension Benefits	Other Benefits
2009	77	8
2010	81	9
2011	84	9
2012	88	10
2013	91	10
2014 to 2018	510	59

The significant weighted average actuarial assumptions adopted in measuring the Company's benefit obligations at December 31 were as follows:

	Pension Benefit Plans		Other Benefit Plans
	2008	2007	2008	2007
Discount rate	6.65%	5.30%	6.50%	5.50%
Rate of compensation increase	3.65%	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 follows:

	Pension Benefit Plans			Other Benefit Plans
	2008	2007	2006	2008	2007	2006
Discount rate	5.30%	5.05%	5.00%	5.50%	5.20%	5.15%
Expected long-term rate of return on plan assets	6.95%	6.90%	6.90%	7.75%	7.75%	7.75%
Rate of compensation increase	3.60%	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 considered in determining 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 2009 measurement purposes. The rate was assumed to decrease gradually to five per cent in 2018 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	11	(10	)

124 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company's net benefit cost is as follows:

	Pension Benefit Plans						Other Benefit Plans
Year ended December 31 (millions of dollars)	2008		2007		2006		2008		2007		2006
Current service cost	52		45		39		2		2		3
Interest cost	80		73		65		8		7		8
Actual return on plan assets	222		(33	)	(134	)	10		(2	)	(6	)
Actuarial (gain)/loss	(261	)	(22	)	53		(21	)	8		(2	)
Plan amendment	–		–		–		(11	)	–		(18	)
Elements of net benefit cost prior to adjustments to recognize the long-term nature of net benefit cost	93		63		23		(12	)	15		(15	)
Difference between expected and actual return on plan assets	(316	)	(51	)	63		(12	)	(1	)	4
Difference between actuarial loss/(gain) recognized and actual actuarial loss/(gain) on accrued benefit obligation	280		47		(27	)	23		(7	)	4
Difference between amortization of past service costs and actual plan amendments	4		4		4		11		–		19
Amortization of transitional obligation related to regulated business	–		–		–		2		2		2
Net benefit cost recognized	61		63		63		12		9		14

The Company pension plans' weighted average asset allocations and target allocations by asset category were as follows:

December 31	Percentage of Plan Assets		Target Allocations
Asset Category	2008	2007	2008
Debt securities	48%	42%	35% to 60%
Equity securities	52%	58%	40% to 65%
	100%	100%

Debt securities included the Company's debt of $3 million (0.3 per cent of total plan assets) and $4 million (0.3 per cent of total plan assets) at December 31, 2008 and 2007, respectively. Equity securities included the Company's common shares of $4 million (0.3 per cent of total plan assets) and $6 million (0.4 per cent of total plan assets) at December 31, 2008 and 2007, respectively.

The assets of the pension plans are managed on a going concern basis subject to legislative restrictions. The plans' investment policies are to maximize returns within an acceptable risk tolerance. Pension assets are invested in a diversified manner with consideration given to the demographics of the plans' participants.

Employee Future Benefits of Joint Ventures

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 accompanying 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 $42 million in 2008 (2007 – $34 million; 2006 – $25 million).

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 125

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, 2009, and the next required valuations will be as at January 1, 2010.

		Pension Benefit Plans				Other Benefit Plans
(millions of dollars)		2008		2007		2008		2007
Change in Benefit Obligation
	Benefit obligation – beginning of year	789		807		165		169
	Current service cost	27		28		8		10
	Interest cost	42		40		9		8
	Employee contributions	6		5		–		–
	Benefits paid	(37	)	(23	)	(4	)	(2	)
	Actuarial gain	(229	)	(34	)	(45	)	(16	)
	Foreign exchange rate changes	1		(3	)	–		–
	Acquisition	–		(31	)	–		(2	)
	Plan amendment	–		–		–		(2	)
	Benefit obligation – end of year	599		789		133		165
Change in Plan Assets
	Plan assets at fair value – beginning of year	626		666		–		–
	Actual return on plan assets	(78	)	(1	)	–		–
	Employer contributions	38		32		4		2
	Employee contributions	6		5		–		–
	Benefits paid	(37	)	(23	)	(4	)	(2	)
	Foreign exchange rate changes	1		(5	)	–		–
	Acquisition	–		(48	)	–		–
	Plan assets at fair value – end of year	556		626		–		–
Funded status – plan deficit		(43	)	(163	)	(133	)	(165	)
Unamortized net actuarial loss/(gain)		51		169		(3	)	45
Unamortized past service costs		–		–		3		3
Accrued benefit asset/(liability), net of valuation allowance of nil		8		6		(133	)	(117	)

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)	2008	2007	2008		2007
Other Assets	8	6	–		–
Deferred Amounts	–	–	(133	)	(117	)
Total	8	6	(133	)	(117	)

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)	2008		2007		2008		2007
Benefit obligation	(594	)	(786	)	(133	)	(165	)
Plan assets at fair value	551		623		–		–
Funded status – plan deficit	(43	)	(163	)	(133	)	(165	)

The expected total contributions of the Company's joint ventures in 2009 are approximately $37 million for the pension benefit plans and approximately $4 million for the other benefit plans.

126 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following are estimated future benefit payments, which reflect expected future service:

(millions of dollars)	Pension Benefits	Other Benefits
2009	39	4
2010	43	5
2011	46	6
2012	50	7
2013	54	7
2014 to 2018	325	49

The significant weighted average actuarial assumptions adopted in measuring the benefit obligations of the Company's joint ventures at December 31 were as follows:

	Pension Benefit Plans		Other Benefit Plans
	2008	2007	2008	2007
Discount rate	6.70%	5.25%	6.40%	5.15%
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 follows:

	Pension Benefit Plans			Other Benefit Plans
	2008	2007	2006	2008	2007	2006
Discount rate	5.25%	5.00%	5.25%	5.15%	4.90%	5.15%
Expected long-term rate of return on plan assets	7.00%	7.00%	7.30%
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	3	(2	)
Effect on post-employment benefit obligation	17	(14	)

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)	2008		2007		2006		2008		2007		2006
Current service cost	27		28		24		8		10		7
Interest cost	42		40		37		9		8		5
Actual return on plan assets	78		1		(68	)	–		–		–
Actuarial (gain)/loss	(229	)	(34	)	77		(45	)	(16	)	72
Plan amendment	–		–		–		–		(2	)	6
Elements of net benefit cost prior to adjustments to recognize the long-term nature of net benefit cost	(82	)	35		70		(28	)	–		90
Difference between expected and actual return on plan assets	(122	)	(44	)	26		–		–		–
Difference between actuarial loss/(gain) recognized and actual actuarial loss/(gain) on accrued benefit obligation	239		44		(70	)	48		20		(72	)
Difference between amortization of past service costs and actual plan amendments	–		–		–		–		3		(6	)
Net benefit cost recognized related to joint ventures	35		35		26		20		23		12

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 127

The weighted average asset allocations and target allocations by asset category in the pension plans of the Company's joint ventures were as follows:

December 31	Percentage of Plan Assets		Target Allocations
Asset Category	2008	2007	2008
Debt securities	44%	43%	40%
Equity securities	56%	57%	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, 2008 and 2007, respectively. Equity securities included the Company's common shares of $3 million (0.6 per cent of total plan assets) and $3 million (0.5 per cent of total plan assets) at December 31, 2008 and 2007, 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)	2008		2007		2006
(Increase)/decrease in accounts receivable	(126	)	49		(186	)
Decrease/(increase) in inventories	82		(6	)	(108	)
(Increase)/decrease in other current assets	(146	)	118		(6	)
(Decrease)/increase in accounts payable	(100	)	64		(41	)
Increase/(decrease) in accrued interest	102		(10	)	41
	(188	)	215		(300	)

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 and equipment are approximately as follows:

Year ended December 31 (millions of dollars)	Minimum Lease Payments	Amounts Recoverable under Sub-leases		Net Payments
2009	40	(12	)	28
2010	39	(12	)	27
2011	39	(10	)	29
2012	38	(5	)	33
2013	37	(4	)	33
2014 and thereafter	260	(7	)	253
Total	453	(50	)	403

The operating lease agreements for premises, services and equipment expire at various dates through 2035, with an option to renew certain lease agreements for periods of one year to ten years. Net rental expense on operating leases in 2008 was $52 million (2007 – $34 million; 2006 – $25 million).

128 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

TCPL's commitments under the acquired 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 factors. The amount of power purchased under the PPAs in 2008 was $471 million (2007 – $440 million; 2006 – $499 million). The generating capacities and expiry dates of the PPAs are as follows:

	Megawatts	Expiry Date
Sundance A	560	December 31, 2017
Sundance B	353	December 31, 2020
Sheerness	756	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 three-year period ending December 31, 2011, are as follows:

Year ended December 31 (millions of dollars)
2009	204
2010	49
2011	2
	255

Loan – 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. The project would result in a natural gas pipeline being constructed from Inuvik, Northwest Territories, to the northern border of Alberta, where it would connect with the Alberta System. Under the agreement, TCPL agreed to finance the APG for its one-third share of project pre-development costs. These costs, on a cumulative basis, are currently forecast to be between $150 million and $200 million, depending upon the pace of project development. As at December 31, 2008, the Company had advanced $140 million to the APG.

TCPL and the other co-venture companies involved in the MGP continue to pursue approval of the proposed project, focusing on obtaining regulatory approval and the Canadian government's support of an acceptable fiscal framework. Detailed discussions with the Canadian government are continuing, and project timing continues to be uncertain. In the event the co-venture group is unable to reach an agreement with the government on an acceptable fiscal framework, the parties will need to determine the appropriate next steps for the project, including a review by TCPL of the carrying value of advances to the APG.

Other Commitments

TCPL is committed to capital expenditures totalling approximately $2.3 billion related to its share of the construction costs of Keystone, North Central Corridor and other pipeline projects.

The Company is committed to capital expenditures totalling approximately $1.0 billion related to its share of the construction costs of Coolidge, Bruce Power, the remaining Cartier Wind projects, Halton Hills and Portlands Energy.

Contingencies

On April 3, 2008, the Ontario Court of Appeal dismissed an appeal filed by the Canadian Alliance of Pipeline Landowners' Associations (CAPLA). CAPLA filed the appeal as a result of a decision by the Ontario Superior Court in November 2006 to dismiss CAPLA's class action lawsuit against TCPL and Enbridge Inc. for damages 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. The Ontario Court of Appeal's decision is final and binding as CAPLA did not seek any further appeal within the time frame allowed.

TCPL is subject to laws and regulations governing environmental quality and pollution control. At December 31, 2008, the Company accrued approximately $83 million related to operating facilities and $3 million related to discontinued operation sites. The accrued amount represents the Company's estimate of the amount it expects to expend to remediate the sites. However, additional liabilities may be incurred as assessments occur and remediation efforts continue.

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 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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 129

ranging from one year ending in 2010 to perpetuity. In addition, TCPL and BPC have 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 provided as part of the reorganization of Bruce Power in 2005 and have terms ending in 2019. TCPL's share of the potential exposure under these Bruce A and Bruce B guarantees was estimated at December 31, 2008 to range from $711 million to a maximum of $750 million. The fair value of these guarantees is estimated to be $17 million.

The Company and its partners in certain jointly owned entities have severally as well as jointly and severally guaranteed the financial 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, 2008 to range from $688 million to a maximum of $1.4 billion. 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 $9 million for the fair value of these joint and several guarantees.

TCPL has guaranteed a subsidiary's equity undertaking to support the payment, under certain conditions, of principal and interest on US$43 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 would 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.

NOTE 25    RELATED PARTY TRANSACTIONS

The following amounts are included in Due from TransCanada Corporation:

		2008		2007
(millions of dollars)	Maturity Dates	Outstanding December 31	Interest Rate	Outstanding December 31	Interest Rate
Discount Notes	2009	1,529	2.1%	1,226	4.8%
Promissory Notes(1)		–		181
		1,529		1,407

⁽¹⁾

Payable on demand and non-interest bearing.

The following amounts are included in Due to TransCanada Corporation:

		2008		2007
(millions of dollars)	Maturity Dates	Outstanding December 31	Interest Rate	Outstanding December 31	Interest Rate
Credit Facility(1)	2009	1,621	5.3%	1,307	5.5%
Credit Facility(2)		200	4.8%	207	6.0%
Promissory Notes (2007 – US$370)(3)		–	–	365	5.6%
		1,821		1,879

⁽¹⁾

TransCanada established a $2.5 billion, unsecured credit facility agreement with TCPL, bearing interest at the Reuters prime rate or Bankers' Acceptance rate plus 65 basis points, at TCPL's option. The funds advanced under this agreement can be used to repay indebtedness or to make partner contributions to Bruce A, or for working capital and general corporate purposes. At December 31, 2008, $1.6 billion was outstanding under this credit facility (2007 – $1.3 billion). This credit agreement matures on December 15, 2009.

⁽²⁾

In May 2003, TCPL established a demand revolving credit facility with TransCanada for general corporate purposes at $500 million, or a U.S. dollar equivalent amount, bearing interest at the Royal Bank of Canada prime rate per annum or the U.S. base rate per annum. In May 2008, $7 million was repaid to TransCanada.

⁽³⁾

In February 2007, TCPL issued a promissory note to TransCanada for US$700 million bearing interest at LIBOR plus 32.5 basis points, due on or before February 9, 2008. The US$370 million outstanding at December 31, 2007 was fully repaid on January 7, 2008.

In 2008, Financial Charges included $76 million (2007 – $72 million) of interest expense and $55 million (2007 – $30 million) of interest income as a result of transactions with TransCanada. At December 31, 2008, Accounts Payable included $2 million of interest payable to TransCanada (2007 – $5 million).

NOTE 26    DISCONTINUED OPERATIONS

The $28 million income from discontinued operations in 2006 reflected settlements received from bankruptcy claims related to TCPL's Gas Marketing business, which was sold in 2001.

130 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NINE-YEAR FINANCIAL HIGHLIGHTS

(millions of dollars except where indicated)			2008		2007		2006		2005		2004		2003		2002		2001		2000
Income Statement
Revenues			8,619		8,828		7,520		6,124		5,497		5,636		5,225		5,285		4,384
Net income from continuing operations			1,442		1,232		1,071		1,230		1,000		823		769		708		663
Net income/(loss) by segment
		Pipelines	902		686		560		679		584		625		639		572		613
		Energy	614		514		452		566		398		217		160		181		95
		Corporate	(96	)	10		37		(37	)	(4	)	(41	)	(52	)	(67	)	(80	)
	Continuing operations		1,420		1,210		1,049		1,208		978		801		747		686		628
	Discontinued operations		–		–		28		–		52		50		–		(67	)	61
Net income applicable to common shares			1,420		1,210		1,077		1,208		1,030		851		747		619		689
Cash Flow Statement
Funds generated from operations			2,992		2,603		2,374		1,950		1,701		1,822		1,843		1,625		1,484
(Increase)/decrease in operating working capital			(188	)	215		(300	)	(48	)	28		93		92		(487	)	437
Net cash provided by operations			2,804		2,818		2,074		1,902		1,729		1,915		1,935		1,138		1,921
Capital expenditures and acquisitions			(6,363	)	(5,874	)	(2,042	)	(2,071	)	(2,046	)	(965	)	(851	)	(1,082	)	(1,144	)
Disposition of assets, net of current income taxes			28		35		23		671		410		–		–		1,170		2,233
Cash dividends paid on common and preferred shares			(817	)	(725	)	(639	)	(608	)	(574	)	(532	)	(488	)	(440	)	(458	)
Balance Sheet
Assets
Plant, property and equipment
	Pipelines		20,700		18,280		17,141		16,528		17,306		16,064		16,158		16,562		16,937
	Energy		8,435		5,127		4,302		3,483		1,421		1,368		1,340		1,116		776
	Corporate		54		45		44		27		37		50		64		66		111
Total assets
	Continuing operations		40,935		31,737		26,386		24,113		22,414		20,873		20,416		20,255		20,238
	Discontinued operations		–		–		–		–		7		11		139		276		5,007
Total assets			40,935		31,737		26,386		24,113		22,421		20,884		20,555		20,531		25,245
Capitalization
Long-term debt			15,368		12,377		10,887		9,640		9,749		9,516		8,899		9,444		10,008
Junior subordinated notes			1,213		975		–		–		–		–		–		–		–
Preferred securities			–		–		536		536		554		598		944		950		1,208
Non-controlling interests			805		610		366		394		311		324		288		286		257
Preferred shares			389		389		389		389		389		389		389		389		389
Common shareholders' equity			12,574		9,664		7,618		7,164		6,484		6,044		5,747		5,426		5,211

SUPPLEMENTARY INFORMATION 131

		2008	2007	2006	2005	2004	2003	2002	2001		2000
Per Common Share Data (dollars)
Net income – Basic
	Continuing operations	$2.59	$2.33	$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
		$2.59	$2.33	$2.23	$2.50	$2.14	$1.77	$1.56	$1.30		$1.45
Net income – Diluted
	Continuing operations	$2.59	$2.33	$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
		$2.59	$2.33	$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		$2.80
Series Y Cumulative First Preferred Shares		$2.80	$2.80	$2.80	$2.80	$2.80	$2.80	$2.80	$2.80		$2.80
Financial Ratios
Earnings to fixed charges(1)		2.7	2.6	2.6	2.9	2.5	2.3	2.3	2.1		1.9

⁽¹⁾

The earnings to fixed charges ratio is determined by dividing earnings by fixed charges. Earnings is calculated as the sum of income from continuing operations, financial charges, financial charges of joint ventures, income taxes, income from non-controlling interests (excluding non-controlling interests with financial charges) and adjusted for undistributed earnings of investments accounted for by the equity method. Fixed charges is calculated as the sum of financial charges, financial charges of joint ventures and capitalized interest.

132 SUPPLEMENTARY INFORMATION

TRANSCANADA PIPELINES LIMITED

RECONCILIATION TO UNITED STATES GAAP

December 31, 2008

AUDITORS' REPORT ON RECONCILIATION TO UNITED STATES GAAP

To the Board of Directors of TransCanada PipeLines Limited

On February 23, 2009, we reported on the consolidated balance sheets of TransCanada PipeLines Limited as at December 31, 2008 and 2007, 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, 2008, 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" as 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 23, 2009

2

TRANSCANADA PIPELINES LIMITED
RECONCILIATION TO UNITED STATES GAAP

        The 2008 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 significant differences between Canadian and U.S. GAAP on the Company's consolidated financial statements for the years ended December 31, 2008, 2007 and 2006 are described below and should be read in conjunction with TCPL's audited consolidated financial statements prepared in accordance with Canadian GAAP.

Reconciliation of Net Income and Comprehensive Income

Year Ended December 31 (millions of dollars, except per share amounts)		2008			2007			2006
Income from Continuing Operations in Accordance with Canadian GAAP			1,442			1,232			1,071
U.S. GAAP adjustments:
	Unrealized loss/(gain) on natural gas inventory held in storage(1)		32			(25	)		–
	Tax impact of unrealized loss/(gain) on natural gas inventory held in storage		(11	)		8			–
	Unrealized gain/(loss) on energy contracts(2)		–			13			(6	)
	Tax impact of unrealized gain/(loss) on energy contracts		–			(5	)		3
	Tax recovery due to a change in tax legislation substantively enacted in Canada(3)		–			(12	)		–
	Other(4)(5)		–			(2	)		2
Income from Continuing Operations in Accordance with U.S. GAAP			1,463			1,209			1,070
Net Income from Discontinued Operations – U.S. and Canadian GAAP			–			–			28
Net Income in Accordance with U.S. GAAP			1,463			1,209			1,098
Other Comprehensive Income (Loss) in Accordance with Canadian GAAP			(99	)		(187	)		–
U.S. GAAP adjustments:
	Change in funded status of postretirement plan liability(6)		(49	)		(48	)		–
	Tax impact of change in funded status of postretirement plan liability		10			8			–
	Change in equity investment funded status of postretirement plan liability(6)		158			32			–
	Tax impact of change in equity investment funded status of postretirement plan liability		(51	)		(11	)		–
	Unrealized loss on derivatives(2)(4)		–			(22	)		(35	)
	Tax impact of unrealized loss on derivatives		–			8			11
	Changes in minimum pension liability(6)		–			–			98
	Tax impact of changes in minimum pension liability		–			–			(35	)
	Foreign currency translation adjustment		–			–			(1	)
Comprehensive Income in Accordance with U.S. GAAP			1,432			989			1,136

3

Condensed Balance Sheet in Accordance with U.S. GAAP

(millions of dollars)	December 31, 2008			December 31, 2007
Current assets(1)		4,921			3,172
Long-term investments(2)(5)(6)(7)		5,221			3,568
Plant, property and equipment		22,901			19,225
Goodwill		4,258			2,521
Other assets(6)(8)(9)		3,418			3,448
		40,719			31,934
Current liabilities(3)		6,080			2,980
Deferred amounts(6)(7)		1,789			2,465
Deferred income taxes(1)(2)(5)(6)(8)		2,632			2,707
Long-term debt and junior subordinated notes(9)		16,664			13,423
Non-controlling interests		805			610
		27,970			22,185
Shareholders' equity:
Preferred Shares		389			389
Common shares		8,974			7,089
Contributed surplus		284			286
Retained earnings(1)(2)(3)(4)(5)		3,771			2,623
Accumulated other comprehensive income(6)(10)		(669	)		(638	)
		12,749			9,749
		40,719			31,934

4

Statement of Accumulated Other Comprehensive Income in Accordance with U.S. GAAP⁽¹⁰⁾

(millions of dollars)	Under-funded Postretirement Plan Liability (SFAS No. 158)			Cumulative Translation Account			Minimum Pension Liability (SFAS No. 87)			Cash Flow Hedges and Other (SFAS No. 133)			Total
Balance at January 1, 2006		–			(89	)		(77	)		(58	)		(224	)
Change in minimum pension liability, net of tax expense of $35(6)		–			–			63			–			63
Reversal of minimum pension liability, due to adoption of SFAS 158, net of tax recovery of $6(6)		(14	)		–			14			–			–
Change in funding of postretirement plan liability, net of tax recovery of $35(6)		(78	)		–			–			–			(78	)
Change in equity investment postretirement plan liability, net of tax recovery of $70(6)		(154	)		–			–			–			(154	)
Unrealized gain on derivatives, net of tax expense of $11(2)		–			–			–			(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 $101		–			(350	)		–			–			(350	)
Change in gains and losses on hedges of instruments in foreign operations, net of tax expense of $41		–			79			–			–			79
Change in funded status of postretirement plan liability, net of tax recovery of $8(6)		(40	)		–			–			–			(40	)
Change in equity investment funded status of postretirement plan liability, net of tax expense of $11(6)		21			–			–			–			21
Unrealized loss on derivatives, net of tax expense of $42(2)(4)		–			–			–			70			70
Balance at December 31, 2007		(265	)		(361	)		–			(12	)		(638	)
Foreign currency translation adjustment, net of tax recovery of $104		–			571			–			–			571
Change in gains and losses on hedges of instruments in foreign operations, net of tax recovery of $303		–			(589	)		–			–			(589	)
Change in funded status of postretirement plan liability, net of tax recovery of $10(6)		(39	)		–			–			–			(39	)
Change in equity investment funded status of postretirement plan liability, net of tax expense of $51		107			–			–			–			107
Unrealized gain on derivatives, net of tax recovery of $60		–			–			–			(83	)		(83	)
Change in gains and losses on available for sale financial instruments, net of tax of nil		–			–			–			2			2
Balance at December 31, 2008		(197	)		(379	)		–			(93	)		(669	)

5

⁽¹⁾

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.

⁽²⁾

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 for physical energy contracts.

⁽³⁾

In accordance with Canadian GAAP, the Company recorded current income tax benefits resulting from substantively enacted Canadian federal income tax legislation. Under U.S. GAAP, the legislation must be fully enacted for income tax adjustments to be recorded.

⁽⁴⁾

Represents the amortization of certain hedges that became ineffective at different times under Canadian and U.S. GAAP.

⁽⁵⁾

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), an equity investment, were expensed under U.S. GAAP.

⁽⁶⁾

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, 2008 are as follows:

December 31 (millions of dollars)	2008			2007
Non-current assets		–			20
Non-current liabilities		(259	)		(251	)
		(259	)		(231	)

Pre-tax amounts recognized in Accumulated Other Comprehensive Income (AOCI) are as follows:

	2008			2007			2006
December 31 (millions of dollars)	Pension Benefits	Other Benefits	Total	Pension Benefits	Other Benefits	Total	Pension Benefits	Other Benefits		Total
Net loss	173	22	195	120	15	135	92	14		106
Prior service cost (credit)	11	4	15	12	14	26	11	(4	)	7
	184	26	210	132	29	161	103	10		113

Pre-tax amounts recorded in Other Comprehensive Income were as follows:

	2008						2007
December 31 (millions of dollars)	Pension Benefits		Other Benefits		Total		Pension Benefits		Other Benefits		Total
Amortization of net loss from AOCI to net income	(1	)	(1	)	(2	)	(9	)	(1	)	(10	)
Amortization of prior service cost (credit) from AOCI to net income	(2	)	(1	)	(3	)	(1	)	–		(1	)
Funded status adjustment	56		(2	)	54		38		21		59
	53		(4	)	49		28		20		48

The funded status based on the accumulated benefit obligation for all defined benefit pension plans as at December 31, 2008 is as follows:

December 31 (millions of dollars)	2008		2007
Accumulated benefit obligation		1,136		1,244
Fair value of plan assets		1,164		1,358
Funded Status – surplus		28		114

Included in the above accumulated benefit obligation and fair value of plan assets as at December 31, 2008 are the following amounts in respect of plans that are not fully funded:

December 31 (millions of dollars)	2008		2007
Accumulated benefit obligation	149		–
Fair value of plan assets	133		–
Funded Status – (deficit)	(16	)	–

6

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 $1 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 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, 2008 developed by the Company's third party actuary. This yield curve is used to develop spot rates that vary based on the duration of the obligations. The estimated future cash flows for the pension and other post retirement obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate.

⁽⁷⁾

Under Canadian GAAP, the Company accounts for certain investments using the proportionate consolidation basis whereby the Company's proportionate share of the assets, liabilities, revenues, expenses and cash flows are included in the Company's financial statements. U.S. GAAP does not allow the use of proportionate consolidation and requires that such investments be recorded on an equity accounting basis. Information on the balances that have been proportionately consolidated is located in Note 8 to the Company's 2008 audited consolidated annual financial statements. As a consequence of using equity accounting for U.S. GAAP, the Company is required to reflect an additional liability of $51 million at December 31, 2008 (December 31, 2007 – $21 million) for the estimated fair value of certain guarantees related to debt and other performance commitments of the joint venture operations that were not required to be recorded when the underlying liability was reflected on the balance sheet under the proportionate consolidation method of accounting. The distributed earnings from long-term investments for the year ended December 31, 2008 were $295 million (2007 – $376 million; 2006 – $494 million). The undistributed earnings from long-term investments for the year ended December 31, 2008 were $892 million (2007 – $821 million; 2006 – $836 million).

⁽⁸⁾

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.

⁽⁹⁾

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.

⁽¹⁰⁾

At December 31, 2008, Accumulated Other Comprehensive Income in accordance with U.S. GAAP is $197 million higher than under Canadian GAAP. The difference relates primarily to the accounting treatment for defined benefit pension and other postretirement plans.

Fair Value Measurements

        The Company adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 157, "Fair Value Measurements" (SFAS No. 157) for its financial assets and liabilities measured at fair value on a recurring basis effective January 1, 2008. The statement defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. In February 2008, the U.S. Financial Accounting Standards Board (FASB) issued FASB Staff Position No. 157-2, "Effective Date of FASB Statement No. 157", which delayed the effective date of SFAS No. 157 for all non-financial assets and liabilities that are measured at fair value on a non-recurring basis, until fiscal years beginning after November 15, 2008. These non-financial items include assets and liabilities such as non-financial assets and liabilities assumed in a business combination, reporting units measured at fair value in a goodwill impairment test and asset retirement obligations initially measured at fair value.

        Under SFAS No. 157, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (i.e., the 'exit price') in an orderly transaction between market participants at the measurement date.

        The Company's financial assets and liabilities that are recorded at fair value on a recurring basis have been categorized into one of three categories based upon a fair value hierarchy in accordance with SFAS No. 157. Fair values of assets and liabilities included in Level I are determined by reference to quoted prices in active markets for identical assets and liabilities. Assets and liabilities in Level II include valuations using inputs other than quoted prices for which all significant outputs are observable, either directly or indirectly. This includes comparisons with similar instruments that have observable market prices, option pricing models and other valuation techniques commonly used by market participants, which may 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. Level III valuations are based on inputs that are unobservable and significant to the overall fair value measurement. TCPL does not have any assets or liabilities that are included in Level III.

7

        Assets and liabilities measured at fair value on a recurring basis as of December 31, 2008 are categorized in accordance with SFAS No. 157 as follows:

(millions of dollars)		Quoted prices in active markets (Level I)			Significant other observable inputs (Level II)			Significant unobservable inputs (Level III)		Total
Derivative Financial Instruments Held for Trading:
	Assets		130			254			–		384
	Liabilities		(127	)		(347	)		–		(474	)
Derivative Financial Instruments in Hedging Relationships:
	Assets		42			150			–		192
	Liabilities		(100	)		(545	)		–		(645	)
Non-Derivative Financial Instruments Available for Sale:
	Assets		24			–			–		24
	Liabilities		–			–			–		–
Total			(31	)		(488	)		–		(519	)

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)	2008		2007
Deferred Tax Liabilities
Difference in accounting and tax bases of plant, equipment and power purchase arrangements		2,182		1,763
Taxes on future revenue requirement		387		433
Investments in subsidiaries and partnerships		313		443
Unrealized foreign exchange gains on long-term debt		14		110
Pension benefit		6		11
Other comprehensive income		–		8
Other		81		95
		2,983		2,863
Deferred Tax Assets
Deferred amounts		119		45
Other post-employment benefits		38		25
Other comprehensive income		62		22
Non-capital loss carry-forwards		24		–
Unrealized foreign exchange losses on long-term debt		77		–
Other		108		77
		428		169
Less: Valuation allowance		77		13
		351		156
Net deferred tax liabilities		2,632		2,707

        TCPL adopted FASB Financial Interpretation 48, Accounting for Uncertainty in Income Taxes ("FIN 48"), 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.

8

        Below is the reconciliation of the annual changes in the total unrecognized tax benefit.

December 31 (millions of dollars)	2008			2007
Unrecognized tax benefits, beginning of year		70			80
Gross increases – tax positions in prior years		13			9
Gross decreases – tax positions in prior years		(1	)		(11	)
Gross increases – current year positions		18			9
Settlements		(19	)		(6	)
Lapses of statute of limitations		(3	)		(11	)
Unrecognized tax benefits, end of year		78			70

        TCPL expects the enactment of certain Canadian Federal tax legislation in the next twelve months which is expected to 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, TCPL 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. 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 2004 and U.S. state and local income tax matters through 2002.

        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, 2008 is $10 million for interest and nil for penalties (December 31, 2007 – $1 million for interest and nil for penalties). At December 31, 2008, the Company had $24 million accrued for interest and nil accrued for penalties (December 31, 2007 – $14 million accrued for interest and nil accrued for penalties).

Other

        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's U.S. GAAP financial statements were not materially impacted by SFAS No. 159.

        In December 2007, FASB issued SFAS No. 160 "Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51" and SFAS No. 141(R) "Business Combinations" both of which are effective for annual periods beginning after December 15, 2008. SFAS No. 160 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. SFAS No.141(R) 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 will adopt these standards on January 1, 2009.

        In March 2008, FASB issued SFAS No. 161 "Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133", which is effective for fiscal years beginning after November 15, 2008. SFAS No. 161 expands the disclosure requirements for derivative instruments and hedging activities with respect to how and why entities use derivative instruments, how they are accounted for under SFAS No. 133 and the related impact on financial position, financial performance and cash flows. TCPL does not expect a material affect on its financial disclosures as a result of adopting this standard on January 1, 2009.

9

        In May 2008, FASB issued SFAS No. 162 "The Hierarchy of Generally Accepted Accounting Principles" which codifies the sources of accounting principles and the related framework to be utilized in preparing financial statements in conformity with U.S. GAAP. TCPL's U.S. GAAP financial statements are not expected to be impacted by this standard.

        In October 2008, FASB issued Staff Position No. 157-3, "Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active", which clarifies the application of SFAS No. 157 in a market that is not active. This Staff Position is effective upon issuance and the Company's U.S. GAAP financial statements were not impacted by this standard.

        In December 2008, FASB issued Staff Position No. 132(R)-1, "Employers' Disclosures about Postretirement Benefit Plan Assets", which requires more detailed disclosures regarding the employers' plan assets, concentrations of risk within plan assets and valuation techniques used to measure the fair value of plan assets. This Staff Position will be effective for fiscal years ending after December 15, 2009. The Company will adopt these standards for its 2009 year-end reporting.

10

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Internal control over financial reporting is a process designed by or under the supervision of senior management of TransCanada PipeLines Limited ("TCPL" or the "Company"), 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 generally accepted accounting principles, 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. The Company acquired Keyspan-Ravenswood, LLC ("Ravenswood") in August 2008 and began consolidating the operations of Ravenswood from that date. Management has excluded this business from its evaluation of the effectiveness of the Company's internal control over financial reporting as of December 31, 2008. The net income attributable to this business represented less than one per cent of the Company's consolidated net income for the year ended December 31, 2008, and its aggregate total assets represented approximately nine per cent of the Company's consolidated total assets as at December 31, 2008.

Based on this evaluation, management concluded that internal control over financial reporting is effective as at December 31, 2008, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes.

In 2008, 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.

KPMG LLP, the independent auditors appointed by the shareholder 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, 2008 and have issued the report entitled "Report of Independent Registered Public Accounting Firm".

February 23, 2009

/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, 2008, 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, 2008, based on 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 and in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our report dated February 23, 2009 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP
Chartered Accountants
Calgary, Canada

February 23, 2009

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 shareholders dated February 23, 2009 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.

/s/ KPMG LLP 
Chartered Accountants
Calgary, Canada

February 23, 2009

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AUDITED CONSOLIDATED 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

AUDITORS' REPORT ON RECONCILIATION TO UNITED STATES GAAP

TRANSCANADA PIPELINES LIMITED RECONCILIATION TO UNITED STATES GAAP

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

COMMENTS BY AUDITORS FOR UNITED STATES READERS ON CANADA — UNITED STATES REPORTING DIFFERENCES